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

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Form 10-Q

|(Mark one)                                        |                                                                                         
|------------------------------------------------- | ----------------------------------------------------------------------------------------
|ý                                                 | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
|For the Quarterly Period Ended September 30, 2005
|or                                               
|o                                                 | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|For the transition period from
 to               

Commission file number 000-24890

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

|Delaware                                                       |  | 95-4031807                          
|-------------------------------------------------------------- |  | ------------------------------------
|(State or other jurisdiction of incorporation
or organization) |  | (I.R.S. Employer Identification No.)
|18101 Von Karman Avenue, Suite 1700
Irvine, California         |  | 92612                               
|(Address of principal executive offices)                       |  | (Zip Code)                          

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange
Act). Yes o    No ý

Number of shares outstanding of the registrant's Common Stock as of November 4, 2005: 100 shares (all shares held by an affiliate of the registrant).



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TABLE OF CONTENTS

|                               |  |                                                                                       |  | Page
|------------------------------ |  | ------------------------------------------------------------------------------------- |  | ----
|PART I  Financial Information |  |                                                                                      
|Item 1.                        |  | Financial Statements                                                                  |  | 1   
|Item 2.                        |  | Management's Discussion and Analysis of Financial Condition and Results of Operations |  | 23  
|Item 3.                        |  | Quantitative and Qualitative Disclosures about Market Risk                            |  | 61  
|Item 4.                        |  | Controls and Procedures                                                               |  | 62  
|PART II  Other Information   
|Item 1.                        |  | Legal Proceedings                                                                     |  | 63  
|Item 6.                        |  | Exhibits                                                                              |  | 63  
|                               |  | Signatures                                                                            |  | 64  

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PART I  FINANCIAL INFORMATION  ITEM 1.    FINANCIAL STATEMENTS

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

|                                         |                                                                                    | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |    
|---------------------------------------- | ---------------------------------------------------------------------------------- | -------------------------------- | --- | ------------------------------- | ---
|
|Operating Revenues                       |                                                                                    |                                  |     |                                 |    
|                                         | Electric revenues                                                                  |                                  | $   | 640                             |    
|                                         | Net gains (losses) from price risk management and energy trading                   |                                  |     | 31                              |    
|                                         | Operation and maintenance services                                                 |                                  |     | 6                               |    
|                                         |                                                                                    |                                  |     |                                 |    
|                                         |                                                                                    | Total operating revenues         |     |                                 | 677
|                                         |                                                                                    |                                  |     |                                 |    
|Operating Expenses                       |                                                                                    |                                  |     |                                 |    
|                                         | Fuel                                                                               |                                  |     | 193                             |    
|                                         | Plant operations                                                                   |                                  |     | 96                              |    
|                                         | Plant operating leases                                                             |                                  |     | 45                              |    
|                                         | Operation and maintenance services                                                 |                                  |     | 5                               |    
|                                         | Depreciation and amortization                                                      |                                  |     | 31                              |    
|                                         | Loss on lease termination, asset impairment and other charges                      |                                  |     |                                |    
|                                         | Administrative and general                                                         |                                  |     | 29                              |    
|                                         |                                                                                    |                                  |     |                                 |    
|                                         |                                                                                    | Total operating expenses         |     |                                 | 399
|                                         |                                                                                    |                                  |     |                                 |    
|                                         | Operating income (loss)                                                            |                                  |     | 278                             |    
|                                         |                                                                                    |                                  |     |                                 |    
|Other Income (Expense)                   |                                                                                    |                                  |     |                                 |    
|                                         | Equity in income from unconsolidated affiliates                                    |                                  |     | 113                             |    
|                                         | Impairment loss on equity method investment                                        |                                  |     | (55                             | )  
|                                         | Interest and other income                                                          |                                  |     | 15                              |    
|                                         | Gain on sale of assets                                                             |                                  |     |                                |    
|                                         | Loss on early extinguishment of debt                                               |                                  |     |                                |    
|                                         | Interest expense                                                                   |                                  |     | (73                             | )  
|                                         |                                                                                    |                                  |     |                                 |    
|                                         |                                                                                    | Total other income (expense)     |     |                                 |   
|                                         |                                                                                    |                                  |     |                                 |    
|                                         | Income (loss) from continuing operations before income taxes and minority interest |                                  |     | 278                             |    
|                                         | Provision (benefit) for income taxes                                               |                                  |     | 106                             |    
|                                         | Minority interest                                                                  |                                  |     |                                |    
|                                         |                                                                                    |                                  |     |                                 |    
|Income (Loss) From Continuing Operations |                                                                                    |                                  | 172 |                                 |    
|                                         | Income from operations of discontinued subsidiaries, net of tax (Note 6)           |                                  |     | 27                              |    
|                                         |                                                                                    |                                  |     |                                 |    
|Net Income                               |                                                                                    | $                                | 199 |                                 | $  
|                                         |                                                                                    |                                  |     |                                 |    

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 millions, Unaudited)

|                                               |                                                                         | Three Months Ended
September 30,                                                                                                                                                                                                  |      | Nine Months Ended
September 30, |     
|---------------------------------------------- | ----------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | ---- | ------------------------------- | ----
|
|Net Income                                     |                                                                         | $                                                                                                                                                                                                                                 | 199  |                                 | $   
|Other comprehensive income (loss), net of tax: |                                                                         |                                                                                                                                                                                                                                   |      |                                 |     
|                                               | Foreign currency translation adjustments:                               |                                                                                                                                                                                                                                   |      |                                 |     
|                                               |                                                                         | Foreign currency translation adjustments, net of income tax expense of $0 for the three months and $1 for the nine months ended September 30, 2004, respectively                                                                  |      |                                 |    
|                                               |                                                                         | Reclassification adjustment for sale of investment in a foreign subsidiary                                                                                                                                                        |      |                                 |    
|                                               | Unrealized gains (losses) on derivatives qualified as cash flow hedges: |                                                                                                                                                                                                                                   |      |                                 |     
|                                               |                                                                         | Other unrealized holding gains (losses) arising during period, net of income tax expense (benefit) of $(122) and $5 for the three months and $(165) and $(46) for the nine months ended September 30, 2005 and
2004, respectively |      |                                 | (167
|                                               |                                                                         | Reclassification adjustments included in net income (loss), net of income tax expense (benefit) of $51 and $(19) for the three months and $56 and $(51) for the nine months ended September 30, 2005 and 2004,
respectively       |      |                                 | (72 
|                                               |                                                                         |                                                                                                                                                                                                                                   |      |                                 |     
|Other comprehensive loss                       |                                                                         |                                                                                                                                                                                                                                   | (239 | )                               |     
|                                               |                                                                         |                                                                                                                                                                                                                                   |      |                                 |     
|Comprehensive Income (Loss)                    |                                                                         | $                                                                                                                                                                                                                                 | (40  | )                               | $   
|                                               |                                                                         |                                                                                                                                                                                                                                   |      |                                 |     

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 millions, Unaudited)

|                                         |                                                                                | September 30,
2005                |       | December 31,
2004
|---------------------------------------- | ------------------------------------------------------------------------------ | --------------------------------- | ----- | -----------------
|Assets                                   |                                                                                |                                   |       |                  
|Current Assets                           |                                                                                |                                   |       |                  
|                                         | Cash and cash equivalents                                                      |                                   | $     | 1,556            
|                                         | Short-term investments                                                         |                                   |       |                 
|                                         | Accounts receivabletrade                                                      |                                   |       | 273              
|                                         | Accounts receivableaffiliates                                                 |                                   |       | 7                
|                                         | Inventory                                                                      |                                   |       | 118              
|                                         | Assets under price risk management and energy trading                          |                                   |       | 116              
|                                         | Margin and collateral deposits                                                 |                                   |       | 726              
|                                         | Prepaid expenses and other                                                     |                                   |       | 26               
|                                         |                                                                                |                                   |       |                  
|                                         |                                                                                | Total current assets              |       |                  
|                                         |                                                                                |                                   |       |                  
|Investments in Unconsolidated Affiliates |                                                                                |                                   | 430   |                  
|                                         |                                                                                |                                   |       |                  
|Property, Plant and Equipment            |                                                                                |                                   | 3,527 |                  
|                                         | Less accumulated depreciation and amortization                                 |                                   |       | 800              
|                                         |                                                                                |                                   |       |                  
|                                         |                                                                                | Net property, plant and equipment |       |                  
|                                         |                                                                                |                                   |       |                  
|Other Assets                             |                                                                                |                                   |       |                  
|                                         | Deferred financing costs                                                       |                                   |       | 42               
|                                         | Long-term assets under price risk management and energy trading                |                                   |       | 94               
|                                         | Restricted cash                                                                |                                   |       | 70               
|                                         | Rent payments in excess of levelized rent expense under plant operating leases |                                   |       | 392              
|                                         | Other long-term assets                                                         |                                   |       | 56               
|                                         |                                                                                |                                   |       |                  
|                                         |                                                                                | Total other assets                |       |                  
|                                         |                                                                                |                                   |       |                  
|Assets of Discontinued Operations        |                                                                                |                                   | 1     |                  
|                                         |                                                                                |                                   |       |                  
|Total Assets                             |                                                                                | $                                 | 6,634 |                  
|                                         |                                                                                |                                   |       |                  

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 millions, Unaudited)

|                                                                     |                                                                                                      | September 30,
2005        |       | December 31,
2004 |      
|-------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------- | ------------------------- | ----- | ----------------- | -----
|Liabilities and Shareholder's Equity                                 |                                                                                                      |                           |       |                   |      
|Current Liabilities                                                  |                                                                                                      |                           |       |                   |      
|                                                                     | Accounts payableaffiliates                                                                          |                           | $     | 107               |      
|                                                                     | Accounts payable and accrued liabilities                                                             |                           |       | 293               |      
|                                                                     | Dividends payable                                                                                    |                           |       |                  |      
|                                                                     | Liabilities under price risk management and energy trading                                           |                           |       | 597               |      
|                                                                     | Interest payable                                                                                     |                           |       | 89                |      
|                                                                     | Current maturities of long-term obligations                                                          |                           |       | 46                |      
|                                                                     |                                                                                                      |                           |       |                   |      
|                                                                     |                                                                                                      | Total current liabilities |       |                   | 1,132
|                                                                     |                                                                                                      |                           |       |                   |      
|Long-term obligations net of current maturities                      |                                                                                                      |                           | 3,309 |                   |      
|Deferred taxes and tax credits                                       |                                                                                                      |                           | 12    |                   |      
|Long-term liabilities under price risk management and energy trading |                                                                                                      |                           | 88    |                   |      
|Other long-term liabilities                                          |                                                                                                      |                           | 463   |                   |      
|Liabilities of discontinued operations                               |                                                                                                      |                           | 4     |                   |      
|                                                                     |                                                                                                      |                           |       |                   |      
|Total Liabilities                                                    |                                                                                                      |                           | 5,008 |                   |      
|                                                                     |                                                                                                      |                           |       |                   |      
|Commitments and Contingencies(Note 11)                               |                                                                                                      |                           |       |                   |      
|Shareholder's Equity                                                 |                                                                                                      |                           |       |                   |      
|                                                                     | Common stock, par value $0.01 per share; 10,000 shares authorized; 100 shares issued and outstanding |                           |       | 64                |      
|                                                                     | Additional paid-in capital                                                                           |                           |       | 2,197             |      
|                                                                     | Retained deficit                                                                                     |                           |       | (351              | )    
|                                                                     | Accumulated other comprehensive income (loss)                                                        |                           |       | (284              | )    
|                                                                     |                                                                                                      |                           |       |                   |      
|Total Shareholder's Equity                                           |                                                                                                      |                           | 1,626 |                   |      
|                                                                     |                                                                                                      |                           |       |                   |      
|Total Liabilities and Shareholder's Equity                           |                                                                                                      | $                         | 6,634 |                   | $    
|                                                                     |                                                                                                      |                           |       |                   |      

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

4

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EDISON MISSION ENERGY AND SUBSIDIARIES  CONSOLIDATED STATEMENTS OF CASH FLOWS  (In millions, Unaudited)

|                                                                        |                                                                                  | Nine Months Ended
September 30,                               |      
|----------------------------------------------------------------------- | -------------------------------------------------------------------------------- | ------------------------------------------------------------- | -----
|
|Cash Flows From Operating Activities                                    |                                                                                  |                                                               |      
|                                                                        | Income (loss) from continuing operations, net                                    |                                                               | $    
|                                                                        | Adjustments to reconcile income (loss) to net cash used in operating activities: |                                                               |      
|                                                                        |                                                                                  | Equity in income from unconsolidated affiliates               |      
|                                                                        |                                                                                  | Distributions from unconsolidated affiliates                  |      
|                                                                        |                                                                                  | Depreciation and amortization                                 |      
|                                                                        |                                                                                  | Minority interest                                             |      
|                                                                        |                                                                                  | Deferred taxes and tax credits                                |      
|                                                                        |                                                                                  | Gain on sale of assets                                        |      
|                                                                        |                                                                                  | Loss on early extinguishment of debt                          |      
|                                                                        |                                                                                  | Impairment charges                                            |      
|                                                                        | Changes in operating assets and liabilities:                                     |                                                               |      
|                                                                        |                                                                                  | Increase in margin and collateral deposits                    |      
|                                                                        |                                                                                  | Increase in accounts receivable                               |      
|                                                                        |                                                                                  | Decrease (increase) in inventory                              |      
|                                                                        |                                                                                  | Decrease in prepaid expenses and other                        |      
|                                                                        |                                                                                  | Increase in rent payments in excess of levelized rent expense |      
|                                                                        |                                                                                  | Increase in accounts payable and accrued liabilities          |      
|                                                                        |                                                                                  | Increase in interest payable                                  |      
|                                                                        |                                                                                  | Decrease in net assets under risk management                  |      
|                                                                        |                                                                                  | Other operatingassets                                        |      
|                                                                        |                                                                                  | Other operatingliabilities                                   |      
|                                                                        |                                                                                  |                                                               |      
|                                                                        |                                                                                  | Net cash used in operating activities                         |      
|                                                                        |                                                                                  |                                                               |      
|Cash Flows From Financing Activities                                    |                                                                                  |                                                               |      
|                                                                        | Borrowings on long-term debt and lease swap agreements                           |                                                               |      
|                                                                        | Payments on long-term debt agreements                                            |                                                               |      
|                                                                        | Cash dividends to parent                                                         |                                                               |      
|                                                                        | Payments for price appreciation on stock options exercised                       |                                                               |      
|                                                                        | Financing costs                                                                  |                                                               |      
|                                                                        |                                                                                  |                                                               |      
|                                                                        |                                                                                  | Net cash provided by (used in) financing activities           |      
|                                                                        |                                                                                  |                                                               |      
|Cash Flows From Investing Activities                                    |                                                                                  |                                                               |      
|                                                                        | Capital expenditures                                                             |                                                               |      
|                                                                        | Proceeds from sale of interest in projects                                       |                                                               |      
|                                                                        | Proceeds from sale of discontinued operations                                    |                                                               |      
|                                                                        | Sale of short-term investments, net                                              |                                                               |      
|                                                                        | Decrease in restricted cash                                                      |                                                               |      
|                                                                        | Investments in other assets                                                      |                                                               |      
|                                                                        |                                                                                  |                                                               |      
|                                                                        |                                                                                  | Net cash provided by investing activities                     |      
|                                                                        |                                                                                  |                                                               |      
|Effect on cash from discontinued operations activities                  |                                                                                  |                                                               | 50   
|                                                                        |                                                                                  |                                                               |      
|Effect on cash from deconsolidation of subsidiary                       |                                                                                  |                                                               |     
|                                                                        |                                                                                  |                                                               |      
|Net increase (decrease) in cash and cash equivalents                    |                                                                                  |                                                               | (715 
|Cash and cash equivalents at beginning of period                        |                                                                                  |                                                               | 2,272
|                                                                        |                                                                                  |                                                               |      
|Cash and cash equivalents at end of period                              |                                                                                  |                                                               | 1,557
|Cash and cash equivalents classified as part of discontinued operations |                                                                                  |                                                               | (1   
|                                                                        |                                                                                  |                                                               |      
|Cash and cash equivalents of continuing operations                      |                                                                                  | $                                                             | 1,556
|                                                                        |                                                                                  |                                                               |      

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

5

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EDISON MISSION ENERGY AND SUBSIDIARIES  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS  SEPTEMBER 30, 2005  (Unaudited)

Note 1. General

In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to present fairly the consolidated financial
position and results of operations for the periods covered by this report. The results of operations for the nine months ended September 30, 2005 are not necessarily indicative of the operating
results for the full year.

Edison
Mission Energy (EME's) significant accounting policies are described in Note 2 to its Consolidated Financial Statements as of December 31, 2004 and 2003, included in
EME's annual report on Form 10-K for the year ended December 31, 2004. EME follows the same accounting policies for interim reporting purposes. This quarterly report should
be read in connection with such financial statements. Terms used but not defined in this report are defined in EME's annual report on Form 10-K for the year ended
December 31, 2004.

Margin and Collateral Deposits

Margin and collateral deposits include cash deposited with counterparties and brokers as credit support under energy contracts. The amount of margin and
collateral deposits generally varies based on changes in fair value of the related positions. Deposits with counterparties and brokers generally earn interest that approximates the Federal Funds Rate.

Reclassifications

Certain prior year reclassifications have been made to conform to the current year financial statement presentation. Except as indicated, amounts reflected in the
notes to the consolidated financial statements relate to continuing operations of EME.

Note 2. Inventory

Inventory is stated at the lower of weighted average cost or market. Inventory at September 30, 2005 and December 31, 2004 consisted of the
following:

September 30,
2005

December 31,
2004(in millions)Coal and fuel oil

$
75

$
65Spare parts, materials and supplies


43


42Total

$
118

$
107


Note 3. Agreement to Sell the Doga Project

EME owns an 80% interest in a 180 MW gas-fired cogeneration plant near Istanbul, Turkey, which EME refers to as the Doga project. EME has entered into
a Purchase Agreement, dated as of August 17, 2005, to sell its interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim Isletme ve Ticaret Limited
Sirketi, which will acquire an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which will acquire a 50% interest in the Doga

6

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project.
Completion of the sale is subject to the satisfaction of a number of closing conditions, including obtaining the consent of a majority of the project's lenders. The sale is expected to close
in the fourth quarter of 2005.

Note 4. Loss on Lease Termination, Impairment Losses and Other Charges

Impairment Loss on Equity Method Investment

During the third quarter of 2005, EME fully impaired its equity investment in the March Point project following an updated forecast of future project cash flows.
The March Point project is a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, in which a subsidiary of EME owns a 50% partnership interest. The March Point
project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell Oil) under a
steam supply agreement that also expires in 2011. March Point purchases a portion of its fuel requirements under long-term contracts with the remaining requirements purchased at current
market prices. March Point's power sales agreements do not provide for a price adjustment related to the project's fuel costs. During the third quarter of 2005, long-term natural gas
prices increased substantially, thereby adversely affecting the future cash flows of the March Point project. As a result, management concluded that its investment was impaired and recorded a
$55 million charge during the third quarter of 2005.

Loss on Lease Termination, Asset Impairment and Other Charges

On April 27, 2004, EME's subsidiary, Midwest Generation, LLC (Midwest Generation) terminated the Collins Station lease through a negotiated transaction
with the lease equity investor. Midwest Generation made a lease termination payment of approximately $960 million. This amount represented the $774 million of lease debt outstanding,
plus accrued interest, and the amount owed to the lease equity investor for early termination of the lease. Midwest Generation received title to the Collins Station as part of the transaction. EME
recorded a pre-tax loss of approximately $956 million (approximately $587 million after tax) due to termination of the lease and the planned decommissioning of the asset and
disposition of excess inventory.

Following
the termination of the Collins Station lease, Midwest Generation announced plans on May 28, 2004 to permanently cease operations at the Collins Station by
December 31, 2004 and decommission the plant. In September 2004, EME recorded a pre-tax impairment charge of $5 million resulting from the termination of the power
purchase agreement effective September 30, 2004 for the two units at the Collins Station that remained under contract.

In
September 2004, management completed an analysis of future competitiveness in the expanded PJM Interconnection, LLC (PJM) marketplace of its eight remaining small peaking units
in Illinois. Based on this analysis, management decided to decommission six of the eight small peaking units. As a result of the decision to decommission the units, projected future cash flows
associated with the Illinois peaking units were less than the book value of the units, resulting in an impairment under Statement of Financial Accounting Standards No. 144, "Accounting for the
Impairment or the Disposal of Long-Lived Assets." During the third quarter of 2004, EME recorded a pre-tax impairment charge of $29 million (approximately
$18 million after tax).

7

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Note 5. Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss), including discontinued operations, consisted of the following:

Unrealized Gains
(Losses) on Cash
Flow Hedges

Minimum
Pension Liability
Adjustment

Accumulated Other
Comprehensive
Income (Loss)(in millions)Balance at December 31, 2004

$
18

$
(1
)
$
17Current period change


(301
)




(301
)Balance at September 30, 2005

$
(283
)
$
(1
)
$
(284
)


Unrealized losses on cash flow hedges, net of tax, at September 30, 2005, include unrealized losses on commodity hedges primarily related
to Midwest Generation and EME Homer City Generation L.P. (EME Homer City) futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of
future electricity prices in these markets are greater than contract prices. The increase in the unrealized losses during the third quarter of 2005 resulted from a combination of new hedges for 2006
and 2007 and an increase in market prices for power driven largely from higher natural gas and oil prices. In addition, at September 30, 2005, EME reclassified a $9 million, after tax,
unrealized gain from other comprehensive loss to earnings due to the impairment of its equity investment in the March Point project.

As
EME's hedged positions for continuing operations are realized, approximately $257 million, after tax, of the net unrealized losses on cash flow hedges at September 30,
2005 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will offset energy revenue recognized at market
prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions. The maximum
period over which a cash flow hedge is designated is through December 31, 2007.

Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. EME recorded net losses of approximately $32 million and $13 million during the third quarters of 2005 and 2004 and $35 million and
$9 million during the nine months ended September 30, 2005 and 2004, respectively, representing the amount of cash flow hedges' ineffectiveness for continuing operations, reflected in
net gains from price risk management and energy trading in EME's consolidated income statements.

Note 6. Discontinued Operations

Tri Energy Project

On February 3, 2005, EME sold its 25% equity interest in the Tri Energy project pursuant to a Purchase Agreement, dated December 15, 2004, by and
between EME and a consortium comprised of International Power plc (70%) and Mitsui & Co., Ltd. (30%), referred to as IPM, for approximately $20 million. EME recorded an impairment
charge of approximately $5 million during the fourth quarter of 2004 related to the planned disposition of this investment. The sale of this investment had no significant effect on net income
in the first quarter of 2005.

8

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CBK Project

On January 10, 2005, EME sold its 50% equity interest in the CBK project pursuant to a Purchase Agreement, dated November 5, 2004, by and between
EME and Corporacion IMPSA S.A. Proceeds from the sale were approximately $104 million. EME recorded a pre-tax gain on the sale of approximately $9 million during the first
quarter of 2005.

MEC International B.V.

On December 16, 2004, EME sold the stock and related assets of MEC International B.V. (MECIBV) pursuant to a Purchase Agreement, dated July 29,
2004, by and between EME and IPM. The purchase agreement was entered into following a competitive bidding process. The sale of MECIBV included the sale of EME's interests in ten electric power
generating projects or companies located in Europe, Asia, Australia, and Puerto Rico. Consideration from the sale of MECIBV and related assets was $2.0 billion.

Contact Energy

On September 30, 2004, EME sold its 51.2% interest in Contact Energy to Origin Energy New Zealand Limited pursuant to a Purchase Agreement, dated
July 20, 2004. The purchase agreement was entered into following a competitive bidding process. Consideration for the sale was NZ$1,101.4 million (approximately US$739 million) in
cash and NZ$535 million (approximately US$359 million) of debt assumed by the purchaser. EME recorded an after-tax gain on sale of Contact Energy of $141 million
during the third quarter of 2004.

Lakeland Project

EME previously owned and operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the Lakeland project.
The ownership of the project was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant pursuant to a power sales agreement with Norweb
Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe). EME ceased consolidating the activities of Lakeland
Power Ltd. in 2002, when an administrative receiver was appointed following a default by Norweb Energi Ltd. under the power sales agreement. Accordingly, EME accounts for its ownership
of Lakeland Power Ltd. on the cost method and earnings are recognized as cash is distributed from this entity.

As
previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination of the power sales agreement. On
November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings of their own in the
United Kingdom (similar to bankruptcy proceedings in the United States). On March 31, 2005, Lakeland Power Ltd. received £112 million (approximately
$210 million) from the TXU administrators, representing an interim payment of 97% of its accepted claim of £116 million (approximately $217 million).

From
the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of £20 million (approximately
$37 million) to EME on April 7, 2005 comprised of £7 million (approximately $13 million) for a secured loan which EME purchased from Lakeland
Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd., and £13 million (approximately $24 million) as a distribution
to the EME subsidiary that owns the equity interest in Lakeland Power Ltd. The distribution was recognized in income during the

9

---



quarter
ended June 30, 2005. Additionally, Lakeland Power Ltd. will pay to EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after
resolution of any remaining secured and unsecured creditor claims and payment of or provision for tax liabilities and the fees and expenses associated with Lakeland Power Ltd.'s liquidation.

EME
estimates that the remaining net proceeds after tax (including taxes due in the United States) and net income resulting from the above payments will be approximately
$64 million. The majority of the remaining proceeds are expected to be received in 2006, when Lakeland Power Ltd.'s liquidation is expected to be completed. Because the amounts required
to settle outstanding claims and UK taxes have not been finalized and cannot be estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net income may
vary materially from the above estimate.

Summarized Financial Information for Discontinued Operations

In accordance with SFAS No. 144, all of the projects discussed above are classified as discontinued operations in the accompanying consolidated statements
of income. Previously issued statements of operations have been restated to reflect discontinued operations reported subsequent to the original issuance date. Summarized results of discontinued
operations are as follows:

Three Months Ended
September 30,

Nine Months Ended
September 30,2005

2004

2005

2004(in millions)Total operating revenues

$


$
354

$


$
1,102Income (loss) before income taxes and minority interest


(2
)

59


20


214Benefit for income taxes


(29
)

(316
)

(30
)

(264
)Minority interest





18





49Income from operations of discontinued foreign subsidiaries


27


357


50


429Gain on sale before income taxes





312


9


312Gain on sale after income taxes





141


5


141


During the quarter ended September 30, 2005, EME recorded tax adjustments of $28 million which resulted from completion of the 2004
federal and California income tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004 and are
included in "Benefit for income taxes" in the above table. During the quarter ended September 30, 2004, EME recorded a deferred income tax benefit of $327 million in accordance with
Emerging Issues Task Force Issue No. 93-17, "Recognition of Deferred Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a
Discontinued Operation," (EITF 93-17). Under EITF 93-17, because the tax basis of the stock of EME's Dutch subsidiary, MECIBV, exceeded EME's book basis, an adjustment to
deferred taxes was required during the third quarter of 2004.

The
assets and liabilities associated with the discontinued operations are segregated on the consolidated balance sheets at September 30, 2005 and December 31, 2004. The
carrying amount of

10

---



major
asset and liability classifications for EME's international operations recorded as discontinued operations are as follows:

September 30,
2005

December 31,
2004(in millions)Cash and cash equivalents

$
1

$
2Other current assets





2Total current assets


1


4Investments in unconsolidated affiliates





107Assets of discontinued operations

$
1

$
111Accounts payable and accrued liabilities

$


$
1Total current liabilities





1Deferred revenue


4


4Total long-term deferred liabilities


4


4Liabilities of discontinued operations

$
4

$
5


Note 7. Restructuring Costs

During the first quarter of 2005, EME initiated a review of its domestic organization to better align its resources with its domestic business requirements.
Management and organizational changes have been implemented to streamline EME's reporting relationships and eliminate its regional management structure. As a result of these changes, EME recorded
charges of approximately $10 million (pre-tax) in the nine months ended September 30, 2005 for severance and related costs. These charges were included in
administrative and general expense on EME's consolidated statement of income.

Note 8. Employee Benefit Plans

Pension Plans

EME previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $12 million to its pension
plans in 2005. As of September 30, 2005, $9 million in contributions have been made. EME anticipates meeting its original expectation by year-end 2005.

Components
of pension expense are:

Three Months Ended
September 30,

Nine Months Ended
September 30,2005

2004

2005

2004(in millions)Service cost

$
5

$
4

$
14

$
12Interest cost


2


2


6


6Expected return on plan assets


(1
)

(1
)

(4
)

(3
)Net amortization and deferral








1


Total expense

$
6

$
5

$
17

$
15


11

---



Postretirement Benefits Other Than Pensions

EME previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $1 million to its
postretirement benefits other than pensions in 2005. As of
September 30, 2005, $0.5 million in contributions have been made. EME anticipates meeting its original expectation by year-end 2005.

Components
of postretirement benefits other than pensions expense are:

Three Months Ended
September 30,

Nine Months Ended
September 30,2005

2004

2005

2004(in millions)Service cost

$
1

$


$
2

$
Interest cost


1


1


3


3Amortization of unrecognized prior service costs








(1
)

Total expense

$
2

$
1

$
4

$
3


Note 9. Refinancing

EME Financing Developments

On January 25, 2005, EME repaid the junior subordinated debentures and consequently repaid the cumulative monthly income preferred securities (MIPS) of
$150 million. The junior subordinated debentures are described more fully in Note 10Financial Instruments, included in EME's annual report on Form 10-K
for the year ended December 31, 2004. In connection with the repayment of the junior subordinated debentures, EME recorded a $4 million loss on early extinguishment of debt during the
first quarter of 2005.

Midwest Generation Financing Developments

On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of
Midwest Generation's existing credit facility, originally entered into April 27, 2004. The existing credit facility had provided for a $700 million first priority secured institutional
term loan due in 2011 and a $200 million first priority secured revolving credit, working capital facility due in 2009.

The
refinancing consisted of, among other things, a repricing of Midwest Generation's existing term loan and a new $300 million revolving credit, working capital facility due in
2011. The previously existing $200 million working capital facility remains in place. Midwest Generation drew in full upon the new $300 million working capital facility at closing and
used the proceeds to pay down an equivalent portion of the existing term loan. After giving effect to the paydown, the term loan carries a lower interest rate of LIBOR + 2%. The maturity
date of the repriced term loan remains 2011. The new working capital facility, together with the existing working capital facility, shares first lien priority with the repriced term loan. The new
working capital facility carries an interest rate of LIBOR + 2.25%. The maturity date of the new working capital facility is 2011; however, the lenders can request to be fully repaid in
2010.

On
the day after the closing of the refinancing transaction, EME contributed $300 million in equity to Midwest Generation, and Midwest Generation used the proceeds of this equity
contribution

12

---



to
repay the loans outstanding under the new working capital facility. Thus, after completion of the actions outlined herein, Midwest Generation had $343 million outstanding under its term loan
and $500 million of working capital facilities available for working capital requirements, including credit support for hedging activities. As of September 30, 2005, approximately
$170 million was utilized under these working capital facilities.

Under
the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of excess cash flow (as defined in the credit agreement). In addition, if
equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributes to
the equity contribution equals the amount thereof. Accordingly, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to
the equity contribution made by EME in Midwest Generation on April 19, 2005 equals $300 million. However, Midwest Generation is required to make concurrently with each distribution an
offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the portion thereof attributed to the equity contribution. Thus, Midwest Generation
will not be required to offer to repay debt concurrently with a distribution so long as the portion of each distribution attributed to the April 19, 2005 equity contribution is at least
one-third of such distribution.

Note 10. Income Taxes

EME's income tax provision (benefit) from continuing operations was $129 million and $(342) million during the nine months ended
September 30, 2005 and 2004, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. During the second quarter of 2005,
EME resolved a dispute regarding additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME
reversed $11.5 million of accrued taxes which was recorded as a reduction of income taxes during the second quarter of 2005. During the second quarter of 2004, EME recorded a tax benefit of
$368 million primarily relating to the loss on the termination of the Collins Station lease, and during the first quarter of 2004, EME recorded a tax provision of $18 million relating to
the sale of 100% of its stock in Edison Mission Energy Oil & Gas, which in turn held interests in Four Star Oil & Gas.

Note 11. Commitments and Contingencies

Contractual Obligations

Long-Term Debt

EME's long-term debt maturities as of September 30, 2005 are (in millions):

October through December 2005

$
22006


472007


1292008


4162009


610


These amounts have been updated primarily to reflect financing activities completed during the first nine months of 2005. See
Note 9Refinancing.

13

---



Fuel Supply Contracts

Midwest Generation and EME Homer City have entered into additional fuel purchase commitments with various third-party suppliers during the first
nine months of 2005. These additional commitments are currently estimated to be $22 million for 2005, $114 million for 2006, $169 million for 2007, $44 million for
2008, and $62 million for 2009.

Coal Transportation Agreements

Midwest Generation has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various
delivering carriers) which extend through 2011. Midwest Generation commitments under this agreement are based on actual coal purchases from the Powder River Basin. Accordingly, contractual obligations
for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first nine months of 2005 relates to
additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $33 million for 2005, $61 million for 2006,
$117 million for 2007, $40 million for 2008, and $77 million for 2009.

Capital Improvements

At September 30, 2005, EME's subsidiaries had firm commitments to spend on capital expenditures of approximately $4 million during the remainder of
2005 and approximately $5 million in 2006.

Commercial Commitments

Introduction

EME and certain of its subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As
discussed below, these contracts include performance guarantees, standby letters of credit, guarantee of debt and indemnifications.

Standby Letters of Credit

At September 30, 2005, standby letters of credit aggregated $17 million and were scheduled to expire as follows: remainder of
2005$3 million; 2006$11 million; and 2007$3 million.

Guarantees and Indemnities

Tax Indemnity Agreements

In
connection with the sale-leaseback transactions that EME has entered into related to the Powerton and Joliet Stations in Illinois, the Collins Station in Illinois, and the
Homer City facilities in Pennsylvania, EME and several of its subsidiaries entered into tax indemnity agreements. Under these tax indemnity agreements, these entities agreed to indemnify the lessors
in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults
under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a
maximum potential liability which would be triggered by a valid claim from the lessors. EME has not recorded a liability related to these indemnities. In connection with the termination of the Collins
Station lease in April 2004, Midwest

14

---



Generation
will continue to have obligations under the tax indemnity agreement with the former lease equity investor.

Indemnities Provided as Part of the Acquisition of the Illinois Plants

In
connection with the acquisition of the Illinois Plants, EME agreed to indemnify Commonwealth Edison with respect to specified environmental liabilities before and after
December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth
Edison take all reasonable steps to mitigate losses related to any such indemnification claim. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be
determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Except as discussed below, EME has not recorded
a liability related to this indemnity.

Midwest
Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company on February 20, 2003 to resolve a dispute regarding interpretation
of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse
Commonwealth Edison and Exelon Generation for 50% of specific existing asbestos claims and expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses
associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future asbestos-related
claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The
supplemental agreement has a five-year term with an automatic renewal provision (subject to the right of either party to terminate). Payments are made under this indemnity upon tender by
Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were between 170 and 190 cases for which Midwest Generation was
potentially liable and that had not been settled and dismissed at September 30, 2005. Midwest Generation had recorded a $68 million liability at September 30, 2005 related to this
matter.

The
amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Projecting future events, such as the number of new claims to be
filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower
than projected.

Indemnity Provided as Part of the Acquisition of the Homer City Facilities

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

Indemnities Provided under Asset Sale Agreements

The
asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to
operations of the

15

---



assets
prior to the sale and for pre-closing environmental liabilities. EME also provided an indemnity to IPM for matters arising out of the exercise by one of its project partners of a
purported right of first refusal. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the
sellers or purchasers, as the case may be. At September 30, 2005, EME had recorded a liability of $86 million related to these matters.

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

Guarantee of Brooklyn Navy Yard Contractor Settlement Payments

On
March 31, 2004, EME completed the sale of 100% of the stock of Mission Energy New York, Inc., which holds a 50% partnership interest in Brooklyn Navy Yard Cogeneration
Partners, L.P. (referred to as Brooklyn Navy Yard), to BNY Power Partners LLC. Brooklyn Navy Yard owns a 286 MW gas-fired cogeneration power plant in Brooklyn, New York. In
February 1997, the construction contractor asserted general monetary claims under the turnkey agreement against Brooklyn Navy Yard. A settlement agreement was executed on January 17,
2003, and all litigation has been dismissed. EME agreed to indemnify Brooklyn Navy Yard and, in connection with the sale of EME's interest in Brooklyn Navy Yard, BNY Power Partners for any payments
due under this settlement agreement, which are scheduled through January 2007. At September 30, 2005, EME had recorded a liability of $7 million related to this indemnity.

Capacity Indemnification Agreements

EME
has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity
payments to the project's power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal
operations within a reasonable time after a complete or partial shutdown, during the term of the power contracts. In addition, a subsidiary of EME has guaranteed the obligations of Sycamore
Cogeneration Company under its project power sales agreement to repay capacity payments to the project's power purchaser in the event that the project unilaterally terminates its performance or
reduces its electric power producing capability during the term of the power contract. The obligations under the indemnification agreements as of September 30, 2005, if payment were required,
would be $134 million. EME has not recorded a liability related to these indemnities.

Subsidiary Guarantee for Performance of Unconsolidated Affiliate

A
subsidiary of EME has guaranteed the obligations of an unconsolidated affiliate to make payments to a third party for power delivered under a fixed-price power sales agreement. This
agreement runs through 2007. EME believes there is sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. Due to the nature of this indemnity, a maximum
potential liability cannot be determined. To the extent EME's subsidiary would be required to make payments under the guarantee, EME's subsidiary and EME are indemnified by Peabody Energy

16

---



Corporation
pursuant to the 2000 Purchase and Sale Agreement for Citizens Power LLC. EME's subsidiary has not recorded a liability related to this indemnity.

Contingencies

Legal Developments Affecting Sunrise Power Company

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and
on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise Power Company.
The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain
unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies
obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits.
In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also
alleges a class action. One of the newly added parties removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court. Defendants filed a responding pleading on
May 6, 2005. Following a hearing on September 7, 2005, the court sustained defendants' demurrer regarding preemption and filed rate doctrine. The plaintiff has waived his right to
appeal.

Regulatory Developments Affecting Doga Project

On August 4, 2002, a new Electricity Market License Regulation was implemented in Turkey. The new regulation contains, among other things, a requirement
that each generator obtain a generation license. The effect of the regulation is still undetermined, as the new license provisions have not been specified. Doga complied with the new regulation's
stipulation to apply for a new generation license by June 2, 2003. The license has not been issued yet.

If
actions or inactions undertaken pursuant to the new regulation directly or indirectly impede, hinder, prevent or delay the operation of the Doga facility or increase Doga's cost of
performing its obligations under its project documents, this may constitute a "risk event" under Doga's Implementation Contract. A risk event may permit Doga to request an increase in its tariff or,
under certain circumstances, request a buyout of the project by the Ministry of Energy and Natural Resources.

On
October 3, 2002, Doga (and several other power producers in Turkey acting independently) filed a lawsuit in the Danistay, Turkey's high administrative court, against the Energy
Market Regulatory Authority seeking both an injunction and permanent invalidation of certain provisions of the new regulation on the grounds of the illegality and unconstitutionality of any new
license requirement that does not take into account the vested rights of a company operating pursuant to previously agreed terms of the Implementation Contract. Doga's request for injunctive relief
was rejected, and there are no further rights of appeal against that rejection.

On
June 21, 2005, a hearing regarding the merits of the case was held. Following the hearing, the Danistay rendered a decision upholding the contested provisions of the new
regulation. Doga has filed

17

---



an
appeal with the General Council of the Administrative Chamber of the Danistay. EME cannot currently estimate when a decision on the appeal may be taken. As described more fully in
Note 3Agreement to Sell the Doga Project, EME has entered into a contract to sell its interest in the Doga project.

Income Taxes

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

Litigation

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

Environmental Matters and Regulations

EME and its subsidiaries 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. EME believes that it is in substantial compliance with environmental regulatory requirements and that maintaining compliance with
current requirements will not materially affect its financial position or results of operation. However, possible future developments, such as the promulgation of more stringent environmental laws and
regulations, future proceedings that may be initiated by environmental authorities, and settlements agreed to by other companies could affect the costs and the manner in which EME conducts its
business, and may also cause it to make substantial
additional capital expenditures. There is no assurance that EME would be able to recover these increased costs from its customers or that EME's financial position and results of operations would not
be materially adversely affected as a result.

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

With
respect to the investigation and remediation of contaminated property, EME accrues a liability to the extent that the costs are probable and can be reasonably estimated. Midwest
Generation has accrued approximately $3 million for estimated environmental investigation and remediation costs for the Illinois Plants. This estimate is based upon the number of sites, the
scope of work and the estimated costs for environmental activity where such expenditures could be reasonably estimated. Future estimated costs may vary based on changes in regulations or requirements
of federal, state or local governmental agencies, changes in technology, and actual costs of disposal. In addition, future remediation costs will be affected by the nature and extent of contamination
discovered at the sites that requires remediation. There can be no assurance the existence or extent of all contamination at EME's sites has been fully identified, or that activities at the Illinois
Plants or any other facilities identified in

18

---



the
future may not result in additional environmental claims being asserted against EME and its subsidiaries or additional investigations or remedial actions being required. See "Note 15.
Commitments and ContingenciesEnvironmental Matters and Regulations" in EME's financial statements included in its annual report on Form 10-K for the year ended
December 31, 2004 for a more complete discussion of EME's environmental contingencies.

Note 12. Supplemental Statements of Cash Flows Information

Nine Months Ended
September 30,2005

2004(in millions)Cash paidInterest (net of amount capitalized)

$
180

$
190Income taxes (receipts)


(41
)

44Cash payments under plant operating leases


247


213Non-cash activities from deconsolidation of variable interest entitiesAssets

$


$
133Liabilities





165


Note 13. Stock-based Compensation

Edison International has three stock-based employee compensation plans, which are described more fully in Note 14Stock Compensation Plans,
included in EME's annual report on Form 10-K for the year ended December 31, 2004. EME accounts for those plans using the intrinsic value method. Upon grant, no stock-based
employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The
following table illustrates the effect on net income if EME had used the fair value accounting method.

|                                                                                                                             |  | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|---------------------------------------------------------------------------------------------------------------------------- |  | -------------------------------- | --- | ------------------------------- | -
|
|
|Net income, as reported                                                                                                      |  | $                                | 199 |                                 | $
|Add: stock-based compensation expense included in reported net income, net of related tax effects                            |  |                                  | 5   |                                 |  
|Deduct: Total stock-based employee compensation expense determined under fair value based method, net of related tax effects |  |                                  | (5  | )                               |  
|                                                                                                                             |  |                                  |     |                                 |  
|Pro forma net income                                                                                                         |  | $                                | 199 |                                 | $
|                                                                                                                             |  |                                  |     |                                 |  

See "Statement of Financial Accounting Standards No. 123(R)" included in Note 14 below for further discussion.

19

---



Note 14. New Accounting Pronouncements

Statement of Financial Accounting Standards Interpretation No. 46(R)

In December 2003, the FASB re-issued Statement of Financial Accounting Standards Interpretation No. 46, "Consolidation of Variable
Interest Entities" (FIN 46R). The primary objective of the Interpretation is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through
means other than voting rights; such entities are known as variable interest entities. Under this Interpretation, the primary beneficiary is the variable interest holder that absorbs a majority of
expected losses; if no variable interest holder meets this criteria, then it is the variable interest holder that receives a majority of the expected residual returns. The primary beneficiary is
required to consolidate the variable interest entity unless specific exceptions or exclusions are met. This Interpretation applies to variable interest entities created after January 31, 2003,
and applies to variable interest entities in which EME holds a variable interest that it acquired before February 1, 2003. This Interpretation became effective for special purpose entities as
of December 31, 2003 and for all other entities as of March 31, 2004.

Deconsolidation of Variable Interest Entities

In accordance with FIN 46R, EME determined that it was not the primary beneficiary of the Doga and Kwinana projects and, accordingly, deconsolidated these
projects as of March 31, 2004. The Kwinana project was sold on December 16, 2004 as part of the sale of international operations to IPM and, accordingly, is included in discontinued
operations. As described more fully in Note 3Agreement to Sell the Doga Project, EME has entered into a contract to sell its interest in the Doga project.

Variable Interest Entities

EME completed a review of the application of FIN 46R to its subsidiaries and affiliates and concluded that it had variable interests in variable interest entities
as defined in this interpretation. The following table summarizes the variable interest entities held by continuing operations in which EME has a significant variable interest:

|Variable Interest Entity |  | Location        |  | Investment at
September 30, 2005 |     | Ownership
Interest at
September 30, 2005 |    | Description
|------------------------ |  | --------------- |  | -------------------------------- | --- | ---------------------------------------- | -- | -----------
|
|Sunrise                  |  | Fellows, CA     |  | $                                | 122 |                                          | 50 | %          
|Watson                   |  | Carson, CA      |  |                                  | 98  |                                          | 49 | %          
|Sycamore                 |  | Bakersfield, CA |  |                                  | 61  |                                          | 50 | %          
|Midway-Sunset            |  | Fellows, CA     |  |                                  | 54  |                                          | 50 | %          
|Kern River               |  | Bakersfield, CA |  |                                  | 39  |                                          | 50 | %          

EME determined that it is not the primary beneficiary in these entities; accordingly, EME continues to account for its variable interests on the
equity method. EME's maximum exposure to loss in these variable interest entities is generally limited to its investment in these entities.

FASB Staff Position FIN 46(R)-5

In March 2005, the FASB issued Staff Position FIN 46(R)-5, "Implicit Variable Interests Under FIN 46" (FIN 46(R)-5). FIN
46(R)-5 states that a reporting entity should consider whether it holds an implicit variable interest in a variable interest entity or in a potential variable interest entity. If the
aggregate of the explicit and implicit variable interests held by the reporting entity and its related

20

---



parties
would, if held by a single party, identify that party as the primary beneficiary, the party within the group most closely associated with the variable interest entity should be deemed the
primary beneficiary. The guidance of FIN 46(R)-5 is effective for reporting periods beginning after March 3, 2005. FIN 46(R)-5 did not affect EME's accounting for
variable interest entities.

Statement of Financial Accounting Standards No. 123(R) and Staff Accounting Bulletin No. 107

In December 2004, the FASB reissued SFAS No. 123(R), "Share-Based Payment." This is a revision of SFAS No. 123, "Accounting for Stock-Based
Compensation," and supersedes APB No. 25, "Accounting for Stock Issued to Employees." SFAS No. 123(R) establishes accounting standards for transactions in which an entity receives
employee services in exchange for (a) equity instruments of the entity or (b) liabilities that are based on the fair value of the entity's equity instruments or that may be settled by
the issuance of equity instruments. The standard will require EME to recognize the grant-date fair value of Edison International stock options and equity based compensation issued to
employees in the statement of income. The standard also requires that such transactions be accounted for using the fair value based method, thereby eliminating use of the intrinsic value method of
accounting in APB No. 25, which was permitted under Statement 123, as originally issued. EME currently uses the intrinsic value accounting method for stock-based compensation. On
April 14, 2005, the Securities and Exchange Commission (SEC) announced a delay in the effective date for the standard to fiscal years beginning after June 15, 2005. EME will
implement the new standard effective January 1, 2006 by applying the modified prospective transition method. The difference in expense between the two accounting methods related to stock
options granted is shown in Note 13Stock-Based Compensation above. EME is assessing the impact of this accounting standard on its performance shares.

In
March 2005, the SEC issued Staff Accounting Bulletin No. 107 (SAB 107), which conveys the SEC staff's views on the interaction between SFAS No. 123(R) and certain
SEC rules and regulations. SAB 107 also provides the SEC staff's views regarding the valuation of share-based payment arrangements for public companies. EME will apply the principles of SAB 107 in
conjunction with its adoption of SFAS No. 123(R).

FASB Staff Position FAS 109-1

In December 2004, the FASB issued FASB Staff Position FAS 109-1, "Application of FASB Statement No. 109, "Accounting for Income
Taxes,' to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004." The primary objective of this Position is to provide guidance on the application of
SFAS No. 109 to the provision within the American Jobs Creation Act of 2004 that provides a tax deduction on qualified production activities under the provisions of Internal Code
Section 199 effective for tax years beginning after December 31, 2004. Under FAS 109-1, recognition of the tax deduction on qualified production activities,
which include the production of electricity, is ordinarily reported in the year it is earned. The deduction is calculated, and the limitations to the deduction are applied at the consolidated income
tax reporting level by the parent of the affiliated group (Edison International). The benefit of the deduction is then allocated among the members of the group in proportion to each member's
respective amount, if any, of income from qualified production activities. EME will apply FAS 109-1 in computing income taxes as tax deductions related to qualified production activities are
earned.

Statement of Financial Accounting Standard Interpretation No. 47

In March 2005, the FASB issued Financial Accounting Standard Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" (FIN
47). FIN 47 clarifies that an entity is required to

21

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recognize
a liability for the fair value of a conditional asset retirement obligation if the fair value can be reasonably estimated even though uncertainty exists about the timing and (or) method of
settlement. EME is required to adopt FIN 47 by the end of 2005. EME is currently assessing the impact of FIN 47 on its results of operations and financial condition.

Statement of Financial Accounting Standards No. 153

In December 2004, the FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for
Nonmonetary Transactions." SFAS No. 153 amends and clarifies that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, SFAS
No. 153 eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have
commercial substance. Beginning in the third quarter of 2005, SFAS No. 153 is applicable to nonmonetary asset exchanges. The adoption of this standard had no impact on EME's consolidated
financial statements.

Statement of Financial Accounting Standards No. 154

In May 2005, the FASB issued SFAS No. 154, "Accounting Changes and Error Corrections" (SFAS No. 154), which replaces APB Opinion
No. 20, "Accounting Changes," and SFAS No. 3, "Reporting Accounting Changes in Interim Financial Statements." SFAS No. 154 changes the requirements for the accounting for and
reporting of a change in accounting principle, and applies to all voluntary changes in accounting principles, as well as changes required by an accounting pronouncement in the unusual instance it does
not include specific transition provisions. Specifically, SFAS No. 154 requires retrospective application to prior periods' financial statements, unless it is impracticable to determine the
period-specific effects or the cumulative effect of the change. When it is impracticable to determine the effects of the change, the new accounting principle must be applied to the balances of assets
and liabilities as of the beginning of the earliest period for which retrospective application is practicable and a corresponding adjustment must be made to the opening balance of retained earnings
for that period. When it is impracticable to determine the cumulative effect of the change, the new principle must be applied as if it were adopted prospectively from the earliest date practicable.
SFAS No. 154 is effective for all accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. This standard does not change the transition
provisions of any existing pronouncements. EME does not expect the adoption of this standard will have a material impact on its consolidated financial statements.

22

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

This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) contains "forward-looking statements"
within the meaning of the Private Securities Litigation Reform Act of 1995. These statements reflect Edison Mission Energy's (EME's) current expectations and projections about future events based on
EME's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information
distributed by EME that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects,"
"believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of
strategy or plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those
anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ, or that otherwise could impact EME or its subsidiaries, include but are not limited
to:



Certain of the risk factors listed above are discussed in more detail in "Market Risk Exposures" below, and under "Risks Related to the Business" in the MD&A
included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2004. Additional information about the risk factors listed above and other risks and
uncertainties is contained throughout this MD&A. Readers are urged to read this entire quarterly report, including the information incorporated by reference, and carefully consider the risks,
uncertainties and other factors that affect EME's business. The information contained in this report is subject to change without notice. Forward-looking statements speak only as of the date they are
made and

23

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EME is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by EME with the Securities and Exchange Commission.

The MD&A of this Form 10-Q discusses material changes in the results of operations, financial condition and other developments of EME since
December 31, 2004, and as compared to the third quarter and nine months ended September 30, 2004. This discussion presumes that the reader has read or has access to the MD&A
included in Item 7 of EME's annual report on Form 10-K for the year ended December 31, 2004.

The
MD&A presents a discussion of EME's financial results and analysis of its financial condition. It is presented in four major sections:

PageManagement's Overview; Critical Accounting Estimates

24Results of Operations

29Liquidity and Capital Resources

42Market Risk Exposures

51


MANAGEMENT'S OVERVIEW; CRITICAL ACCOUNTING ESTIMATES

Management's Overview

EME Restructuring Activities

During 2004, EME sold most of its international operations. EME's international operations, except for the Doga project, are accounted for as discontinued
operations in accordance with Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," and, accordingly, all prior
periods have been restated to reclassify the results of operations and assets and liabilities as discontinued operations. In the first quarter of 2005, EME completed the sale of two international
projects:



EME
entered into a purchase agreement, dated as of August 17, 2005, to sell its 80% interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji
Yatirim Isletme ve Ticaret Limited Sirketi, which will acquire an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which will acquire a 50% interest in the
Doga project. Completion of the sale is subject to the satisfaction of a number of closing conditions, including obtaining the consent of a majority of the project's lenders. The sale is expected to
close in the fourth quarter of 2005.

In
connection with the sale of its international operations in 2004, together with cash on hand, in January 2005, EME:



24

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In
April 2005, EME made an equity contribution of $300 million to Midwest Generation, which used the proceeds to repay indebtedness. See "Liquidity and Capital
ResourcesMidwest Generation Financing" for a discussion of the Midwest Generation financing.

EME
has also completed a review of its domestic organization to better align its resources with its domestic business requirements. Management and organizational changes have been
implemented to streamline EME's reporting relationships and eliminate its regional management structure. As a result of these changes, EME recorded charges of approximately $10 million
(pre-tax) in the nine months ended September 30, 2005 for severance and related costs.

Business Development Plans

Following the completion of restructuring activities described above, EME, together with its affiliate, Edison Capital, has established a joint business
development effort for wind projects in addition to EME's development plans for thermal projects.

Wind Business Development

EME's affiliate, Edison Capital, has an existing 196 MW portfolio of wind projects located in Iowa and Minnesota. In addition, a subsidiary of Edison Capital has
entered into an agreement to acquire a 120 MW wind project in eastern New Mexico from a wind generation developer for $157 million. The acquisition of this project is subject to achieving commercial
operations and other closing conditions, which are expected to be met in December 2005. EME and Edison Capital are considering transferring some or all of these projects to EME as part of EME's
independent power generation portfolio and expanding significantly, through EME, further investments in wind projects throughout the U.S. In addition, EME is considering entering into agreements to
purchase wind turbines to support these wind business development activities. Pursuit of new renewable energy investments depends upon economic and regulatory conditions and may be affected by
government policies supporting renewable energy. In August 2005, federal incentives for new wind projects, referred to as production tax credits, were extended for new wind projects installed by
December 31, 2007 under a comprehensive federal energy bill, named the "Energy Policy Act of 2005."

Thermal Business Development

EME continues to review opportunities to develop or acquire additions to its power generation portfolio. As part of this activity, EME has begun the process of
obtaining permits for two sites in Southern California for peaker plants and has responded to several requests for proposals to build or acquire generation. Pursuit of new thermal projects in
California and elsewhere depends on a range of factors outside the control of EME, and, accordingly, there is no assurance that these efforts will result in the actual development or acquisition of
additional generation capacity.

Expiration of the Exelon Power Purchase Agreements

The five-year power purchase agreements between Midwest Generation and Exelon Generation Company expired on December 31, 2004 and, accordingly,
beginning January 1, 2005, all the output from the Illinois Plants is considered merchant generation. In 2004, approximately 53% of the energy and capacity sales from the Illinois Plants were
to Exelon Generation under the power purchase agreements.

25

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The
Exelon Generation power purchase agreement for coal-fired units was structured to provide significant capacity payments and lower energy payments which were primarily
designed to reimburse the cost of production. The agreement also provided for substantial capacity payments during the summer months. The Illinois Plants continue to derive revenue from sales
of capacity and energy. In the current wholesale energy market, energy prices are substantially higher than the energy prices previously set forth in the agreement, but capacity payments are, and are
expected to remain for some time, substantially lower. As a result, the composition of EME's revenues was significantly different in the first nine months of 2005 compared to 2004. EME's
merchant generation is subject to significant volatility as described further in "Market Risk ExposuresCommodity Price Risk."

Wholesale Energy Prices in Illinois

Wholesale energy prices at the Northern Illinois Hub (related to the Illinois Plants) have increased substantially in 2005 from the comparable market prices in
2004 driven largely by increases in the market price of natural gas and oil. The average market price during the nine months ended September 30, 2005 at the Northern Illinois Hub
(related to the Illinois Plants) increased to $44.26 per MWh, compared to the average market prices "Into ComEd" and at the Northern Illinois Hub of $29.36 per MWh during the nine months ended
September 30, 2004.

Energy Trading Activities

EME seeks to generate profit by utilizing the commercial platform of its subsidiary, Edison Mission Marketing & Trading, to engage in trading activities in those
markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. Edison Mission Marketing & Trading trades power, fuel and transmission
primarily in the eastern power grid using products available over-the-counter, through exchanges and from independent system operators. Earnings from energy trading activities were $84 million and
$125 million for the third quarter and nine months ended September 30, 2005, respectively. Volatile market conditions during the first nine months of 2005, driven by increased prices for natural gas
and oil and warmer summer temperatures, have created favorable conditions for Edison Mission Marketing & Trading's trading strategies in 2005 compared to 2004. This trading activity is limited by the
risk management policies of EME, including a limit on value at risk. During the first nine months of 2005, the maximum value at risk associated with trading of over-the-counter products and
exchange-traded products was $1.9 million, using a 95% confidence interval and assuming a one-day holding period. As of September 30, 2005, the collateral required to support Edison Mission
Marketing & Trading's transactions was approximately $90 million. EME's management pays particular attention to the risk management of these activities, because income from them will vary
substantially from period to period depending on market conditions.

Overview of EME's 2005 Financial Performance from Continuing Operations

EME's financial performance in the third quarter and nine months ended September 30, 2005 improved over the third quarter and nine months ended
September 30, 2004 with a number of important items affecting performance:



26

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27

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Critical Accounting Estimates

For a discussion of EME's critical accounting estimates, refer to "Critical Accounting Estimates" on page 38 of EME's annual report on
Form 10-K for the year ended December 31, 2004.

28

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RESULTS OF OPERATIONS

Introduction

This section discusses operating results for the third quarters and nine months of 2005 and 2004. Continuing operations include EME's Illinois
Plants and Homer City facilities, energy trading, equity investments in power projects primarily located in California, corporate interest expense and general and administrative expenses. Discontinued
operations include all of EME's international operations, except the Doga project. It is organized under the following headings:

PageNet Income Summary

29Results of Continuing Operations

30Results of Discontinued Operations

40New Accounting Pronouncements

41Proposed Accounting Pronouncements

41


Net Income Summary

Net income is comprised of the following components:

|                                         |  | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|---------------------------------------- |  | -------------------------------- | --- | ------------------------------- | -
|
|
|Income (loss) from continuing operations |  | $                                | 172 |                                 | $
|Income from discontinued operations      |  |                                  | 27  |                                 |  
|                                         |  |                                  |     |                                 |  
|Net income                               |  | $                                | 199 |                                 | $
|                                         |  |                                  |     |                                 |  

29

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EME's income (loss) from continuing operations for the third quarters and nine months ended September 30, 2005 and 2004 is comprised of:

|                                                             |                                                                                                                                                                           | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|------------------------------------------------------------ | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------- | -------------------------------- | --- | ------------------------------- | -
|
|
|Income (loss) from Continuing Operations                     |                                                                                                                                                                           | $                                | 172 |                                 | $
|Discrete Items (after tax)                                   |                                                                                                                                                                           |                                  |     |                                 |  
|                                                             | Loss on lease termination, asset impairment and other charges (see "Results of Continuing OperationsEarnings from Consolidated OperationsIllinois Plants")             |                                  |     |                                |  
|                                                             | Impairment loss on equity method investment (see "Results of Continuing OperationsEarnings from Unconsolidated AffiliatesImpairment Loss on Equity Method Investment") |                                  |     | (34                             | )
|                                                             | Gain on sale of assets (see "Results of Continuing OperationsGain on Sale of Assets")                                                                                   |                                  |     |                                |  
|                                                             | Other                                                                                                                                                                     |                                  |     |                                |  
|                                                             |                                                                                                                                                                           |                                  |     |                                 |  
|Income from Continuing Operations (excluding discrete items) |                                                                                                                                                                           | $                                | 206 |                                 | $
|                                                             |                                                                                                                                                                           |                                  |     |                                 |  

The
increase in the third quarter income from continuing operations, excluding discrete items, was primarily attributable to higher energy trading income and higher wholesale energy
prices at the Illinois Plants and Homer City facilities. The year-to-date increase in income from continuing operations, excluding discrete items, was primarily due to higher
wholesale energy prices at the Illinois Plants and Homer City facilities, higher energy trading income and resolution of a tax dispute.

Results of Continuing Operations

Overview

EME operates in one line of business, electric power generation. Operating revenues are primarily derived from the sale of power generated from the Illinois
Plants and Homer City facilities. Intercompany interest expense and income between EME and its consolidated subsidiaries have been eliminated in the following project results, except as described
below with respect to loans provided to EME from a wholly owned subsidiary, Midwest Generation. Equity in income from unconsolidated affiliates relates to energy projects accounted for under the
equity method. EME recognizes its proportional share of the income or loss of such entities.

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

30

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The
following section provides a summary of the operating results for the third quarters and nine months ended September 30, 2005 and 2004 together with discussions
of the contributions by specific projects and of other significant factors affecting these results.

|                                                                      |                                                                                    | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |  
|--------------------------------------------------------------------- | ---------------------------------------------------------------------------------- | -------------------------------- | --- | ------------------------------- | -
|
|
|Income (Loss) before Taxes and Minority Interest
(Earnings/Losses)(1) |                                                                                    |                                  |     |                                 |  
|                                                                      | Consolidated operations                                                            |                                  |     |                                 |  
|                                                                      | Illinois Plants                                                                    |                                  | $   | 187                             |  
|                                                                      | Homer City                                                                         |                                  |     | 33                              |  
|                                                                      | Energy Trading(2)                                                                  |                                  |     | 84                              |  
|                                                                      | Doga                                                                               |                                  |     |                                |  
|                                                                      | Other                                                                              |                                  |     | (2                              | )
|                                                                      | Unconsolidated affiliates                                                          |                                  |     |                                 |  
|                                                                      | Big 4 projects                                                                     |                                  |     | 73                              |  
|                                                                      | Sunrise                                                                            |                                  |     | 29                              |  
|                                                                      | March Point                                                                        |                                  |     | 5                               |  
|                                                                      | Impairment loss on equity method investment                                        |                                  |     | (55                             | )
|                                                                      | Doga                                                                               |                                  |     | (2                              | )
|                                                                      | Other                                                                              |                                  |     | 5                               |  
|                                                                      |                                                                                    |                                  |     |                                 |  
|                                                                      |                                                                                    |                                  | 357 |                                 |  
|                                                                      | Corporate interest expense                                                         |                                  |     | (67                             | )
|                                                                      | Corporate and regional administrative and general                                  |                                  |     | (26                             | )
|                                                                      | Gain on sale of assets                                                             |                                  |     |                                |  
|                                                                      | Loss on early extinguishment of debt                                               |                                  |     |                                |  
|                                                                      | Corporate interest income and other, net                                           |                                  |     | 14                              |  
|                                                                      |                                                                                    |                                  |     |                                 |  
|                                                                      | Income (Loss) from Continuing Operations Before Income Taxes and Minority Interest |                                  | $   | 278                             |  
|                                                                      |                                                                                    |                                  |     |                                 |  

---

31

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Earnings from Consolidated Operations

Illinois Plants

|                                      |                                                               | Three Months Ended
September 30, |     | Nine Months Ended
September 30, |      
|------------------------------------- | ------------------------------------------------------------- | -------------------------------- | --- | ------------------------------- | -----
|
|
|Operating Revenues                    |                                                               |                                  |     |                                 |      
|                                      | Energy revenues                                               |                                  | $   | 438                             |      
|                                      | Capacity revenues                                             |                                  |     | 10                              |      
|                                      | Other revenues                                                |                                  |     | 3                               |      
|                                      | Net losses from price risk management                         |                                  |     | (33                             | )    
|                                      |                                                               |                                  |     |                                 |      
|                                      | Total operating revenues                                      |                                  |     | 418                             |      
|                                      |                                                               |                                  |     |                                 |      
|Operating Expenses                    |                                                               |                                  |     |                                 |      
|                                      | Fuel                                                          |                                  |     | 107                             |      
|                                      | Plant operations                                              |                                  |     | 75                              |      
|                                      | Plant operating leases                                        |                                  |     | 19                              |      
|                                      | Depreciation and amortization                                 |                                  |     | 25                              |      
|                                      | Loss on lease termination, asset impairment and other charges |                                  |     |                                |      
|                                      | Administrative and general                                    |                                  |     | 1                               |      
|                                      |                                                               |                                  |     |                                 |      
|                                      | Total operating expenses                                      |                                  |     | 227                             |      
|                                      |                                                               |                                  |     |                                 |      
|Operating Income (Loss)               |                                                               |                                  | 191 |                                 |      
|                                      |                                                               |                                  |     |                                 |      
|Other Income (Expense)                |                                                               |                                  |     |                                 |      
|                                      | Interest income from note receivable from EME                 |                                  |     | 28                              |      
|                                      | Interest expense and other                                    |                                  |     | (32                             | )    
|                                      |                                                               |                                  |     |                                 |      
|                                      | Total other income (expense)                                  |                                  |     | (4                              | )    
|                                      |                                                               |                                  |     |                                 |      
|Income (Loss) Before Taxes            |                                                               | $                                | 187 |                                 | $    
|                                      |                                                               |                                  |     |                                 |      
|Statistics  Coal-Fired Generation(1) |                                                               |                                  |     |                                 |      
|                                      | Generation (in GWh):                                          |                                  |     |                                 |      
|                                      |                                                               | Merchant                         |     |                                 | 8,137
|                                      |                                                               | Power purchase agreement         |     |                                 |     
|                                      |                                                               |                                  |     |                                 |      
|                                      |                                                               | Total coal-fired generation      |     |                                 | 8,137
|                                      |                                                               |                                  |     |                                 |      
|                                      | Equivalent availability(2)                                    |                                  |     | 87.9%                           |      
|                                      | Forced outage rate(3)                                         |                                  |     | 9.4%                            |      
|                                      | Average energy price/MWh:                                     |                                  |     |                                 |      
|                                      |                                                               | Merchant                         |     | $                               | 53.85
|                                      |                                                               | Power purchase agreement         |     | $                               |     
|                                      |                                                               | Total coal-fired generation(4)   |     | $                               | 53.85

---

32

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Earnings (losses) from the Illinois Plants were $187 million and $297 million during the three and nine months ended
September 30, 2005, respectively, compared to $98 million and $(850) million for the comparable periods in the prior year. Discrete items affecting the income (loss) of the
Illinois Plants include:



Earnings
from the Illinois Plants, excluding the above discrete items, were $133 million and $139 million during the three and nine months ended September 30,
2004, respectively, compared to $187 million and $297 million for the three and nine months ended September 30, 2005, respectively. The increase in the third quarter of
2005 earnings of $54 million was primarily attributable to higher energy revenues resulting from increased average energy prices. Earnings for the nine-month period ended
September 30, 2005 increased $158 million due to the following factors:



Partially
offset by:



Losses
from price risk management activities increased $30 million and $44 million for the third quarter and nine months ended September 30, 2005,
respectively, compared to the corresponding periods of 2004. The 2005 increases were primarily due to significantly greater losses in 2005 on

33

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futures,
swaps and power contracts compared to gains on power contracts recorded during the third quarter of 2004. These price risk management contracts were entered into to hedge the price risk
related to projected sales of power through 2007 (sometimes referred to as economic hedges). However, as such contracts did not qualify for hedge accounting under SFAS No. 133, these positions
are accounted for at fair value with changes in fair value recorded through earnings. Losses on these contracts are a result of increased power prices. While these positions reflect a current loss,
the market price of power has increased, which will result in higher revenue recorded in future periods if power prices do not change. See "Market Risk ExposuresCommodity Price Risk" for
more information regarding forward market prices.

Under
SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective
portion, is immediately recognized in earnings. Midwest Generation recorded net losses of approximately $0.5 million and $5 million for the third quarters of 2005 and 2004, respectively,
and $0.2 million for both the nine months ended September 30, 2005 and 2004, representing the amount of cash flow hedges' ineffectiveness. The ineffective portion of the cash flow
hedges was primarily attributable to changes in the difference between energy prices at the delivery points set forth in the hedge contracts and the energy prices at the delivery points where power
generated by the Illinois Plants is delivered into the transmission system. In addition, Midwest Generation recognized losses in 2004 on the ineffective portion of forward contracts that expired
during the period.

The
earnings (losses) of the Illinois Plants included interest income of $28 million for both the third quarters of 2005 and 2004 and $85 million for both the
nine months ended September 30, 2005 and 2004, related to loans to EME. In August 2000, Midwest Generation, which owns or leases the Illinois Plants, entered into a
sale-leaseback transaction of the Powerton-Joliet facilities. The proceeds from the sale of these facilities were loaned to EME, which also provided a guarantee of the related lease
obligations of Midwest Generation. The Powerton-Joliet sale-leaseback is recorded as an operating lease by EME for accounting purposes.

34

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Homer City

|                       |                                       | Three Months Ended
September 30, |    | Nine Months Ended
September 30, |  
|---------------------- | ------------------------------------- | -------------------------------- | -- | ------------------------------- | -
|
|
|Operating Revenues     |                                       |                                  |    |                                 |  
|                       | Energy revenues                       |                                  | $  | 185                             |  
|                       | Capacity revenues                     |                                  |    | 5                               |  
|                       | Net losses from price risk management |                                  |    | (22                             | )
|                       |                                       |                                  |    |                                 |  
|                       | Total operating revenues              |                                  |    | 168                             |  
|                       |                                       |                                  |    |                                 |  
|Operating Expenses     |                                       |                                  |    |                                 |  
|                       | Fuel                                  |                                  |    | 84                              |  
|                       | Plant operations                      |                                  |    | 21                              |  
|                       | Plant operating leases                |                                  |    | 25                              |  
|                       | Depreciation and amortization         |                                  |    | 4                               |  
|                       | Administrative and general            |                                  |    | 3                               |  
|                       |                                       |                                  |    |                                 |  
|                       | Total operating expenses              |                                  |    | 137                             |  
|                       |                                       |                                  |    |                                 |  
|Operating Income       |                                       |                                  | 31 |                                 |  
|                       |                                       |                                  |    |                                 |  
|Other Income (Expense) |                                       |                                  |    |                                 |  
|                       | Interest and other income             |                                  |    | 2                               |  
|                       | Interest expense                      |                                  |    |                                |  
|                       |                                       |                                  |    |                                 |  
|                       | Total other income (expense)          |                                  |    | 2                               |  
|                       |                                       |                                  |    |                                 |  
|Income Before Taxes    |                                       | $                                | 33 |                                 | $
|                       |                                       |                                  |    |                                 |  
|Statistics             |                                       |                                  |    |                                 |  
|                       | Generation (in GWh)                   |                                  |    | 4,060                           |  
|                       | Equivalent availability(1)            |                                  |    | 98.7%                           |  
|                       | Forced outage rate(2)                 |                                  |    | 0.2%                            |  
|                       | Average energy price/MWh              |                                  | $  | 45.45                           |  

---

Earnings from Homer City increased $7 million and $22 million for the third quarter and nine months ended
September 30, 2005, respectively, compared to the corresponding periods of 2004. The 2005 increases were primarily attributable to higher energy revenues in 2005 due to increased generation and
higher average energy prices as compared to 2004. During the first quarter of 2004, an unplanned outage at Unit 1 contributed to lower generation and higher maintenance costs. During the third quarter
of 2004, coal deliveries under contracts with four fuel suppliers to Homer City were temporarily interrupted. As a result of these interruptions, Homer City reduced generation during
off-peak periods when power prices were lower and purchased coal from alternative suppliers at spot prices, which were substantially higher than the contract prices from these four fuel
suppliers. Partially offsetting this increase were higher fuel costs attributable to higher fuel consumption, higher coal prices and higher priced SO2 emission allowances. Included in fuel costs was
$22 million and $10 million during the third quarters of 2005 and 2004, respectively, and $51 million and $24 million during the nine months ended
September 30, 2005 and 2004, respectively, related to the net cost of emission

35

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allowances.
See "Market Risk ExposuresCommodity Price RiskEmission Allowances Price Risk" for more information regarding the price of SO2 allowances.

The
average energy price earned by Homer City during the third quarter and nine months ended September 30, 2005 was $45.45/MWh and $44.17/MWh compared to the average real-time
market price at the Homer City busbar for the same periods of $62.56/MWh and $50.54/MWh. Homer City's average energy price was lower than the average real-time market price due
to: (1) hedge contracts having been entered into in prior periods when market prices were lower, and (2) the differential in market prices at the PJM West Hub versus the Homer
City busbar having increased (referred to as a widening of the basis between these PJM locations). Homer City hedges its energy price risk at PJM West Hub and retains the risk that the basis between
PJM West Hub and Homer City widens. See "Market Risk ExposuresCommodity Price RiskBasis Risk."

Losses
from price risk management activities increased $16 million and $13 million for the third quarter and nine months ended September 30, 2005,
respectively, compared to the corresponding periods of 2004. The 2005 increases were primarily attributable to the ineffective portion of forward and futures contracts which are derivatives that
qualify as cash flow hedges under SFAS No. 133. Homer City recorded net losses of approximately $32 million and $9 million during the third quarters of 2005 and 2004,
respectively, and $35 million and $9 million during the nine months ended September 30, 2005 and 2004, respectively, representing the amount of cash flow hedges'
ineffectiveness. The ineffective losses from Homer City were primarily attributable to an increase in the difference between energy prices at PJM West Hub (the settlement point under forward
contracts) and the energy prices at the delivery point where power generated by the Homer City facilities is delivered into the transmission system (referred to as the Homer City busbar). In addition,
Homer City recognized ineffective gains (losses) related to forward contracts that expired during the respective periods. Partially offsetting the ineffective losses were gains in 2005 primarily
related to futures contracts that did not qualify for hedge accounting under SFAS No. 133. See "Market Risk ExposuresCommodity Price Risk" for more information regarding forward
market prices.

Seasonal Disclosure

Due to higher electric demand resulting from warmer weather during the summer months, electric revenues generated from the Illinois Plants and the Homer
City facilities are generally higher during the third quarter of each year. However, as a result of recent increases in market prices for power (driven in part from higher natural gas and oil prices),
this historical trend may not be applicable to quarterly revenue in the future.

Energy Trading

EME seeks to generate profit by utilizing the commercial platform of its subsidiary, Edison Mission Marketing & Trading, to engage in trading activities in those
markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. Edison Mission Marketing & Trading trades power, fuel and transmission
primarily in the eastern power grid using
products available over-the-counter, through exchanges and from independent system operators. Earnings from energy trading activities were $84 million and $125 million for the third quarter and nine
months ended September 30, 2005, respectively. Volatile market conditions during the first nine months of 2005, driven by increased prices for natural gas and oil and warmer summer temperatures, have
created favorable conditions for Edison Mission Marketing & Trading's trading strategies in 2005 compared to 2004.

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Earnings from Unconsolidated Affiliates

Big 4 Projects

Earnings from the Big 4 projects increased $1 million and $12 million for the third quarter and nine months ended September 30, 2005,
compared to the corresponding periods of 2004. The 2005 increases in earnings were primarily due to higher energy prices in 2005 compared to 2004. The impact of the higher energy prices in 2005 was
partially offset by lower earnings from the Kern River project during the third quarter and nine months ended September 30, 2005, compared to the corresponding periods of 2004 resulting
from the expiration of the project's long-term power purchase and steam supply agreements in August 2005. See "Expiration of Power Purchase Agreement and Steam Supply Agreement"
below for more information.

The
earnings from the Big 4 projects included interest expense from Edison Mission Energy Funding of $2 million and $3 million for the third quarters of 2005 and 2004,
respectively. For the nine months ended September 30, 2005 and 2004, earnings included interest expense from Edison Mission Energy Funding of $7 million and $10 million,
respectively.

Expiration of Power Purchase Agreement and Steam Supply Agreement

EME
owns a 50% partnership interest in Kern River Cogeneration Company, which owns a 300 MW natural gas-fired cogeneration facility located near Bakersfield, California,
which EME refers to as the Kern River project. The Kern River project's long-term power purchase agreement with Southern California Edison Company (SCE) and its steam supply agreement with
Texaco Exploration and Production Inc. (TEPI) both expired on August 9, 2005.

Kern
River Cogeneration entered into a Reformed Standard Offer No. 1 As-Available Energy and Capacity Power Purchase Agreement (RSO#1) with SCE, effective
August 10, 2005. As of
September 30, 2005, Kern River Cogeneration was negotiating a bilateral agreement with SCE which is expected to be completed in late 2005, subject to California Public Utilities Commission
approval. Kern River Cogeneration also entered into a new Steam Purchase and Sale Agreement with Chevron North America Exploration and Production Company, a division of Chevron U.S.A., Inc.,
effective August 10, 2005. Due to lower volumes and pricing, revenues under the new agreements are expected to be lower than revenues under the expired agreements.

Sunrise

Earnings from the Sunrise project increased $1 million and $2 million for the third quarter and nine months ended September 30, 2005,
compared to the corresponding periods of 2004. The 2005 increases primarily resulted from higher energy revenues attributable to increased dispatch.

March Point

Earnings from March Point increased $6 million and $3 million for the third quarter and nine months ended September 30, 2005,
respectively, compared to the corresponding periods of 2004. The 2005 increases in earnings were primarily due to mark-to-market gains on fuel contracts entered into by
March Point, which are derivatives that do not qualify as cash flow hedges under SFAS No. 133.

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Impairment Loss on Equity Method Investment

During the third quarter of 2005, EME fully impaired its equity investment in the March Point project following an updated forecast of future project cash
flows. The March Point project is a 140 MW natural gas-fired cogeneration facility located in Anacortes, Washington, in which a subsidiary of EME owns a 50% partnership interest.
The March Point project sells electricity to Puget Sound Energy, Inc. under two power purchase agreements that expire in 2011 and sells steam to Equilon Enterprises, LLC (a subsidiary of Shell
Oil) under a steam supply agreement that also expires in 2011. March Point purchases a portion of its fuel requirements under long-term contracts with the remaining requirements
purchased at current market prices. March Point's power sales agreements do not provide for a price adjustment related to the project's fuel costs. During the third quarter of 2005,
long-term natural gas prices increased substantially, thereby
adversely affecting the future cash flows of the March Point project. As a result, management concluded that its investment was impaired and recorded a $55 million charge during the
third quarter of 2005.

Doga

In accordance with Statement of Financial Accounting Standards Interpretation No. 46(R), "Consolidation of Variable Interest Entities," EME determined that
it was not the primary beneficiary of the Doga project and, accordingly, deconsolidated this project as of March 31, 2004. Revenues included in EME's consolidated statements of income from the
Doga project were $29 million for the nine months ended September 30, 2004, representing revenues from the first quarter of 2004. Earnings from the Doga project were
$6 million for the nine months ended September 30, 2004, representing earnings from the first quarter of 2004. Beginning April 1, 2004, EME recorded its interest in the
Doga project on the equity method basis of accounting. Earnings (losses) from the Doga project were $(2) million and $3 million for the third quarter and nine months ended
September 30, 2005, respectively, compared to $2 million and $3 million for the third quarter and nine months ended September 30, 2004, respectively.

On
August 17, 2005, EME entered into a purchase agreement to sell its 80% interest in the Doga project to EME's co-investor in the Doga project, Doga Enerji Yatirim
Isletme ve Ticaret Limited Sirketi, which will acquire an additional 30% interest in the Doga project, and The Kansai Electric Power Co., Inc., which will acquire a 50% interest in the Doga
project. Completion of the sale is subject to the satisfaction of a number of closing conditions, including obtaining the consent of a majority of the project's lenders. The sale is expected to close
in the fourth quarter of 2005.

Seasonal Disclosure

EME's third quarter equity in income from its energy projects is materially higher than equity in income related to other quarters of the year due to warmer
weather during the summer months and because a number of EME's energy projects located on the West Coast have power sales contracts that provide for higher payments during the
summer months.

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Corporate Interest Expense

Three Months Ended
September 30,

Nine Months Ended
September 30,2005

2004

2005

2004(in millions)Interest expense to third parties

$
39

$
41

$
118

$
125Interest expense to Midwest Generation


28


28


85


85Total corporate interest expense

$
67

$
69

$
203

$
210


Corporate and Regional Administrative and General Expenses

Administrative and general expenses decreased $11 million and $16 million for the third quarter and nine months ended September 30,
2005, respectively, compared to the corresponding periods of 2004. The decreases were primarily due to decreased use of third-party consultants. Partially offsetting the
year-to-date decrease was higher costs incurred in 2005 to implement EME's restructuring plan described under "Management's Overview."

Gain on Sale of Assets

Gain on sale of assets in 2004 consisted of a $47 million gain related to the sale of 100% of EME's stock of Edison Mission Energy Oil & Gas, which
in turn held minority interests in Four Star Oil & Gas, and a $4 million loss related to the sale of EME's interest in Brooklyn Navy Yard Cogeneration Partners, L.P. recorded during the
first quarter of 2004.

Loss on Early Extinguishment of Debt

Loss on early extinguishment of debt was $4 million in the first nine months of 2005. Extinguishment of debt consisted of a $4 million loss
related to the early repayment of EME's junior subordinated debentures recorded during the first quarter of 2005.

Corporate Interest Income and Other, Net

Corporate interest income and other (net) increased $17 million and $35 million for the third quarter and nine months ended
September 30, 2005, respectively, compared to the corresponding periods of 2004. The increases were primarily attributable to higher interest income resulting from higher average cash balances
during the first nine months of 2005, compared with the corresponding period of 2004.

Income Taxes

EME's income tax provision (benefit) from continuing operations was $129 million and $(342) million during the nine months ended
September 30, 2005 and 2004, respectively. Income tax benefits are recognized pursuant to a tax-allocation agreement with Edison International. See "Liquidity and Capital
ResourcesEME's Liquidity as a Holding CompanyIntercompany Tax-Allocation Agreement." During the second quarter of 2005, EME resolved a dispute regarding
additional taxes asserted by the Internal Revenue Service during the audit of the 1994-1996 tax returns. As a result of the resolution of this item, EME reversed $11.5 million of
accrued taxes which was recorded as a reduction of income taxes during the second quarter of 2005. During the second quarter of 2004, EME recorded a tax benefit of $368 million primarily
relating to the loss on the termination of

39

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the
Collins Station lease, and during the first quarter of 2004, EME recorded a tax provision of $18 million relating to the sale of 100% of its stock in Edison Mission Energy Oil & Gas,
which in turn held interests in Four Star Oil & Gas.

Results of Discontinued Operations

Income from discontinued operations, net of tax, was $27 million and $498 million during the third quarters of 2005 and 2004, respectively, and
$55 million and $570 million during the first nine months of 2005 and 2004, respectively. During the first nine months of 2005, EME completed the following sales:



The
aggregate after-tax gain on the sale of the aforementioned projects was $5 million. During the first nine months of 2004, EME completed the following sale:



During
the quarter ended September 30, 2005, EME recorded a tax benefit adjustment of $28 million which resulted from completion of the 2004 federal and California income
tax returns and quarterly review of tax accruals. The majority of the tax adjustments are related to the sale of the international projects in December 2004. During the third quarter ended
September 30, 2004, EME recorded a deferred income tax benefit of $327 million in accordance with Emerging Issues Task Force Issue No. 93-17, "Recognition of Deferred
Tax Assets for a Parent Company's Excess Tax Basis in the Stock of a Subsidiary that is Accounted for as a Discontinued Operation," (EITF 93-17). Under EITF 93-17, because the
tax basis of the stock of EME's Dutch subsidiary, MEC International B.V., exceeded EME's book basis, an adjustment to deferred taxes was required during the third quarter of 2004.

During
the third quarter of 2004, EME reclassified its international activities which were then under contracts for sale as discontinued operations. Subsequently, EME completed the sale
of these operations, except for the Doga project, which was no longer under a contract for sale. While EME continued to seek to sell its ownership interest in this project, there was no assurance that
such efforts would result in a sale during the twelve-month period prescribed under Statement of Financial Accounting Standards No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." As a result, EME reclassified the Doga project to continuing operations during the fourth quarter of 2004, and, accordingly, it is reflected as part of continuing
operations for all periods presented.

Previously Reported Discontinued Operations

Lakeland Project

EME previously owned and operated a 220 MW combined cycle, natural gas-fired power plant located in the United Kingdom, known as the Lakeland project.
The ownership of the project was held through EME's indirect subsidiary, Lakeland Power Ltd., which sold power generated from the plant

40

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pursuant
to a power sales agreement with Norweb Energi Ltd., a subsidiary of TXU (UK) Holdings Limited (TXU UK) and an indirect subsidiary of TXU Europe Group plc (TXU Europe). EME ceased
consolidating the activities of Lakeland Power Ltd. in 2002, when an administrative receiver was appointed following a default by Norweb Energi Ltd. under the power sales agreement.
Accordingly, EME accounts for its ownership of Lakeland Power Ltd. on the cost method and earnings are recognized as cash is distributed from this entity.

As
previously disclosed, the administrative receiver of Lakeland Power Ltd. filed a claim against Norweb Energi Ltd. for termination of the power sales agreement. On
November 19, 2002, TXU UK and TXU Europe, together with a related entity, TXU Europe Energy Trading Limited (TXU Energy), entered into formal administration proceedings of their own in the
United Kingdom (similar to bankruptcy proceedings in the United States). On March 31, 2005, Lakeland Power Ltd. received £112 million (approximately
$210 million) from the TXU administrators, representing an interim payment of 97% of its accepted claim of £116 million (approximately $217 million).

From
the amount received, Lakeland Power Ltd., now controlled by a liquidator in the United Kingdom, has made a payment of £20 million (approximately
$37 million) to EME on April 7, 2005 comprised of £7 million (approximately $13 million) for a secured loan which EME purchased from Lakeland
Power Ltd.'s secured creditors in 2004 and certain unsecured receivables from Lakeland Power Ltd., and £13 million (approximately $24 million) as a distribution
to the EME subsidiary that owns the equity interest in Lakeland Power Ltd. The distribution was recognized in income during the quarter ended June 30, 2005. Additionally, Lakeland
Power Ltd. will pay to EME's subsidiary that owns the equity interest in Lakeland Power Ltd. the amount remaining after resolution of any remaining secured and unsecured creditor claims
and payment of or provision for tax liabilities and the fees and expenses associated with Lakeland Power Ltd.'s liquidation.

EME
estimates that the remaining net proceeds after tax (including taxes due in the United States) and net income resulting from the above payments will be approximately
$64 million. The majority of the remaining proceeds are expected to be received in 2006, when Lakeland Power Ltd.'s liquidation is expected to be completed. Because the amounts required
to settle outstanding claims and UK taxes have not been finalized and cannot be estimated precisely in the context of the liquidation, the actual amount of net proceeds and increase in net income may
vary materially from the above estimate.

New Accounting Pronouncements

For a discussion of new accounting pronouncements affecting Edison Mission Energy, see "Mission Energy Holding Company and Subsidiaries Notes to Consolidated
Financial StatementsNote 14. New Accounting Pronouncements."

Proposed Accounting Pronouncements

Statement of Financial Accounting Standard Interpretation, "Accounting for Uncertain Tax Positions"

On July 14, 2005, the FASB published an exposure draft of a proposed interpretation, "Accounting for Uncertain Tax Positions." The exposure draft seeks to
reduce the diversity in practice associated with recognition and measurement in the accounting for income taxes. It would apply to all tax positions accounted for in accordance with FASB Statement
No. 109, "Accounting for Income Taxes." The exposure draft requires that a tax position meet a "probable recognition threshold" for the benefit of the uncertain tax position to be recognized in
the financial statements. The exposure draft contains guidance with respect to the measurement of the benefit that is recognized for an uncertain tax position, when that benefit should be
derecognized, and other matters. The comment period for the exposure draft ended on September 12, 2005; the earliest the guidance would be implemented is December 31, 2005. EME is
currently assessing the potential impact of the proposed interpretation on its results of operations and financial condition.

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LIQUIDITY AND CAPITAL RESOURCES

Introduction

The following discussion of liquidity and capital resources is organized in the following sections:

PageEME's Liquidity

42Midwest Generation Financing

42Capital Expenditures

43EME's Historical Consolidated Cash Flow

43EME's Credit Ratings

44Margin, Collateral Deposits and Other Credit Support for Energy Contracts

45EME's Liquidity as a Holding Company

46Dividend Restrictions in Major Financings

47Contractual Obligations

48Off-Balance Sheet Transactions

49Environmental Matters and Regulations

49


For
a complete discussion of these issues, read this quarterly report in conjunction with EME's annual report on Form 10-K for the year ended December 31, 2004.

EME's Liquidity

At September 30, 2005, EME and its subsidiaries had cash and cash equivalents of $1.6 billion and EME had available the full amount of borrowing
capacity under a $98 million corporate credit facility. EME's consolidated debt at September 30, 2005 was $3.4 billion. In addition, EME's subsidiaries had $5.0 billion of
long-term lease obligations that are due over periods ranging up to 30 years.

Midwest Generation Financing

On April 18, 2005, Midwest Generation completed a refinancing of indebtedness. The refinancing was effected through the amendment and restatement of
Midwest Generation's existing credit facility, originally entered into April 27, 2004. The existing credit facility had provided for a $700 million first priority secured institutional
term loan due in 2011 and a $200 million first priority secured revolving credit, working capital facility due in 2009.

The
refinancing consisted of, among other things, a repricing of Midwest Generation's existing term loan and a new $300 million revolving credit, working capital facility due in
2011. The previously existing $200 million working capital facility remains in place. Midwest Generation drew in full upon the new $300 million working capital facility at closing and
used the proceeds to pay down an equivalent portion of the existing term loan. After giving effect to the paydown, the term loan carries a lower interest rate of LIBOR + 2%. The maturity
date of the repriced term loan remains 2011. The new working capital facility, together with the existing working capital facility, shares first lien priority with the repriced term loan. The new
working capital facility carries an interest rate of LIBOR + 2.25%. The maturity date of the new working capital facility is 2011; however, the lenders can request to be fully repaid in
2010.

On
the day after the closing of the refinancing transaction, EME contributed $300 million in equity to Midwest Generation, and Midwest Generation used the proceeds of this equity
contribution to repay the loans outstanding under the new working capital facility. Thus, after completion of the

42

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actions
outlined herein, Midwest Generation had $343 million outstanding under its term loan and $500 million of working capital facilities available for working capital requirements,
including credit support for hedging activities. As of September 30, 2005, approximately $170 million was utilized under these working capital facilities.

Under
the terms of Midwest Generation's credit agreement, Midwest Generation is permitted to distribute 75% of excess cash flow (as defined in the credit agreement). In addition, if
equity is contributed to Midwest Generation, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of distributions that Midwest Generation attributes to
the equity contribution equals the amount thereof. Accordingly, Midwest Generation is permitted to distribute 100% of excess cash flow until the aggregate portion of such distributions attributed to
the equity contribution made by EME in Midwest Generation on April 19, 2005 equals $300 million. However, Midwest Generation is required to make concurrently with each distribution an
offer to repay debt in an amount equal to the excess, if any, of one-third of such distribution over the portion thereof attributed to the equity contribution. Thus, Midwest Generation
will not be required to offer to repay debt concurrently with a distribution so long as the portion of each distribution attributed to the April 19, 2005 equity contribution is at least
one-third of such distribution.

Capital Expenditures

The estimated capital and construction expenditures of EME's subsidiaries are $14 million for the final quarter of 2005 and $63 million and
$49 million for 2006 and 2007, respectively. Non-environmental expenditures relate to upgrades to dust collection/mitigation systems and the coal handling system, ash removal
improvements and various other projects. EME plans to finance these expenditures with existing subsidiary credit agreements, cash on hand or cash generated from operations. Included in the estimated
expenditures are environmental expenditures of $4 million for the final quarter of 2005, $8 million for 2006 and $6 million for 2007. The environmental expenditures relate to
environmental projects such as selective catalytic reduction system improvements at the Homer City facilities.

EME's Historical Consolidated Cash Flow

Consolidated Cash Flows from Operating Activities

Cash used in operating activities decreased $619 million in the first nine months of 2005, compared to the first nine months of 2004. The
2005 decrease was primarily attributable to the $960 million lease termination payment in 2004 related to the Collins Station lease and tax-allocation payments received by EME from
Edison International of approximately $52 million during the first nine months of 2005, compared to approximately $43 million paid to Edison International during the first
nine months of 2004. For further discussion of the tax-allocation payments, see "EME's Liquidity as a Holding CompanyIntercompany
Tax-Allocation Agreement." Also contributing to the decrease were larger distributions from unconsolidated affiliates in 2005, primarily attributable to the Big 4 projects, and operating
income in 2005 versus an operating loss in 2004. Partially offsetting these decreases was $684 million in required margin and collateral deposits in 2005 for EME's price risk management and
trading activities, compared to $42 million in 2004. This increase in margin and collateral deposits resulted from an increase in forward market prices.

Consolidated Cash Flows from Financing Activities

Cash used in financing activities increased $1.6 billion in the first nine months of 2005, compared to the first nine months of 2004. The
2005 increase was primarily attributable to dividend payments

43

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made
to MEHC of $360 million during 2005, compared to $69 million during 2004. The increase was also due to the repayment of EME's junior subordinated debentures of $150 million
in January 2005 and a $302 million repayment in April 2005 related to Midwest Generation's existing term loan. Net borrowings in 2004 consisted of the $1 billion secured
notes and $700 million term loan facility received by Midwest Generation in April 2004 partially offset by the repayment of $693 million related to Edison Mission Midwest
Holdings' credit facility and $28 million related to the Coal and Capex facility in April 2004.

Consolidated Cash Flows from Investing Activities

Cash provided by investing activities decreased $593 million in the first nine months of 2005, compared to the first nine months of 2004. The 2005
decrease was primarily attributable to proceeds of $739 million received in 2004 from the sale of Contact Energy. Proceeds of $124 million received in 2005 from the sale of EME's 25%
investment in the Tri Energy project and EME's 50% investment in the CBK project were comparable to proceeds of $118 million received in 2004 from the sale of EME's stock of Edison Mission
Energy Oil & Gas and the sale of EME's 50% partnership interest in the
Brooklyn Navy Yard project. Partially offsetting the 2005 decrease were net sales of auction rate securities of $140 million in 2005, compared to $20 million in 2004.

EME's Credit Ratings

Overview

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

Moody's Rating

S&P RatingEME

B1

B+Midwest Generation, LLC:First priority senior secured rating

Ba3

BB-Second priority senior secured rating

B1

BEdison Mission Marketing & Trading

Not Rated

B+


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

EME
does not have any "rating triggers" contained in subsidiary financings that would result in EME being required to make equity contributions or provide additional financial support to
its subsidiaries.

The
credit ratings of EME are below investment grade and, accordingly, EME has historically provided collateral in the form of cash and letters of credit for the benefit of
counterparties for its price risk management and trading activities related to accounts payable and unrealized losses.

Credit Rating of Edison Mission Marketing & Trading

The Homer City sale-leaseback documents restrict EME Homer City Generation L.P.'s (EME Homer City's) ability to enter into trading activities, as
defined in the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City facilities if Edison Mission

44

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Marketing &
Trading does not have an investment grade credit rating from Standard & Poor's or Moody's or, in the absence of those ratings, if it is not rated as investment grade pursuant
to EME's internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party,
be investment grade. EME currently sells all the output from the Homer City facilities through Edison Mission Marketing & Trading, which has a below investment grade credit rating, and EME
Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback
owner participant to permit EME Homer City to sell directly into the market or through Edison Mission Marketing & Trading; or (2) Edison Mission Marketing & Trading must provide
assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow
EME Homer City to enter into such sales, under specified conditions, through December 31, 2006. EME Homer City continues to be in compliance with the terms of the consent; however, the consent
is revocable by the sale-leaseback owner participant at any time. The sale-leaseback owner participant has not indicated that it intends to revoke the consent; however, there
can be no assurance that it will not do so in the future. Revocation of the consent would not affect trades between Edison Mission Marketing & Trading and EME Homer City that had been entered
into while the consent was still in effect. EME is permitted to sell the output of the Homer City facilities into the spot market at any time. See "Market Risk ExposuresCommodity Price
RiskEnergy Price Risk Affecting Sales from the Homer City Facilities."

Margin, Collateral Deposits and Other Credit Support for Energy Contracts

In connection with entering into energy contracts (including forward contracts, transmission contracts and futures contracts), EME's subsidiary, Edison Mission
Marketing & Trading, has entered into agreements to support the risk of nonperformance. At September 30, 2005, Edison Mission Marketing & Trading had deposited $516 million
in cash with brokers in margin accounts in support of futures contracts and had deposited $210 million with counterparties in support of forward energy and transmission contracts. These margin
and collateral deposits are used in support of EME's price risk management and energy trading activities. The margin and collateral deposits generally earn interest at a rate that approximates the
Federal Funds Rate. In addition, EME has issued letters of credit of $6 million in support of commodity contracts at September 30, 2005.

Margin
and collateral deposits increased substantially during the third quarter of 2005 due to higher wholesale energy prices and increased megawatt hours hedged. Future cash collateral
requirements may be higher than the margin and collateral requirements at September 30, 2005, if wholesale energy prices increase further. Using the amount of energy contracts outstanding at
September 30, 2005, EME estimates that margin and collateral requirements could increase by approximately $300 million using a 95% confidence interval and an internal model estimate
using historical volatility.

Midwest
Generation has $500 million in credit facilities to support margin requirements specifically related to contracts entered into by Edison Mission Marketing & Trading
related to the Illinois Plants. At September 30, 2005, Midwest Generation has borrowed $165 million under these credit facilities to finance margin advances to Edison Mission
Marketing & Trading of $316 million. The balance of the margining advances by Midwest Generation was provided through cash on hand. In addition, EME has cash on hand and a
$98 million working capital facility to provide credit support to subsidiaries. See "EME's Liquidity" for further discussion.

45

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EME's Liquidity as a Holding Company

Overview

At September 30, 2005, EME had corporate cash and cash equivalents of $1.3 billion to meet liquidity needs. See "EME's Liquidity." EME
had no borrowings outstanding or letters of credit outstanding on the $98 million secured line of credit at September 30, 2005. Cash distributions from EME's subsidiaries and partnership
investments, and unused capacity under its corporate credit facility represent EME's major sources of liquidity to meet its cash requirements. The timing and amount of distributions from EME's
subsidiaries may be affected by many factors beyond its control. See "Dividend Restrictions in Major Financings."

EME's
secured corporate credit facility provides credit available in the form of cash advances or letters of credit. In addition to the interest payments, EME pays a commitment fee of
0.50% on the unutilized portion of the facility. EME has agreed to maintain a minimum interest coverage ratio and a minimum recourse debt to recourse capital ratio (as such ratios are defined in the
credit agreement). At September 30, 2005, EME met both these ratio tests.

As
security for its obligations under its new corporate credit facility, EME pledged its ownership interests in the holding companies through which it owns its interests in the Illinois
Plants, the Homer City facilities, the Westside projects and the Sunrise project. EME also granted a security interest in an account into which all distributions received by it from the Big 4 projects
will be deposited. EME is free to use these distributions unless and until an event of default occurs under its corporate credit facility.

At
September 30, 2005, EME also had available $88 million under Midwest Generation EME, LLC's $100 million letter of credit facility with Citibank, N.A., as Issuing
Bank, that expires in December 2006. Under the terms of this letter of credit facility, Midwest Generation EME is required to deposit cash in a bank account in order to cash collateralize any
letters of credit that may be outstanding under the facility. The bank account is pledged to the Issuing Bank. Midwest Generation EME owns 100% of Edison Mission Midwest Holdings, which in turn owns
100% of Midwest Generation, LLC.

46

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Historical Distributions Received By EME

The following table is presented as an aid in understanding the cash flow of EME's continuing operations and its various subsidiary holding companies which depend
on distributions from subsidiaries and affiliates to fund general and administrative costs and debt service costs of recourse debt.

|                                                      |                                                              | Nine Months Ended
September 30,
|----------------------------------------------------- | ------------------------------------------------------------ | -------------------------------
|
|
|Distributions from Consolidated Operating Projects:   |                                                              |                                
|                                                      | Edison Mission Midwest Holdings (Illinois Plants)(1)         |                                
|                                                      | EME Homer City Generation L.P. (Homer City facilities)(2)    |                                
|                                                      | Holding companies of other consolidated generating projects  |                                
|Distributions from Unconsolidated Operating Projects: |                                                              |                                
|                                                      | Edison Mission Energy Funding Corp. (Big 4 Projects)(3)      |                                
|                                                      | Sunrise Power Company                                        |                                
|                                                      | Holding company for Doga project                             |                                
|                                                      | Holding companies for Westside projects                      |                                
|                                                      | Holding companies of other unconsolidated operating projects |                                
|                                                      |                                                              |                                
|Total Distributions                                   |                                                              | $                              
|                                                      |                                                              |                                

---

Intercompany Tax-Allocation Agreement

EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to participate in
tax-allocation payments with other subsidiaries of Edison International in circumstances where domestic tax losses are incurred. The right of EME to receive and the amount and timing of
tax-allocation payments is dependent on the inclusion of EME in the consolidated income tax returns of Edison International and its subsidiaries and other factors, including the
consolidated taxable income of Edison International and its subsidiaries, the amount of net operating losses and other tax items of EME, its subsidiaries, and other subsidiaries of Edison
International and specific procedures regarding allocation of state taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison
International group generates sufficient taxable income in order to be able to utilize EME's tax losses in the consolidated income tax returns for Edison International and its subsidiaries. Based on
the application of the factors cited above, EME is obligated during periods it generates taxable income to make payments under the tax-allocation agreements.

Dividend Restrictions in Major Financings

General

Each of EME's direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME's subsidiaries
are not available to satisfy EME's

47

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obligations
or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of
financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies.

Key Ratios of EME's Principal Subsidiaries Affecting Dividends

Set forth below are key ratios of EME's principal subsidiaries required by financing arrangements for the twelve months ended September 30, 2005:

|Subsidiary                                             |  | Financial Ratio                    |  | Covenant                           |  | Actual   
|------------------------------------------------------ |  | ---------------------------------- |  | ---------------------------------- |  | ---------
|Midwest Generation, LLC (Illinois Plants)              |  | Interest Coverage Ratio            |  | Greater than or equal to 1.25 to 1 |  | 2.35 to 1
|Midwest Generation, LLC (Illinois Plants)              |  | Secured Leverage Ratio             |  | Less than or equal to 8.75 to 1    |  | 3.06 to 1
|EME Homer City Generation L.P. (Homer City facilities) |  | Senior Rent Service Coverage Ratio |  | Greater than 1.7 to 1              |  | 3.03 to 1
|Edison Mission Energy Funding Corp. (Big 4 Projects)   |  | Debt Service Coverage Ratio        |  | Greater than or equal to 1.25 to 1 |  | 3.14 to 1

For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make
distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "Dividend Restrictions in Major Financings" on page 65 of EME's annual report on
Form 10-K for the year ended December 31, 2004.

Contractual Obligations

Fuel Supply Contracts

Midwest Generation and EME Homer City have entered into additional fuel purchase commitments with various third-party suppliers during the first
nine months of 2005. These additional commitments are currently estimated to be $22 million for 2005, $114 million for 2006, $169 million for 2007, $44 million for
2008, and $62 million for 2009.

Coal Transportation Agreements

Midwest Generation has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various
delivering carriers) which extend through 2011. Midwest Generation commitments under this agreement are based on actual coal purchases from the Powder River Basin. Accordingly, contractual obligations
for transportation are based on coal volumes set forth in fuel supply contracts. The increase in transportation commitments entered into during the first nine months of 2005 relates to
additional volumes of fuel purchases using the terms of existing transportation agreements. These commitments are currently estimated to be $33 million for 2005, $61 million for 2006,
$117 million for 2007, $40 million for 2008, and $77 million for 2009.

48

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Fuel Supply Dispute

Beginning in 2004, EME Homer City experienced interruptions of supply under two agreements with Unionvale Coal Company and Genesis, Inc. Unionvale and
Genesis claimed that alleged geologic conditions at the Genesis No. 17 Mine in Pennsylvania, which is one source of coal under these multi-source coal contracts, constituted force majeure and
excused contract performance. These two agreements together provide for the delivery to EME Homer City of approximately 20% of EME Homer City's clean coal requirements in 2005 and 2006, and
approximately 10% in 2007. Claims arising from these matters have been resolved in a confidential settlement, and the lawsuit has been dismissed.
EME Homer City has awarded contracts to alternate suppliers, and adjusted its inventory strategies to reflect and offset the delivery shortfall for 2005.

Off-Balance Sheet Transactions

For a discussion of EME's off-balance sheet transactions, refer to "Off-Balance Sheet Transactions" on page 74 of EME's annual
report on Form 10-K for the year ended December 31, 2004. There have been no significant developments with respect to EME's off-balance sheet transactions that
affect disclosures presented in EME's annual report.

Environmental Matters and Regulations

For a discussion of EME's environmental matters, refer to "Environmental Matters and Regulations" on page 77 of EME's annual report on
Form 10-K for the year ended December 31, 2004 and the notes to the Consolidated Financial Statements set forth therein. There have been no significant developments with
respect to environmental matters specifically affecting EME since the filing of EME's annual report, except as follows:

On
May 12, 2005, the Clean Air Interstate Rule (CAIR) was published in the Federal Register. The CAIR requires 28 eastern states and the District of Columbia to address
ozone attainment issues by reducing regional NOx and SO2 emissions. The CAIR reduces the current SO2 (i.e., Clean Air Act Title IV Phase II) emissions allowance cap in 2010 and 2015 by
50% and 65%, respectively. Regional NOx emissions are required to be reduced in 2009 and 2015 by 53% and 61%, respectively, from 2003 levels. The CAIR has been challenged in court by state,
environmental and industry groups, which may result in changes to the substance of the rule and to the timetables for implementation. EME is reviewing the impact of the rule on its business plan.
Given the uncertainty of the requirements that will need to be implemented and the options available to meet the NOx and SO2 reductions fleetwide, EME at this time cannot accurately estimate the cost
to meet these obligations.

The
Clean Air Mercury Rule (CAMR), published in the Federal Register on May 18, 2005, creates a market-based cap-and-trade program that will reduce
nationwide utility emissions of mercury in two distinct phases. In the first phase of the program, which will come into effect in 2010, the annual nationwide cap is 38 tons and emissions will be
reduced primarily by taking advantage of "co-benefit" reductions; that is, mercury reductions achieved by reducing sulfur dioxide and nitrogen oxides emissions under the CAIR. In the
second phase, due in 2018, coal-fired power plants will be subject to a second annual cap, which will reduce emissions nationwide to 15 tons upon full implementation. States may join the
trading program by adopting the CAMR model trading rule in state regulations, or they may adopt regulations that mirror the necessary components of the model trading rule. States are not required to
adopt a cap-and-trade program and may promulgate alternative regulations, such as command and control regulations, that are equivalent to or more stringent than the CAMR's
suggested cap-and-trade program. Any program adopted by a state must be approved by the US EPA.

49

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Contemporaneous
with the adoption of the CAMR, the US EPA rescinded its previous finding that mercury emissions from coal-fired electric generating units were required to be
regulated pursuant to Section 112 of the federal Clean Air Act. Litigation has already been filed challenging the US EPA's rescission action and claiming that the agency should have imposed
technology-based limitations on mercury emissions instead of adopting a market-based program. Litigation was also filed to challenge the CAMR following its publication in the Federal Register. As a
result of these challenges, the CAMR rules may change in terms of substance and timetables.

To
the extent that Illinois and Pennsylvania implement US EPA's CAMR by adopting a cap-and-trade program for achieving reductions in mercury emissions, then EME
may have the option to purchase mercury emission allowances, to install control equipment (or otherwise to alter operations so as to reduce mercury emissions), or some combination thereof. If EME were
to implement environmental control technology at its Homer City facilities instead of purchasing allowances to comply with the CAMR and other Clean Air Act developments described in "Environmental
Matters and RegulationsFederalUnited States of America" on page 79 of EME's annual report on Form 10-K for the year ended December 31, 2004,
it currently estimates capital expenditures for such improvements to be approximately $350 million to $400 million in the 2006-2010 timeframe. However, because the mercury
state implementation plans are not due until October 31, 2006 and such plans may not adopt the CAMR's cap-and-trade program, and because EME cannot predict the outcome
of the legal challenge to the CAMR and the US EPA's decision not to regulate mercury emissions pursuant to Section 112 of the federal Clean Air Act, the full impact of this regulation currently
cannot be assessed. EME's approach to meeting these obligations will continue to be based upon an ongoing assessment of the federal requirements and market conditions.

50

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MARKET RISK EXPOSURES

Introduction

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

This
section discusses these market risk exposures under the following headings:

PageCommodity Price Risk

51Credit Risk

58Interest Rate Risk

59Fair Value of Financial Instruments

60Regulatory Matters

61


For a complete discussion of these issues, read this quarterly report in conjunction with EME's annual report on Form 10-K for
the year ended December 31, 2004.

Commodity Price Risk

General Overview

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



51

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A
discussion of commodity price risk for the Illinois Plants and Homer City facilities is set forth below.

Energy Price RiskIntroduction

Electric power generated at EME's merchant plants is generally sold into the PJM market.

EME's
merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity
price risks are actively monitored by a risk management committee to ensure compliance with EME's risk management policies. Policies are in place which define risk tolerance, and procedures exist
which allow for monitoring of all commitments and positions with regular reviews by EME's risk management committee. Despite this, there can be no assurance that all risks have been accurately
identified, measured and/or mitigated.

In
addition to the prevailing market prices, EME's ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply
with environmental regulations. The costs of production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to
vary from unit to unit.

EME
uses a "value at risk" analysis in its daily business to identify, measure, monitor and control its overall market risk exposure in respect of its Illinois Plants, its Homer City
facilities, and its trading positions. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk
measures the possible loss over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk
measurement tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop loss limits and counterparty credit
exposure limits.

Hedging Strategy

To reduce its exposure to market risk, EME hedges a portion of its merchant portfolio risk through Edison Mission Marketing & Trading. To the extent that
EME does not hedge its merchant portfolio, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through the use
of contracts cleared on the Intercontinental Trading Exchange and the New York Mercantile Exchange. Hedge transactions are also entered into as forward sales to utilities and power marketing
companies.

The
extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether sales at
forward market prices are sufficiently attractive compared to assuming the risk associated with spot market sales. Second, EME's ability to enter into hedging transactions depends upon its, Midwest
Generation's and Edison Mission Marketing & Trading's credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging
transactions.

In
the case of hedging transactions related to the generation and capacity of the Illinois Plants, Midwest Generation is permitted to use its working capital facility and cash on hand to
provide credit support for such hedging transactions entered into by Edison Mission Marketing & Trading under an energy services agreement between Midwest Generation and Edison Mission
Marketing & Trading. Utilization of this credit facility in support of such hedging transactions is expected to provide

52

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additional
liquidity support for implementation of EME's contracting strategy for the Illinois Plants. In the case of hedging transactions related to the generation and capacity of the Homer City
facilities, credit support is provided by EME pursuant to intercompany arrangements between it and Edison Mission Marketing & Trading. See "Credit Risk," below.

Energy Price Risk Affecting Sales from the Illinois Plants

Pre-2005 Merchant Sales

Energy generated at the Illinois Plants was historically sold under three power purchase agreements between Midwest Generation and Exelon Generation Company,
under which Exelon Generation was obligated to make capacity payments for the plants under contract and energy payments for the energy produced by these plants and taken by Exelon Generation. The
power purchase agreements began on December 15, 1999. The capacity payments provided the units under contract with revenue for fixed charges, and the energy payments compensated those units for
all, or a portion of, variable costs of production. The three power purchase agreements with Exelon Generation had all been terminated by December 31, 2004.

To
the extent that energy and capacity from the Illinois Plants was not sold under the power purchase agreements with Exelon Generation, it was sold on a wholesale basis through a
combination of bilateral agreements, forward energy sales and spot market sales. Approximately 43% of the energy and capacity sales from the Illinois Plants in the first nine months of 2004
were made on a wholesale basis outside of the power purchase agreements.

Prior
to May 1, 2004, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois Plants were direct "wholesale customers" and broker
arranged "over-the-counter customers." Effective May 1, 2004, the transmission system of Commonwealth Edison was placed under the control of PJM as the Northern Illinois
control area, and on October 1, 2004, the transmission system of AEP was integrated into PJM, which linked
eastern PJM and the Northern Illinois control areas of the PJM system and improved access from the Illinois Plants into the broader PJM market. Further, on April 1, 2005, the Midwest
Independent Transmission System Operator (MISO) commenced operation, linking the MISO footprint, including Illinois, Wisconsin, Indiana, Michigan, and Ohio, in a locational marginal pricing system
similar to that of PJM.

Since
the initial expansion of PJM, Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing and is no longer required to arrange and pay
separately for transmission when making sales to wholesale buyers within the PJM system. Hedging transactions related to the generation of the Illinois units are entered into at the Northern Illinois
Hub in PJM, the AEP/Dayton Hub in PJM and, with the advent of MISO, at the Cinergy Hub in MISO. Because of proximity, the Midwest Generation assets are primarily hedged with transactions at the
Northern Illinois Hub, but from time to time may be hedged in limited amounts at the AEP/Dayton Hub and the Cinergy Hub. These trading hubs have been the most liquid locations for these hedging
purposes. However, hedging transactions which settle at points other than the Northern Illinois Hub are subject to the possibility of basis risk. See "Basis Risk" below for further
discussion.

Following
the expansion of the PJM system described above, sales into the expanded PJM, the primary market currently available to the Illinois Plants, replaced sales previously made as
bilateral sales and spot sales "Into ComEd" and "Into AEP." See "Regulatory Matters" in EME's annual report on Form 10-K for the year ended December 31, 2004 for a more
detailed discussion of developments regarding Commonwealth Edison's joining PJM, and "Basis Risk" below for a discussion of locational marginal pricing.

53

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2005 Merchant Sales

During 2005, electric power generated at the Illinois Plants has generally been sold into the PJM market. The PJM pool has a short-term market, which
establishes an hourly clearing price. The Illinois Plants are situated in the new expanded western PJM control area and are physically connected to high-voltage transmission lines serving
this market.

The
following table depicts the average historical market prices for energy per megawatt-hour during the first nine months of 2005 and 2004.

2005(1)

2004January

$
38.36

$
27.88
(2)February


34.92


29.98
(2)March


45.75


30.66
(2)April


38.98


27.88
(2)May


33.60


34.05
(1)June


42.45


28.58
(1)July


50.87


30.92
(1)August


60.09


26.31
(1)September


53.30


27.98
(1)Nine-Month Average

$
44.26

$
29.36


---

Forward market prices at the Northern Illinois Hub fluctuate as a result of a number of factors, including natural gas prices, transmission
congestion, changes in market rules, electricity demand which is affected by weather and economic growth, plant outages in the region, and the amount of existing and planned power plant capacity. The
actual spot prices for electricity delivered by the Illinois Plants into these markets may vary materially from the forward market prices set forth in the table below.

The
following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at September 30, 2005:

24-Hour
Northern Illinois Hub
Forward Energy Prices*2005October

$
47.40November


49.98December


55.852006 Calendar "strip"(1)

$
52.742007 Calendar "strip"(1)

$
47.61


---

54

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The following table summarizes Midwest Generation's hedge position (primarily based on prices at the Northern Illinois Hub) at
September 30, 2005:

2005

2006

2007Megawatt hours


4,835,118


14,193,014


6,804,000Average price/MWh(1)

$
35.34

$
43.02

$
42.24


---

Energy Price Risk Affecting Sales from the Homer City Facilities

Electric power generated at the Homer City facilities is generally sold into the PJM market. The PJM pool has short-term markets, which establish an
hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and New York
Independent System Operator (NYISO) markets.

The
following table depicts the average historical market prices for energy per megawatt-hour in PJM during the first nine months of 2005 and 2004:

Historical Energy Prices*
24-Hour PJMHomer City

West Hub2005

2004

2005

2004January

$
45.82

$
51.12

$
49.53

$
55.01February


39.40


47.19


42.05


44.22March


47.42


39.54


49.97


39.21April


44.27


43.01


44.55


42.81May


43.67


44.68


43.64


48.04June


46.63


36.72


53.72


38.05July


54.63


40.09


66.34


43.64August


66.39


34.76


82.83


38.59September


66.67


40.62


76.82


41.96Nine-Month Average

$
50.54

$
41.97

$
56.61

$
43.50


---

Forward market prices at the PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion,
changes in market rules, electricity demand which is affected by weather and economic growth, plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot
prices for electricity delivered by the Homer City facilities into these markets may vary materially from the forward market prices set forth in the table below.

55

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The
following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at September 30, 2005:

24-Hour PJM West Hub
Forward Energy Prices*2005October

$
69.90November


74.49December


80.802006 Calendar "strip"(1)

$
72.012007 Calendar "strip"(1)

$
62.18


---

The following table summarizes Homer City's hedge position at September 30, 2005:

2005

2006

2007Megawatt hours


2,215,125


8,525,200


3,618,000Average price/MWh(1)

$
43.14

$
53.24

$
60.68


---

The average price/MWh for Homer City's hedge position is based on PJM West Hub. Energy prices at the Homer City busbar have been lower than energy
prices at the PJM West Hub. See "Basis Risk" below for a discussion of the difference.

Basis Risk

Sales made from the Illinois Plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices at
the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts
as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, there is not a liquid market for entering into these contracts at the individual plant
busbars. A liquid market does exist for a settlement point known as the PJM West Hub in the case of Homer City and for a settlement point known as the Northern Illinois Hub in the case of the Illinois
Plants. EME's price risk management activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. EME's revenues with respect to such
forward contracts include:



56

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Under
the PJM market design, locational marginal pricing (sometimes referred to as LMP), which establishes hourly prices at specific locations throughout PJM by considering factors
including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be raised or lowered relative to other locations depending on how
the point is affected by transmission constraints. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement
point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to by EME as "basis risk." During the past 12 months,
transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub (the primary trading hub in PJM for the Homer City facilities) by an average
of 9%. The monthly average difference during this period ranged from zero to 20%, which occurred in August 2005. For comparison, the same difference during 2004 was 4%. By contrast to the Homer
City facilities, during the past 12 months, transmission congestion in PJM has not resulted in prices at the Northern Illinois Hub being significantly different from those at the individual
busbars of the Illinois Plants.

By
entering into cash settled futures contracts and forward contracts using the PJM West Hub and the Northern Illinois Hub (or other similar trading hubs) as the settlement points, EME
is exposed to basis risk as described above. In order to mitigate basis risk, EME has participated in purchasing financial transmission rights in PJM, and may continue to do so in the future. A
financial transmission right is a financial instrument that entitles the holder thereof to receive actual spot prices at one point of delivery and pay prices at another point of delivery that are
pegged to prices at the first point of delivery, plus or minus a fixed amount. Accordingly, EME's price risk management activities include using financial transmission rights alone or in combination
with forward contracts to manage basis risk.

Coal Price and Transportation Risk

The Illinois Plants use approximately 18 million to 20 million tons of coal annually, primarily obtained from the Southern Powder River Basin of
Wyoming. In addition, the Homer City facilities use approximately 5 million tons of coal annually, obtained from mines located near the facilities in Pennsylvania. Coal purchases are made under
a variety of supply agreements typically ranging from one year to six years in length. The following table summarizes the percent of expected coal requirements for the next five years
that are under contract at September 30, 2005.

Percent of Coal Requirements
Under Contract2005(1)

2006

2007

2008

2009Illinois Plants

111%

100%

91%

32%

32%Homer City facilities(2)

101%

78%

78%

21%

15%


---

EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachia coal, which is purchased for the
Homer City facilities, increased considerably since 2004. In January 2004, prices of Northern Appalachia coal (with 13,000 British Thermal units (Btu) content and <3.0 SO2 MMBtu
content) were below $40 per ton and increased to more than $60 per ton during 2004. On September 30, 2005, the Energy Information Administration reported the price of Northern Appalachia coal
at $54.00 per ton. The overall increase in the Northern Appalachia coal price has been largely attributed to greater demand from domestic power producers and increased international

57

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shipments
of coal to Asia. Prices of Powder River Basin (PRB) coal (with 8,800 Btu content and 0.8 SO2 MMBtu content), which is purchased for the Illinois Plants, have recently increased due to
curtailment of coal shipments for the remainder of 2005 due to increased PRB coal demand from the other regions (east), rail constraints (discussed below) and higher prices for SO2 allowances. On
September 30, 2005, the Energy Information Administration reported the price of $12.79 per ton, which compares to 2004 prices generally below $7 per ton.

During
the first nine months of 2005, the rail lines that bring coal from the PRB to EME's Illinois Plants were damaged from derailments caused by heavy rains. The railroads are
in the process of making repairs to these rail lines and have advised their customers, including EME, that shipments will be curtailed by 15% to 20% during 2005. Through September 30, 2005, EME
received approximately 87% of expected shipments and expects to receive shipments of approximately 80% to 85% during the fourth quarter of 2005. Rail maintenance will continue as long as weather
permits. EME continues to work with its transportation provider to minimize any disruption of planned shipments. Based on communication with the transportation provider, EME expects to continue
receiving a sufficient amount of coal to generate power at historical levels while these repairs are being completed.

Emission Allowances Price Risk

Under the federal Acid Rain Program (which requires electric generating stations to hold sulfur dioxide allowances) and Illinois and Pennsylvania regulations
implementing the federal NOx SIP Call requirement, EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated
under these programs. As part of the acquisition of the Illinois Plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been or are allocated to these
plants.

The
price of emission allowances, particularly SO2 allowances issued through the US EPA Acid Rain Program, increased substantially during 2004 and the first nine months of 2005.
The average price of purchased SO2 allowances increased to $765 per ton during the nine months ended September 30, 2005 from $281 per ton during the nine months ended
September 30, 2004. The increase in the price of SO2 allowances has been attributed to reduced numbers of both allowance sellers and prior vintage allowances.

See
"Liquidity and Capital ResourcesEnvironmental Matters and Regulations" for a discussion of environmental regulations related to emissions.

Credit Risk

In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies, financial institutions, and other
companies, collectively referred to as counterparties. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss associated with
re-contracting the product at a price different from the original contracted price if the non-performing counterparty were unable to pay the resulting liquidated damages owed
to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products delivered prior to the time such counterparty defaulted.

To
manage credit risk, EME looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform
pursuant to the terms of their contractual obligations. EME measures, monitors and mitigates, to the extent possible, credit risk. To mitigate counterparty risk, master netting agreements are used
whenever possible and counterparties may be required to pledge collateral when deemed necessary. EME also takes other

58

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appropriate
steps to limit or lower credit exposure. Processes have also been established to determine and monitor the creditworthiness of counterparties. EME manages the credit risk on the portfolio
based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the
process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. A risk management committee regularly reviews the credit quality of EME's
counterparties. Despite this, there can be no assurance that these efforts will be wholly successful in mitigating credit risk or that collateral pledged will be adequate.

EME
measures credit risk exposure from counterparties of its merchant energy activities as either: (i) the sum of 60 days of accounts receivable, current fair value of open
positions, and a credit value at risk, or (ii) the sum of delivered and unpaid accounts receivable and the current fair value of open positions. EME's subsidiaries enter into master agreements
and other arrangements in conducting price risk management and trading activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. Accordingly,
EME's credit risk exposure from counterparties is based on net exposure under these agreements. At September 30, 2005, the amount of exposure, broken down by the credit ratings of EME's
counterparties, was as follows:

S&P Credit Rating

September 30, 2005(in millions)A or higher

$
2A-


148BBB+


64BBB


3BBB-


1Below investment grade


Total

$
218


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

In
addition, coal for the Illinois Plants and the Homer City facilities is purchased from suppliers under contracts which may be for multiple years. A number of the coal suppliers
to the Illinois Plants and the Homer City facilities do not currently have an investment grade credit rating and, accordingly, EME may have limited recourse to collect damages from a supplier in the
event of default. EME seeks to mitigate this risk through diversification of its coal suppliers and through guarantees and other collateral arrangements when available. Despite this, there can be no
assurance that these efforts will be successful in mitigating credit risk from coal suppliers.

For
the nine months ended September 30, 2004, one customer accounted for 14% and a second customer, Exelon Generation, accounted for 40% of EME's consolidated operating
revenues. For more information on Exelon Generation, see "Commodity Price RiskEnergy Price Risk Affecting Sales from the Illinois PlantsPre-2005 Merchant Sales."

Interest Rate Risk

Interest rate changes affect the cost of capital needed to operate EME's projects. EME mitigates the risk of interest rate fluctuations by arranging for fixed
rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. The fair market values of
long-term fixed interest rate obligations are subject to interest rate risk. The fair market value of EME's total long-term obligations (including current portion) was
$3.8 billion at September 30, 2005, compared to the carrying value of $3.4 billion.

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Fair Value of Financial Instruments

Non-Trading Derivative Financial Instruments

The following table summarizes the fair values for outstanding derivative financial instruments used in EME's continuing operations for purposes other than
trading by risk category (in millions):

September 30,
2005

December 31,
2004Commodity price:Electricity

$
(582
)
$
10


In assessing the fair value of EME's non-trading derivative financial instruments, EME uses a variety of methods and assumptions based
on the market conditions and associated risks existing at each balance sheet date. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility
of the underlying commodities and other factors. The following table summarizes the maturities, the valuation method and the related fair value of EME's commodity price risk management assets and
liabilities as of September 30, 2005 (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 yearsPrices actively quoted

$
(582
)
$
(501
)
$
(81
)
$


$



Energy Trading Derivative Financial Instruments

The fair value of the commodity financial instruments related to energy trading activities as of September 30, 2005 and December 31, 2004, are set
forth below (in millions):

September 30, 2005

December 31, 2004Assets

Liabilities

Assets

LiabilitiesElectricity

$
186

$
79

$
125

$
36


The change in the fair value of trading contracts for the nine months ended September 30, 2005, was as follows (in millions):

Fair value of trading contracts at January 1, 2005

$
89Net gains from energy trading activities


130Amount realized from energy trading activities


(130
)Other changes in fair value


18Fair value of trading contracts at September 30, 2005

$
107


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

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following
table summarizes the maturities, the valuation method and the related fair value of energy trading assets and liabilities (as of September 30, 2005) (in millions):

Total Fair
Value

Maturity
<1 year

Maturity
1 to 3
years

Maturity
4 to 5
years

Maturity
>5 yearsPrices actively quoted

$
18

$
18

$


$


$
Prices based on models and other valuation methods


89


2


9


7


71Total

$
107

$
20

$
9

$
7

$
71


Regulatory Matters

For a discussion of EME's regulatory matters, refer to "Overview of Domestic FacilitiesIllinois Power Markets" on page 5 of EME's annual
report on Form 10-K for the year ended December 31, 2004 and "Regulatory Matters" on page 16 of EME's annual report on Form 10-K for the year ended
December 31, 2004. There have been no significant developments with respect to regulatory matters specifically affecting EME since the filing of EME's annual report, except as follows:

Opening of MISO Market

The MISO's day-ahead and real-time locational marginal pricing markets commenced operation on April 1, 2005. Since that time, the
wholesale electricity trading community has opted to trade a product delivered at the Cinergy Hub as defined by MISO rather than at the "Into Cinergy" location that was used previously. EME
anticipates that the opening of the MISO market will lead to increased liquidity in the Midwest electricity markets because locational marginal pricing provides a liquid and credible cash index
against which the trading community can settle contracts.

Passage of Comprehensive Energy Legislation by Congress

A comprehensive energy bill was passed by the House and Senate in July 2005 and was signed into law by the President on August 8, 2005. Known as
"EPAct 2005," this comprehensive legislation includes provisions for the repeal of the Public Utility Holding Company Act (PUHCA), for amendments to the Public Utility Regulatory Policies Act of 1978
(PURPA), for the introduction of new regulations regarding "Transmission Operation Improvements," for Transmission Rate Reform, for incentives for various generation technologies and for the extension
through December 31, 2007 of production tax credits for wind and other specified types of generation. A number of these provisions will require implementing regulations to be promulgated by the
Federal Energy Regulatory Commission (FERC). EME is currently assessing the potential impact of this legislation and the likely regulations.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For a discussion of market risk sensitive instruments, refer to "Market Risk Exposures" on page 86 of EME's annual report on Form 10-K
for the year ended December 31, 2004. Refer to "Market Risk Exposures" in Item 2 of this report for an update to that disclosure.

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ITEM 4.    CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

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

Internal Control Over Financial Reporting

There were no changes in EME's internal control over financial reporting (as that term is defined in Rules 13a-15(f) or
15d-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, EME's internal
control over financial reporting.

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PART II  OTHER INFORMATION

ITEM 1.    LEGAL PROCEEDINGS

For
a discussion of EME's legal proceedings, refer to "Legal Proceedings" on page 23 of EME's annual report on Form 10-K for the year ended December 31, 2004.
There have been no significant developments with respect to EME's legal proceedings specifically affecting EME since the filing of EME's annual report, except as follows:

Legal Developments Affecting Sunrise Power Company

Sunrise Power Company, in which EME's wholly owned subsidiary owns a 50% interest, sells all its output to the California Department of Water Resources. On
May 15, 2002, Sunrise Power Company was served with a complaint filed in the Superior Court of the State of California, City and County of San Francisco, by James M. Millar, "individually, and
on behalf of the general public and as a representative taxpayer suit" against sellers of long-term power to the California Department of Water Resources, including Sunrise Power Company.
The lawsuit alleges that the defendants, including Sunrise Power Company, engaged in unfair and fraudulent business practices by knowingly taking advantage of a manipulated power market to obtain
unfair contract terms. The lawsuit seeks to enjoin enforcement of the "unfair and oppressive terms and conditions" in the contracts, as well as restitution by the defendants of excessive monies
obtained by the defendants. Plaintiffs in several other class action lawsuits pending in Northern California have filed petitions seeking to have the Millar lawsuit consolidated with those lawsuits.
In December 2003, James Millar filed a First Amended Class Action and Representative Action Complaint which contains allegations similar to those in the earlier complaint but also
alleges a class action. One of the newly added parties
removed the lawsuit to federal court, and the court ordered remand to the San Francisco Superior Court. Defendants filed a responding pleading on May 6, 2005. Following a hearing on
September 7, 2005, the court sustained defendants' demurrer regarding preemption and filed rate doctrine. The plaintiff has waived his right to appeal.

ITEM 6.    EXHIBITS

|Exhibit No. |  | Description                                                                                    
|----------- |  | -----------------------------------------------------------------------------------------------
|31.1        |  | Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
|31.2        |  | Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act.
|32          |  | Statement Pursuant to 18 U.S.C. Section 1350.                                                  

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SIGNATURES

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

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

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