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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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



For the quarterly period ended September 30, 2004



| ̈ | 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: 000-29311



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DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)



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|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Delaware                                                       |  | 94-3248415                          
|(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)



1000 Louisiana,
Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)



(713) 507-6400

(Registrants telephone number, including area code)



---



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



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



All of the registrants outstanding stock is owned, directly or indirectly by Dynegy Inc.



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DYNEGY HOLDINGS INC.



TABLE OF
CONTENTS



|                                                                                                                            |  |                                                                                       |  |     
|--------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------------------------------------------------------- |  | ----
|                                                                                                                            |  |                                                                                       |  | Page
|PART I. FINANCIAL INFORMATION                                                                                               |  |                                                                                      
|                                                                                                                            |  |                                                                                      
|Item 1.                                                                                                                     |  | CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:                                          |  |     
|                                                                                                                            | 
|Condensed Consolidated Balance Sheets:    September 30, 2004 and December 31, 2003                                          |  | 4                                                                                    
|Condensed Consolidated Statements of Operations:    For the three and nine months ended September 30, 2004 and 2003         |  | 5                                                                                    
|Condensed Consolidated Statements of Cash Flows:    For the nine months ended September 30, 2004 and 2003                   |  | 6                                                                                    
|Condensed Consolidated Statements of Comprehensive Loss:    For the three and nine months ended September 30, 2004 and 2003 |  | 7                                                                                    
|Notes to Condensed Consolidated Financial Statements                                                                        |  | 8                                                                                    
|                                                                                                                            |  |                                                                                      
|Item 2.                                                                                                                     |  | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  | 42  
|Item 3.                                                                                                                     |  | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                            |  | 73  
|Item 4.                                                                                                                     |  | CONTROLS AND PROCEDURES                                                               |  | 74  
|                                                                                                                            | 
|PART II. OTHER INFORMATION                                                                                                  |  |                                                                                      
|                                                                                                                            |  |                                                                                      
|Item 1.                                                                                                                     |  | LEGAL PROCEEDINGS                                                                     |  | 76  
|Item 6.                                                                                                                     |  | EXHIBITS                                                                              |  | 76  



Explanatory Note



On September 23, 2004, we filed a Current Report on Form
8-K with the SEC announcing restatements of our previously issued financial statements contained in our 2003 Form 10-K and first and second quarter 2004 Form 10-Qs. The restatements relate to our deferred income tax accounts. As a result of our
inability to complete our review of our deferred income tax accounts prior to the filing of this report, the financial statements accompanying this report do not reflect the effects of this item and have not been reviewed by an independent public
accountant under Rule 10-01(d) of Regulation S-X. We expect that our independent public accountant, PricewaterhouseCoopers LLP, will complete the quarterly review required by Rule 10-01(d) of Regulation S-X following the issuance of restated
financial statements contained in our third quarter 2004 Form 10-Q.



Also as a result of our inability to complete our deferred income tax account review and reflect its effects in our financial statements, this report is not accompanied by the certifications required by Sections 302 and 906 of the
Sarbanes-Oxley Act of 2002 and Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934, as amended. As soon as practicable following the date of this report, we expect to file an amendment to this report which includes these certifications, as
well as amendments to our 2003 Form 10-K and first and second quarter 2004 Form 10-Qs.



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DEFINITIONS



As used in this Form 10-Q, the abbreviations listed below have the following meanings:



|               |  |                                                                                                                                                                 
|-------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------
|ARO            |  | Asset retirement obligation                                                                                                                                     
|Bbtu/d         |  | Billions of British thermal units per day                                                                                                                       
|Cal ISO        |  | The California Independent System Operator                                                                                                                      
|Cal PX         |  | The California Power Exchange                                                                                                                                   
|CDWR           |  | California Department of Water Resources                                                                                                                        
|CFTC           |  | Commodity Futures Trading Commission                                                                                                                            
|CPUC           |  | California Public Utilities Commission                                                                                                                          
|CRM            |  | Our customer risk management business segment                                                                                                                   
|$/Bbl          |  | Dollars per barrel                                                                                                                                              
|$/Gal          |  | Dollars per gallon                                                                                                                                              
|DMG            |  | Dynegy Midwest Generation, Inc.                                                                                                                                 
|DMS            |  | Dynegy Midstream Services                                                                                                                                       
|DPM            |  | Dynegy Power Marketing Inc.                                                                                                                                     
|Dynegy         |  | Dynegy Inc., our parent company, together with its subsidiaries                                                                                                 
|EITF           |  | Emerging Issues Task Force                                                                                                                                      
|EPA            |  | Environmental Protection Agency                                                                                                                                 
|ERCOT          |  | Electric Reliability Council of Texas, Inc.                                                                                                                     
|ERISA          |  | The Employee Retirement Income Security Act of 1974, as amended                                                                                                 
|FASB           |  | Financial Accounting Standards Board                                                                                                                            
|FERC           |  | Federal Energy Regulatory Commission                                                                                                                            
|FIN            |  | FASB Interpretation                                                                                                                                             
|Form 8-K       |  | Our Current Report on Form 8-K filed on September 23, 2004                                                                                                      
|Form 10-K      |  | Our Annual Report on Form 10-K for the year ended December 31, 2003, filed on March 5, 2004, as amended by Amendment No. 1 on Form 10-K/A filed on July 20, 2004
|GAAP           |  | Accounting principles generally accepted in the United States of America                                                                                        
|GEN            |  | Our power generation business segment                                                                                                                           
|ICC            |  | Illinois Commerce Commission                                                                                                                                    
|Illinois Power |  | Illinois Power Company                                                                                                                                          
|kW-yr          |  | Kilowatts per year                                                                                                                                              
|LIBOR          |  | The London Interbank Offered Rate                                                                                                                               
|LNG            |  | Liquefied natural gas                                                                                                                                           
|MBbls/d        |  | Thousands of barrels per day                                                                                                                                    
|MMBtu          |  | Millions of British thermal units                                                                                                                               
|MMCFD          |  | Million cubic feet per day                                                                                                                                      
|MW             |  | Megawatt                                                                                                                                                        
|MWh            |  | Megawatt hour                                                                                                                                                   
|NGL            |  | Our natural gas liquids business segment                                                                                                                        
|NOV            |  | Notice of Violation                                                                                                                                             
|NSPS           |  | New Source Performance Standard                                                                                                                                 
|PRB            |  | Powder River Basin                                                                                                                                              
|PSD            |  | Prevention of Significant Deterioration                                                                                                                         
|SEC            |  | U.S. Securities and Exchange Commission                                                                                                                         
|SFAS           |  | Statement of Financial Accounting Standards                                                                                                                     
|SPE            |  | Special Purpose Entity                                                                                                                                          
|VaR            |  | Value at Risk                                                                                                                                                   
|VIE            |  | Variable Interest Entity                                                                                                                                        
|WEN            |  | Our former wholesale energy business segment                                                                                                                    



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DYNEGY HOLDINGS INC.



CONDENSED
CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)



|                                                                                           |  |                   |        |   |                  |   |        |  
|------------------------------------------------------------------------------------------ |  | ----------------- | ------ | - | ---------------- | - | ------ | -
|                                                                                           |  | September 30,2004 |        |   | December 31,2003 |  
|ASSETS                                                                                     |  |                   |        |   |                  |   |        |  
|Current Assets                                                                             |  |                   |        |   |                  |   |        |  
|Cash and cash equivalents                                                                  |  | $                 | 415    |   |                  | $ | 328    |  
|Accounts receivable, net of allowance for doubtful accounts of $151 and $174, respectively |  |                   | 667    |   |                  |   | 806    |  
|Accounts receivable, affiliates                                                            |  |                   | 178    |   |                  |   | 25     |  
|Inventory                                                                                  |  |                   | 260    |   |                  |   | 194    |  
|Assets from risk-management activities                                                     |  |                   | 797    |   |                  |   | 818    |  
|Prepayments and other current assets                                                       |  |                   | 434    |   |                  |   | 324    |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Total Current Assets                                                                       |  |                   | 2,751  |   |                  |   | 2,495  |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment                                                              |  |                   | 7,774  |   |                  |   | 7,691  |  
|Accumulated depreciation                                                                   |  |                   | (1,626 | ) |                  |   | (1,389 | )
|                                                                                           |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                         |  |                   | 6,148  |   |                  |   | 6,302  |  
|Other Assets                                                                               |  |                   |        |   |                  |   |        |  
|Unconsolidated investments                                                                 |  |                   | 451    |   |                  |   | 577    |  
|Assets from risk-management activities                                                     |  |                   | 634    |   |                  |   | 629    |  
|Goodwill                                                                                   |  |                   | 15     |   |                  |   | 15     |  
|Deferred income taxes                                                                      |  |                   | 71     |   |                  |   | 106    |  
|Other long-term assets                                                                     |  |                   | 198    |   |                  |   | 156    |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Total Assets                                                                               |  | $                 | 10,268 |   |                  | $ | 10,280 |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                       |  |                   |        |   |                  |   |        |  
|Current Liabilities                                                                        |  |                   |        |   |                  |   |        |  
|Accounts payable                                                                           |  | $                 | 531    |   |                  | $ | 631    |  
|Accounts payable, affiliates                                                               |  |                   | 84     |   |                  |   | 195    |  
|Accrued liabilities and other current liabilities                                          |  |                   | 473    |   |                  |   | 415    |  
|Liabilities from risk-management activities                                                |  |                   | 879    |   |                  |   | 838    |  
|Notes payable and current portion of long-term debt                                        |  |                   | 24     |   |                  |   | 79     |  
|Current portion of long-term debt to affiliates                                            |  |                   |       |   |                  |   | 71     |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Total Current Liabilities                                                                  |  |                   | 1,991  |   |                  |   | 2,229  |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Long-term debt                                                                             |  |                   | 3,926  |   |                  |   | 3,464  |  
|Long-term debt to affiliates                                                               |  |                   | 200    |   |                  |   | 200    |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Long-Term Debt                                                                             |  |                   | 4,126  |   |                  |   | 3,664  |  
|Other Liabilities                                                                          |  |                   |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                |  |                   | 718    |   |                  |   | 746    |  
|Other long-term liabilities                                                                |  |                   | 331    |   |                  |   | 499    |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Total Liabilities                                                                          |  |                   | 7,166  |   |                  |   | 7,138  |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Minority Interest                                                                          |  |                   | 108    |   |                  |   | 121    |  
|Commitments and Contingencies (Note 8)                                                     |  |                   |        |   |                  |   |        |  
|Additional paid-in capital                                                                 |  |                   | 2,419  |   |                  |   | 2,419  |  
|Accumulated other comprehensive income (loss), net of tax                                  |  |                   | (24    | ) |                  |   | 33     |  
|Accumulated deficit                                                                        |  |                   | (433   | ) |                  |   | (463   | )
|Stockholders Equity                                                                       |  |                   | 1,032  |   |                  |   | 1,032  |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Total Stockholders Equity                                                                 |  |                   | 2,994  |   |                  |   | 3,021  |  
|                                                                                           |  |                   |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                 |  | $                 | 10,268 |   |                  | $ | 10,280 |  
|                                                                                           |  |                   |        |   |                  |   |        |  



See the notes to
condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.



CONDENSED
CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)



|                                                                            |  |                                 |        |   |                                |   |        |      |  |   |        |   |  |   |        |  
|--------------------------------------------------------------------------- |  | ------------------------------- | ------ | - | ------------------------------ | - | ------ | ---- |  | - | ------ | - |  | - | ------ | -
|                                                                            |  | Three Months EndedSeptember 30, |        |   | Nine Months EndedSeptember 30, |  
|                                                                            |  | 2004                            |        |   | 2003                           |   |        | 2004 |  |   | 2003   |  
|Revenues                                                                    |  | $                               | 1,387  |   |                                | $ | 1,174  |      |  | $ | 3,945  |   |  | $ | 3,512  |  
|Cost of sales, exclusive of depreciation shown separately below             |  |                                 | (1,184 | ) |                                |   | (1,001 | )    |  |   | (3,304 | ) |  |   | (3,299 | )
|Depreciation and amortization expense                                       |  |                                 | (78    | ) |                                |   | (79    | )    |  |   | (238   | ) |  |   | (247   | )
|Impairment and other charges                                                |  |                                 | (2     | ) |                                |   | (1     | )    |  |   | (29    | ) |  |   | 6      |  
|Gain (loss) on sale of assets, net                                          |  |                                 | (1     | ) |                                |   |       |      |  |   | 52     |   |  |   | 15     |  
|General and administrative expenses                                         |  |                                 | (65    | ) |                                |   | (56    | )    |  |   | (203   | ) |  |   | (226   | )
|                                                                            |  |                                 |        |   |                                |   |        |      |  |   |        |   |  |   |        |  
|Operating income (loss)                                                     |  |                                 | 57     |   |                                |   | 37     |      |  |   | 223    |   |  |   | (239   | )
|Earnings from unconsolidated investments                                    |  |                                 | 26     |   |                                |   | 51     |      |  |   | 117    |   |  |   | 140    |  
|Interest expense                                                            |  |                                 | (85    | ) |                                |   | (103   | )    |  |   | (275   | ) |  |   | (239   | )
|Other income and expense, net                                               |  |                                 |       |   |                                |   | 1      |      |  |   | 6      |   |  |   | 14     |  
|Minority interest income (expense)                                          |  |                                 | (10    | ) |                                |   | (2     | )    |  |   | (19    | ) |  |   | 7      |  
|Accumulated distributions associated with trust preferred securities        |  |                                 |       |   |                                |   |       |      |  |   |       |   |  |   | (8     | )
|                                                                            |  |                                 |        |   |                                |   |        |      |  |   |        |   |  |   |        |  
|Income (loss) from continuing operations before income taxes                |  |                                 | (12    | ) |                                |   | (16    | )    |  |   | 52     |   |  |   | (325   | )
|Income tax benefit (expense) (Note 11)                                      |  |                                 | 6      |   |                                |   | 6      |      |  |   | (13    | ) |  |   | 121    |  
|                                                                            |  |                                 |        |   |                                |   |        |      |  |   |        |   |  |   |        |  
|Income (loss) from continuing operations                                    |  |                                 | (6     | ) |                                |   | (10    | )    |  |   | 39     |   |  |   | (204   | )
|Loss from discontinued operations, net of taxes (Notes 2 and 11)            |  |                                 | (2     | ) |                                |   | (4     | )    |  |   | (9     | ) |  |   | (14    | )
|                                                                            |  |                                 |        |   |                                |   |        |      |  |   |        |   |  |   |        |  
|Income (loss) before cumulative effect of change in accounting principles   |  |                                 | (8     | ) |                                |   | (14    | )    |  |   | 30     |   |  |   | (218   | )
|Cumulative effect of change in accounting principles, net of taxes (Note 1) |  |                                 |       |   |                                |   |       |      |  |   |       |   |  |   | 57     |  
|                                                                            |  |                                 |        |   |                                |   |        |      |  |   |        |   |  |   |        |  
|Net income (loss)                                                           |  | $                               | (8     | ) |                                | $ | (14    | )    |  | $ | 30     |   |  | $ | (161   | )
|                                                                            |  |                                 |        |   |                                |   |        |      |  |   |        |   |  |   |        |  





See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.



CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



|                                                                                        |  |                                 |      |   |      |   |        |  
|--------------------------------------------------------------------------------------- |  | ------------------------------- | ---- | - | ---- | - | ------ | -
|                                                                                        |  | Nine Months Ended September 30, |     
|                                                                                        |  | 2004                            |      |   | 2003 |  
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                   |  |                                 |      |   |      |   |        |  
|Net income (loss)                                                                       |  | $                               | 30   |   |      | $ | (161   | )
|Adjustments to reconcile net income (loss) to net cash flows from operating activities: |  |                                 |      |   |      |   |        |  
|Depreciation and amortization                                                           |  |                                 | 265  |   |      |   | 298    |  
|Impairment and other charges                                                            |  |                                 | 29   |   |      |   |       |  
|Earnings from unconsolidated investments, net of cash distributions                     |  |                                 | (5   | ) |      |   | (26    | )
|Risk-management activities                                                              |  |                                 | (24  | ) |      |   | 373    |  
|Gain on sale of assets, net                                                             |  |                                 | (52  | ) |      |   | (16    | )
|Deferred income taxes                                                                   |  |                                 | 39   |   |      |   | (127   | )
|Cumulative effect of change in accounting principles (Note 1)                           |  |                                 |     |   |      |   | (57    | )
|Liability associated with gas transportation contracts (Note 2)                         |  |                                 | (148 | ) |      |   |       |  
|Other                                                                                   |  |                                 | (5   | ) |      |   | 25     |  
|Changes in working capital:                                                             |  |                                 |      |   |      |   |        |  
|Accounts receivable                                                                     |  |                                 | 137  |   |      |   | 1,598  |  
|Inventory                                                                               |  |                                 | (58  | ) |      |   | 107    |  
|Prepayments and other assets                                                            |  |                                 | (128 | ) |      |   | 830    |  
|Accounts payable and accrued liabilities                                                |  |                                 | (123 | ) |      |   | (1,991 | )
|Changes in non-current assets                                                           |  |                                 | (26  | ) |      |   | (26    | )
|Changes in non-current liabilities                                                      |  |                                 | 7    |   |      |   | (25    | )
|                                                                                        |  |                                 |      |   |      |   |        |  
|Net cash provided by (used in) operating activities                                     |  |                                 | (62  | ) |      |   | 802    |  
|                                                                                        |  |                                 |      |   |      |   |        |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                   |  |                                 |      |   |      |   |        |  
|Capital expenditures                                                                    |  |                                 | (129 | ) |      |   | (157   | )
|Proceeds from asset sales, net                                                          |  |                                 | 197  |   |      |   | 43     |  
|Affiliate transactions.                                                                 |  |                                 | (218 | ) |      |   | (239   | )
|                                                                                        |  |                                 |      |   |      |   |        |  
|Net cash used in investing activities                                                   |  |                                 | (150 | ) |      |   | (353   | )
|                                                                                        |  |                                 |      |   |      |   |        |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                   |  |                                 |      |   |      |   |        |  
|Net proceeds from long-term borrowings                                                  |  |                                 | 588  |   |      |   | 1,552  |  
|Repayments of long-term borrowings                                                      |  |                                 | (265 | ) |      |   | (1,989 | )
|Net cash flow from commercial paper and revolving lines of credit                       |  |                                 |     |   |      |   | (128   | )
|Other financing, net                                                                    |  |                                 | (23  | ) |      |   | (16    | )
|                                                                                        |  |                                 |      |   |      |   |        |  
|Net cash provided by (used in) financing activities                                     |  |                                 | 300  |   |      |   | (581   | )
|                                                                                        |  |                                 |      |   |      |   |        |  
|Effect of exchange rate changes on cash                                                 |  |                                 | (1   | ) |      |   | 7      |  
|Net increase (decrease) in cash and cash equivalents                                    |  |                                 | 87   |   |      |   | (125   | )
|Cash and cash equivalents, beginning of period                                          |  |                                 | 328  |   |      |   | 633    |  
|                                                                                        |  |                                 |      |   |      |   |        |  
|Cash and cash equivalents, end of period                                                |  | $                               | 415  |   |      | $ | 508    |  
|                                                                                        |  |                                 |      |   |      |   |        |  



See the notes to
condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.



CONDENSED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)



|                                                                                                          |  |                                 |     |   |      |   |      |  
|--------------------------------------------------------------------------------------------------------- |  | ------------------------------- | --- | - | ---- | - | ---- | -
|                                                                                                          |  | Three Months EndedSeptember 30, |    
|                                                                                                          |  | 2004                            |     |   | 2003 |  
|Net loss                                                                                                  |  | $                               | (8  | ) |      | $ | (14  | )
|Cash flow hedging activities, net:                                                                        |  |                                 |     |   |      |   |      |  
|Unrealized mark-to-market gains (losses) arising during period, net                                       |  |                                 | (4  | ) |      |   | 7    |  
|Reclassification of mark-to-market losses (gains) to earnings, net                                        |  |                                 | 4   |   |      |   | (8   | )
|                                                                                                          |  |                                 |     |   |      |   |      |  
|Changes in cash flow hedging activities, net (net of tax benefit of zero)                                 |  |                                 |    |   |      |   | (1   | )
|Foreign currency translation adjustments                                                                  |  |                                 | 3   |   |      |   | (2   | )
|Minimum pension liability (net of tax expense of $7 and zero, respectively)                               |  |                                 | (12 | ) |      |   |     |  
|                                                                                                          |  |                                 |     |   |      |   |      |  
|Other comprehensive loss, net of tax                                                                      |  |                                 | (9  | ) |      |   | (3   | )
|                                                                                                          |  |                                 |     |   |      |   |      |  
|Comprehensive loss                                                                                        |  | $                               | (17 | ) |      | $ | (17  | )
|                                                                                                          |  |                                 |     |   |      |   |      |  
|                                                                                                          | 
|                                                                                                          |  | Nine Months EndedSeptember 30,  |    
|                                                                                                          |  | 2004                            |     |   | 2003 |  
|Net income (loss)                                                                                         |  | $                               | 30  |   |      | $ | (161 | )
|Cash flow hedging activities, net:                                                                        |  |                                 |     |   |      |   |      |  
|Unrealized mark-to-market gains (losses) arising during period, net                                       |  |                                 | (57 | ) |      |   | 52   |  
|Reclassification of mark-to-market losses (gains) to earnings, net                                        |  |                                 | 24  |   |      |   | (29  | )
|                                                                                                          |  |                                 |     |   |      |   |      |  
|Changes in cash flow hedging activities, net (net of tax benefit (expense) of $20 and $(7), respectively) |  |                                 | (33 | ) |      |   | 23   |  
|Foreign currency translation adjustments                                                                  |  |                                 | (12 | ) |      |   | 7    |  
|Minimum pension liability (net of tax expense of $7 and zero, respectively)                               |  |                                 | (12 | ) |      |   |     |  
|                                                                                                          |  |                                 |     |   |      |   |      |  
|Other comprehensive income (loss), net of tax                                                             |  |                                 | (57 | ) |      |   | 30   |  
|                                                                                                          |  |                                 |     |   |      |   |      |  
|Comprehensive loss                                                                                        |  | $                               | (27 | ) |      | $ | (131 | )
|                                                                                                          |  |                                 |     |   |      |   |      |  



See the notes to
condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.



NOTES TO
CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



Introductory Note



On September 23, 2004, we filed a Form 8-K announcing restatements of our previously issued financial statements contained in our 2003 Form 10-K and first
and second quarter 2004 Form 10-Qs. The restatements relate to our deferred income tax accounts. The financial information in this report has not been revised to reflect the effects of this item. We expect to file amendments to our 2003 Form 10-K
and first, second and third quarter 2004 Form 10-Qs as soon as practicable after the date of this report.



Note 1Accounting Policies



The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC, except that they have not been reviewed by an independent
public accountant under Rule 10-01(d) of Regulation S-X. The year end condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These interim financial statements should be read
together with the consolidated financial statements and notes thereto included in our Form 10-K and the Introductory Note above.



The unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management,
are necessary for a fair presentation of the results for the interim periods, except for the deferred income tax accounts adjustment, as described in the Introductory Note above. The results of operations for the interim periods presented in this
Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period, however, due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of
maintenance and other expenditures and other factors. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect our reported financial
position and results of operations. These estimates and assumptions also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates affecting our consolidated financial statements on a
recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time such estimates are made. Adjustments made
with respect to the use of these estimates often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates are primarily used in
(1) developing fair value assumptions, including estimates of future cash flows and discount rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets, (4) assessing future tax
exposure and the realization of tax assets and (5) determining amounts to accrue for contingencies. Certain estimates may also effect such items as the calculated gain (loss) on sale of assets. Actual results could differ materially from any such
estimates.



We have reclassified certain amounts reported in
this Form 10-Q from prior periods to conform to the 2004 financial statement presentation. These reclassifications had no impact on reported net income (loss).



Principles of Consolidation.The accompanying unaudited condensed consolidated financial statements include our accounts and the accounts
of our majority-owned or controlled subsidiaries, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities, after eliminating intercompany accounts and transactions.



Cash and Cash Equivalents.Cash and cash
equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Allowance for Doubtful Accounts.We establish provisions for losses on accounts
receivable if it is reasonable to assume we will not collect all or part of outstanding balances. We review collectibility and establish or adjust our allowance as necessary primarily using a percent of balance methodology. The specific
identification method is also used in certain circumstances.



Investment in Unconsolidated Affiliates.Investments in affiliates over which we may exercise significant influence, generally 20% to 50% ownership interests, are accounted for using the equity method. Any excess of our
investment in affiliates, as compared to our share of the underlying equity, that is not recognized as goodwill is amortized over the estimated economic service lives of the underlying assets. Other investments over which we may not exercise
significant influence and that have readily determinable fair values are considered available-for-sale and are recorded at quoted market values or at the lower of cost or net realizable value, if there are no readily determinable fair values. For
securities with readily determinable fair values, the change in the unrealized gain or loss, net of deferred income tax, is recorded as a separate component of other comprehensive income (loss) in the unaudited condensed consolidated statements of
comprehensive loss. Realized gains and losses on investment transactions are determined using the specific identification method. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with
write-downs recognized in earnings from unconsolidated investments in the unaudited condensed consolidated statements of operations.



Concentration of Credit Risk.We sell our energy products and services to customers in the electric and gas distribution industries and to
entities engaged in industrial and petrochemical businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because the customer base may be similarly affected by
changes in economic, industry, weather or other conditions.



Inventory.Our natural gas, natural gas liquids, coal and crude oil inventories are valued at the lower of weighted average cost or at market. Our materials and supplies inventory is carried at the lower of cost or market
using the specific identification method.



Property,
Plant and Equipment.Property, plant and equipment, which has consisted principally of gas gathering, processing, fractionation, terminaling and storage facilities, natural gas transportation and electric transmission lines, pipelines and
power generating facilities, is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized. We consider major maintenance to be expenditures incurred on a cyclical basis to maintain and prolong
the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method over the estimated economic service lives of the
assets, ranging from three to 40 years. Composite depreciation rates, which we refer to as composite rates, are applied to functional groups of assets having similar economic characteristics. The estimated economic service lives of our functional
asset groups are as follows:



|                                                                      |  |               
|--------------------------------------------------------------------- |  | --------------
|Asset Group                                                           |  | Range of Years
|Power Generation Facilities                                           |  | 27 to 40      
|Natural Gas Gathering Systems and Processing Facilities               |  | 20            
|Fractionation, Terminaling and Natural Gas Liquids Storage Facilities |  | 20 to 25      
|Transportation Equipment                                              |  | 5 to 10       
|Buildings and Improvements                                            |  | 10 to 39      
|Office and Miscellaneous Equipment                                    |  | 3 to 20       



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Gains and losses are not recognized for retirements of property, plant and equipment subject to
composite rates until the asset group subject to the composite rate is retired. Gains and losses on sales of individual assets are reflected in gain (loss) on sale of assets in the unaudited condensed consolidated statements of operations. We review
the carrying value of our long-lived assets in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which addresses the accounting and reporting for the impairment or disposal of long-lived
assets. Under this standard, we evaluate an asset for impairment when events or circumstances indicate its carrying value may not be recovered. These events include market declines, changes in the manner in which we intend to use an asset or
decisions to sell an asset and adverse changes in the legal or business environment. When we decide to exit or sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to the estimated sales
price, less costs to sell.



Other Contingencies.
Environmental costs relating to current operations are expensed or capitalized, as appropriate, depending on whether they provide future economic benefit. Liabilities are recorded when environmental assessment indicate remedial efforts are probable
and the costs can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and site-specific costs. Liabilities may be recognized on a discounted basis if the amount and timing of
anticipated expenditures are fixed or reliably determinable; otherwise, such liabilities are recognized on an undiscounted basis. Liabilities incurred by providing indemnification in connection with assets sold or closed are recognized upon such
sale or closure to the extent they are probable, can be estimated and have not previously been reserved. In assessing liabilities, no offset is made for potential insurance recoveries. Recognition of any joint and several liability is based upon our
best estimate of our final pro rata share of such liability.



Liabilities for other contingencies are recognized in accordance with SFAS No. 5, Accounting for Contingencies, upon identification of an exposure, which, when fully analyzed, indicates that it is both probable a liability has
been incurred and the loss amount can be reasonably estimated. Non-capital costs to remedy such contingencies or other exposures are charged to a reserve, if one exists, or otherwise to current-period operations. We accrue the lesser end of the
range when a range of probable loss exists.



Goodwill and
Other Intangible Assets. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets, we subject goodwill to a fair value-based impairment test on at least an annual basis. The estimation of fair value is highly
subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. We currently perform our annual impairment test in the fourth
quarter after our annual budgetary process, and we may record further impairment losses in future periods as a result of such test.



Revenue Recognition. We utilize two comprehensive accounting models in reporting our consolidated financial position and results of
operations as required by GAAP: an accrual model and a fair value model. We determine whether to apply one comprehensive accounting model rather than the other based on guidance provided by the FASB and the SEC.



The accrual model has historically been used to account for substantially all
of the operations conducted in the GEN and NGL segments. Revenues from power generation are recognized upon output, product delivery or satisfaction of specific targets, all as specified by contractual terms. Revenues for product sales, gas
processing, storage and marketing and refinery services are recognized when title passes to the customer or when the service is performed. Fractionation and transportation revenues are recognized based on volumes received in accordance with
contractual terms. Shipping and handling costs are included in revenue when billed to customers with the sale of products.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



The fair value model is used to account for certain forward physical and financial transactions,
primarily in the GEN and CRM segments, which meet criteria defined by FASB for derivative instruments. These criteria require these contracts to relate to future periods, to contain price and volume components and to have terms that require or
permit net settlement of the contract in cash or its equivalent. The value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current prices and rates as of each balance sheet date.
The net gains or losses resulting from the revaluation of these contracts during the period are recognized currently in our consolidated statements of operations unless such contracts qualify and are designated as cash flow hedges, in which case the
same gains or losses are recorded in other comprehensive income (loss) until such time as the hedged transaction occurs. If the underlying transaction being hedged by the commodity, interest rate or foreign currency transaction is disposed of or
otherwise terminated, the gain or loss associated with such contract is no longer deferred and is recognized in the period the underlying contract is eliminated. Subsequent gains and losses associated with the change in value of interest rate or
foreign currency instruments are recognized in other income and expense, net, unless the instrument is redesignated as a hedge. If the hedging transaction is terminated prior to the occurrence of the underlying transaction being hedged, the gain or
loss associated with the hedging transaction is deferred and recognized in income in the period in which the underlying transaction being hedged occurs. Assets and liabilities associated with these transactions are reflected on our consolidated
balance sheets as risk-management assets and liabilities and classified as short- (i.e., current) or long-term pursuant to each contracts individual length.



We estimate the fair value of our marketing portfolio using a liquidation value approach assuming that our ability to
transact business in the market remains at historical levels. The estimated fair value of our portfolio is computed by multiplying all existing positions in our portfolio by estimated prices, reduced by a LIBOR-based time value of money adjustment
and deduction of reserves for credit and price. The estimated prices in this valuation are based either on (1) prices obtained from market quotes or, if market quotes are unavailable, (2) prices from a proprietary model that incorporates forward
energy prices derived from market quotes and values from executed transactions.



Cash inflows and outflows associated with the settlement of risk management activities are recognized in operating cash flows.



Income Taxes. Dynegy, our parent, files a consolidated U.S. federal income tax return and, for financial reporting purposes, accounts for
income taxes using the liability method in accordance with SFAS No. 109, Accounting for Income Taxes. Under this method, income taxes are provided for amounts currently payable and for amounts deferred as tax assets and liabilities
caused by differences between financial statement carrying amounts and the tax basis of certain assets and liabilities. Deferred income taxes are measured using the enacted tax rates that are assumed will be in effect when the differences reverse.
Valuation allowances are provided against deferred tax assets when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates used to recognize deferred tax assets are
subject to revision, either higher or lower, in future periods based on new facts or circumstances.



We are included in the consolidated federal and state income tax returns filed by Dynegy. Pursuant to tax allocation arrangements, we record a receivable
in an amount equal to the tax benefits realized in Dynegys consolidated federal income tax return resulting from the utilization of our net operating losses and/or tax credits, or record a payable to Dynegy in an amount equal to the federal
income tax computed on our separate company taxable income less the tax benefits associated with net operating losses and/or tax credits generated by us which are utilized in Dynegys consolidated federal income tax return.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Foreign Currency. For subsidiaries whose functional currency is not the U.S. Dollar,
assets and liabilities are translated at year-end rates of exchange and revenues and expenses are translated at monthly average exchange rates. Translation adjustments for the asset and liability accounts are included as a separate component of
accumulated other comprehensive income (loss) in stockholders equity.



Currency transaction gains and losses are recorded in other income and expense, net on our unaudited condensed consolidated statements of operations and totaled losses of $2 million and $1 million for the three months
ended September 30, 2004 and 2003, respectively, and gains of $1 million and $10 million for the nine months ended September 30, 2004 and 2003, respectively.



Minority Interest. Minority interest on our unaudited condensed consolidated balance sheets includes third-party investments in entities
that we consolidate, but do not wholly own. The net pre-tax results attributed to minority interest holders in consolidated entities are included in minority interest income (expense) in the unaudited condensed consolidated statements of operations.



Accounting Principles Adopted



EITF Issue 02-03.In October 2002, the EITF rescinded EITF
Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, which previously required use of mark-to-market accounting for our energy trading contracts. While the rescission of EITF Issue 98-10
reduced the number of contracts accounted for on a mark-to-market basis, it did not eliminate mark-to-market accounting. All derivative contracts that either do not qualify, or are not designated, as hedges or as normal purchases or sales, as
defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, continue to be marked-to-market in accordance with SFAS No. 133. Any earnings or losses previously recognized under EITF Issue 98-10 that
would not have been recognized under SFAS No. 133 were reversed in 2003 in connection with our adoption of EITF Issue 02-03.



The cumulative effect of this change in accounting principle resulted in after-tax earnings of $21 million in the first quarter 2003 and comprised the
following items no longer required to be recorded using mark-to-market accounting (in millions):



|                                                                                                |  |   |      |  
|----------------------------------------------------------------------------------------------- |  | - | ---- | -
|Removal of net risk-management assets representing the value of natural gas storage contracts   |  | $ | (176 | )
|Removal of other net risk-management assets                                                     |  |   | (24  | )
|Removal of net risk-management liabilities representing the value of power tolling arrangements |  |   | 103  |  
|                                                                                                |  |   |      |  
|Net change in risk-management assets and liabilities                                            |  |   | (97  | )
|Addition of inventory previously included in risk-management assets (1)                         |  |   | 130  |  
|                                                                                                |  |   |      |  
|Pre-tax gain recorded from change in accounting principle                                       |  |   | 33   |  
|Income tax provision                                                                            |  |   | (12  | )
|                                                                                                |  |   |      |  
|After-tax gain recorded in the unaudited condensed consolidated statements of operations        |  | $ | 21   |  
|                                                                                                |  |   |      |  

---

|(1) | A substantial portion of this natural gas inventory was sold during the three months ended March 31, 2003, with the remainder being sold in the second quarter 2003.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



EITF Issue 03-11.In July 2003, the EITF reached consensus on Issue 03-11,
Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and Not Held for Trading Purposes as Defined in EITF Issue
02-03, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. The consensus stated that determining whether realized gains and
losses on physically settled derivative contracts not held for trading purposes should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. The
consideration of the facts and circumstances, including economic substance, should be made in the context of the various activities of the entity rather than based solely on the terms of the individual contracts. We were not materially impacted by
the adoption of EITF Issue 03-11.



SFAS No. 143.
In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. We adopted SFAS No. 143, which provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets,
effective January 1, 2003. Under SFAS No. 143, an ARO is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset by an amount equal to the ARO. In each subsequent period, the
liability is accreted towards the ultimate obligation amount and the capitalized ARO costs are depreciated over the useful life of the related asset.



As part of the transition adjustment in adopting SFAS No. 143, existing environmental liabilities in the amount of $73 million were reversed in the first
quarter 2003. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the ARO and was recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities exceeded the fair
value of the future retirement obligations, the impact of adopting SFAS No. 143 was an increase in earnings, net of tax, of $34 million in the first quarter 2003, which is included in cumulative effect of change in accounting principles in the
unaudited condensed consolidated statements of operations. In addition to these liabilities, we also have potential retirement obligations for dismantlement of power generation facilities a fractionation facility and natural gas storage facilities.
Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. Liabilities will be recorded in accordance
with SFAS No. 143 at the time we are able to estimate any new AROs.



At January 1, 2004, our ARO liabilities were $30 million for our GEN segment and $10 million for our NGL segment. These retirement obligations related to activities such as ash pond and landfill capping, closure and post-closure costs,
environmental testing, remediation, monitoring and land lease obligations. During the three- and nine-month periods ended September 30, 2004, accretion expense recognized as our ARO liabilities accreted toward their ultimate redemption values
totaled approximately $1 million and $3 million, respectively. In the third quarter 2004, a land lease formerly held by Illinois Power was transferred to our GEN segment. The accompanying ARO liability, which totaled approximately $1 million at
September 30, 2004, was also transferred. There were no additional AROs recorded or settled, nor were there any revisions to estimated cash flows associated with existing AROs, during the three- and nine-month periods ended September 30, 2004. At
September 30, 2004, our aggregate ARO liability was $44 million.



SFAS No. 148. In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based CompensationTransition and Disclosure. SFAS No. 148 amends SFAS No. 123, Accounting for Stock-Based
Compensation, and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation in a fiscal
year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entitys accounting policy decisions with respect to



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



stock-based employee compensation. Although we do not grant stock options to our employees, these employees do participate in Dynegys stock-based
employee compensation programs. We transitioned to a fair value based method of accounting for stock-based compensation in the first quarter 2003 and are using the prospective method of transition as described under SFAS No. 148.



Under the prospective method of transition, all stock options granted by
Dynegy after January 1, 2003 are accounted for on a fair value basis. We will incur compensation expense over the vesting period of the options in an amount equal to the fair value of the options. Options granted prior to January 1, 2003 continue to
be accounted for using the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense is not reflected for employee stock options unless they were granted at an exercise price lower than market value on
the grant date. We have recognized compensation expense over the applicable vesting periods for in-the-money stock options Dynegy previously granted. No in-the-money stock options have been granted by Dynegy since 1999.



Had compensation cost for all stock options granted prior to 2003 been
determined on a fair value basis consistent with SFAS No. 123, our net income (loss) would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2004 and 2003, respectively.



|                                                                                                                                            |  |                                      |     |   |                                |   |     |      |  |   |      |   |  |   |      |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------ | --- | - | ------------------------------ | - | --- | ---- |  | - | ---- | - |  | - | ---- | -
|                                                                                                                                            |  | Three Months EndedSeptember 30,      |     |   | Nine Months EndedSeptember 30, |  
|                                                                                                                                            |  | 2004                                 |     |   | 2003                           |   |     | 2004 |  |   | 2003 |  
|                                                                                                                                            |  | (in millions, except per share data) |    
|Net income (loss) as reported                                                                                                               |  | $                                    | (8  | ) |                                | $ | (14 | )    |  | $ | 30   |   |  | $ | (161 | )
|Add: Stock-based employee compensation expense included in reported net income (loss), net of related tax effects                           |  |                                      | 1   |   |                                |   |    |      |  |   | 3    |   |  |   | 1    |  
|Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax
effects |  |                                      | (4  | ) |                                |   | (7  | )    |  |   | (13  | ) |  |   | (24  | )
|                                                                                                                                            |  |                                      |     |   |                                |   |     |      |  |   |      |   |  |   |      |  
|Pro forma net income (loss)                                                                                                                 |  | $                                    | (11 | ) |                                | $ | (21 | )    |  | $ | 20   |   |  | $ | (184 | )
|                                                                                                                                            |  |                                      |     |   |                                |   |     |      |  |   |      |   |  |   |      |  



SFAS No.
149. In April 2003, the FASB issued SFAS No. 149, Amendment of SFAS No. 133 on Derivative Instruments and Hedging Activities, which clarifies and amends various issues related to derivatives and financial instruments addressed in
SFAS No. 133 and interpretations issued by the Derivatives Implementation Group. In particular, SFAS No. 149: (1) clarifies when a contract with an initial net investment meets the characteristics of a derivative; (2) clarifies when a derivative
contains a financing component that should be recorded as a financing transaction on the balance sheet and the statement of cash flows; (3) amends the definition of an underlying in SFAS No. 133 to conform to the language used in FIN No.
45; and (4) clarifies other derivative concepts. SFAS No. 149 is applicable to all contracts entered into or modified after June 30, 2003 and to all hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not
materially impact our financial statements.



SFAS No.
150.In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity, which establishes how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and equity. Instruments that have an unconditional obligation requiring the issuer to redeem the instrument by transferring an asset at a specified date are required to be classified as
liabilities on the balance sheet. Instruments that require the issuance of a variable number of equity shares by the issuer generally do not have the risks associated with equity instruments and as



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



such should also be classified as liabilities on the balance sheet. SFAS No. 150 was effective for contracts in existence or created or modified for the
first interim period beginning after June 15, 2003. Upon adoption, we reclassified approximately $200 million of Company Obligated Preferred Securities (now referred to as Subordinated Debentures), previously recorded in the mezzanine section of our
balance sheet between liabilities and stockholders equity, to long-term liabilities. Accordingly, the interest related to this instrument is recorded as interest expense beginning July 1, 2003. Prior year amounts have not been reclassified to
conform to this change. Previously, the preferred return on this instrument was reported in accumulated distributions associated with trust preferred securities in the unaudited condensed consolidated statements of operations.



FIN No. 46R. In the fourth quarter 2003, we adopted the initial
provisions of FIN No. 46R, Consolidation of Variable Interest EntitiesAn Interpretation of ARB No. 51. FIN No. 46R was effective on December 31, 2003 for entities considered SPEs. We adopted the remaining provisions of FIN No. 46R
on March 31, 2004. These provisions require that we review the structure of non-SPE legal entities in which we have an investment and other legal entities with whom we transact to determine whether such entities are VIEs, as defined by FIN No. 46R.
With respect to each of the VIEs we identified, we assessed whether we are the primary beneficiary, as defined by FIN No. 46R. We concluded that we were not the primary beneficiary of any of these entities and, therefore, the adoption
did not have an impact on our unaudited condensed consolidated financial statements.



FIN No. 46R requires additional disclosures for entities which meet the definition of a VIE in which we hold a significant variable interest but are not the primary beneficiary. We own 50% equity interests in various
generation facilities in Illinois and California which are accounted for using equity method accounting and are included in Unconsolidated investments in our unaudited condensed consolidated balance sheets. We acquired or began involvement with
these equity interests in 1997 and 1999. Total net generating capacity for these generating facilities ranges from 165 MW to 1,156 MW. As a result of various contractual arrangements into which these entities have entered, we have concluded that
they are VIEs. As we do not absorb a majority of the expected losses or receive a majority of the expected residual returns, we are not considered the primary beneficiary of these entities. Our equity investment balance in the facilities totaled
$346 million at September 30, 2004, and one of these entities has a loan outstanding to another of these entities, which totaled $20 million at September 30, 2004.



In July 2001, we entered into several agreements, including a power tolling agreement, a financial derivative instrument, an
energy management agreement and a natural gas supply agreement, with Sithe Independence Power Partners, L.P., which we refer to as Sithe Independence or Sithe Independence, L.P. and which owns and operates a 1,042 MW combined cycle natural gas
generation facility near Scriba, New York. We had previously been unable to assess whether the entity was a VIE, but have subsequently received the necessary financial and contractual information related to the entity. As a result of various
contractual arrangements into which this entity has entered, we have concluded that it is a VIE. However, as we do not absorb a majority of the expected losses or receive a majority of expected residual returns, we are not considered the primary
beneficiary of the entity. Our agreements with Sithe Independence Power Partners, L.P. are in effect through 2014. Our future obligations under these agreements are approximately $772 million, which includes the fixed capacity payments under our
power tolling contract and fixed payments related to the financial derivative instrument. In November 2004, Dynegy entered into an agreement to purchase from Exelon Corporation all of the outstanding capital stock of ExRes SHC, Inc., the parent
company of Sithe Energies, Inc. and Sithe Independence, L.P. Please read Note 2Acquisitions, Dispositions, Contract Terminations and Discontinued OperationsAcquisitionsSithe Energies below for further discussion.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Cumulative Effect of Change in Accounting Principles



We adopted SFAS No. 143 and provisions of EITF Issue 02-03 in the first
quarter 2003. Please see above for a discussion of the impact of adopting these standards.



Note 2Acquisitions, Dispositions, Contract Terminations and Discontinued Operations



Acquisitions



Sithe Energies. In November 2004, Dynegy entered into an agreement to purchase from Exelon Corporation all of the outstanding capital
stock of ExRes SHC, Inc., the parent company of Sithe Energies, Inc. and Sithe Independence, L.P. Through this acquisition, Dynegy will acquire the 1,042 MW, 7,211-Btu heat rate, combined-cycle Independence power generation facility located near
Scriba, NY, four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. In addition, Sithe Independence, L.P. holds a 750 MW firm capacity sales agreement with Con Edison, a subsidiary of
Consolidated Edison, Inc. The capacity sales agreement, which runs through 2014, provides annual cash receipts of approximately $100 million. Sithe Independence, L.P. also holds power tolling and financial swap contracts with one of our
subsidiaries. At the time of closing, ExRes SHC, Inc. will not be consolidated by us. The acquisition transforms the tolling and swap contracts into Dynegy intercompany and our affiliate agreements. Other than the reporting of the transactions with
Sithe Independence, L.P. as affiliate transactions, we do not anticipate any other material impact to us from the transaction.



The transaction is subject to various closing conditions, including the receipt of approvals from various federal and state regulatory entities, including
the FERC and the New York Public Service Commission, as well as Hart-Scott-Rodino review by the Federal Trade Commission. The transaction is also subject to the receipt by Sithe Independence of a waiver or amendment from its bondholders under its
trust indenture.



Dispositions and Contract Terminations



Sale of Illinois Power and Power Purchase
Agreement. On September 30, 2004, Dynegy sold all of its outstanding common and preferred shares of Illinois Power Company, owned by Illinova Corporation, its subsidiary, as well as its 20% interest in the Joppa power generation facility, to
Ameren for $2.3 billion. Concurrent with that sale, we entered into a two-year power purchase agreement under which Illinois Power will annually purchase from us up to 2,800 MWs of capacity and 11.3 million MWh of energy at fixed prices beginning in
January 2005. We also agreed to sell an additional 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to Illinois Power at a fixed price with an option to purchase energy at market-based prices.



Hackberry LNG Project.During the first quarter 2003, we
entered into an agreement to sell our ownership interest in Hackberry LNG Terminal LLC, the entity we formed in connection with our proposed LNG terminal/gasification project in Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San
Diego-based Sempra Energy. The transaction closed in April 2003, after which we received contingent payments in 2003 based upon project development milestones. In March 2004, we sold our remaining financial interest in this project, which interest
included rights to receive future contingent payments under the 2003 agreement, for $17 million and recognized a pre-tax gain of $17 million on the sale. This gain is included in Gain (loss) on sale of assets, net on our unaudited condensed
consolidated statements of operations.



Indian
Basin. In April 2004, we sold our 16% interest in the Indian Basin Gas Processing Plant for approximately $48 million. In the second quarter 2004, we recognized a pre-tax gain on the sale of approximately



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



$36 million. This gain is included in Gain (loss) on sale of assets, net on our unaudited condensed consolidated statements of operations.



Sherman. In November 2004, we sold our Sherman natural gas
processing facility located in Sherman, Texas. This sale resulted in a pre-tax gain of approximately $16 million.



Gas Transportation Contracts.In June 2004, we agreed to exit four long-term natural gas transportation contracts whose purpose was to
secure firm pipeline capacity through 2014 in support of our former third-party marketing and trading business. In exchange for exiting these obligations, we paid $20 million in June 2004 and will pay an additional $42 million in the first quarter
2005. This future payment obligation was recorded at its fair value of $40 million and will be accreted to $42 million over the period July 1, 2004 through March 31, 2005. Additionally, we reversed an aggregate liability of $148 million associated
with the transportation contracts that was originally established in 2001 and recognized a pre-tax gain of $88 million related to these transactions. This gain is included in Revenues on our unaudited condensed consolidated statements of operations
and is included in the results of our CRM segment. This agreement will eliminate our obligation to make approximately $295 million in aggregate fixed capacity payments from April 2005 through 2014.



Discontinued Operations



As part of our restructuring plan, we sold or liquidated some of our
operations during 2003, including our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.



The following table summarizes information related to our discontinued operations:



|                                           |  |               |   |         |   |     |               |  |   |       |   |  |   |     |  
|------------------------------------------ |  | ------------- | - | ------- | - | --- | ------------- |  | - | ----- | - |  | - | --- | -
|                                           |  | U.K.Storage   |   | U.K.CRM |   |     | GlobalLiquids |  |   | Total |  
|                                           |  | (in millions) |  
|Three Months Ended September 30, 2004      |  |               |   |         |   |     |               |  |   |       |   |  |   |     |  
|Income (loss) from operations before taxes |  | $             |  |         | $ | (2  | )             |  | $ | 1     |   |  | $ | (1  | )
|Loss from operations after taxes           |  |               |  |         |   | (2  | )             |  |   |      |   |  |   | (2  | )
|                                           |  |               |   |        
|Three Months Ended September 30, 2003      |  |               |   |         |   |     |               |  |   |       |   |  |   |     |  
|Loss from operations before taxes          |  | $             |  |         | $ | (7  | )             |  | $ | (2    | ) |  | $ | (9  | )
|Loss from operations after taxes           |  |               |  |         |   | (4  | )             |  |   | (1    | ) |  |   | (5  | )
|Gain on sale before taxes                  |  |               | 1 |         |   |    |               |  |   |      |   |  |   | 1   |  
|Gain on sale after taxes                   |  |               | 1 |         |   |    |               |  |   |      |   |  |   | 1   |  
|                                           |  |               |   |        
|                                           |  | U.K.Storage   |   | U.K.CRM |   |     | GlobalLiquids |  |   | Total |  
|                                           |  | (in millions) |  
|Nine Months Ended September 30, 2004       |  |               |   |         |   |     |               |  |   |       |   |  |   |     |  
|Income from operations before taxes        |  | $             |  |         | $ | 17  |               |  | $ | 1     |   |  | $ | 18  |  
|Loss from operations after taxes           |  |               |  |         |   | (9  | )             |  |   |      |   |  |   | (9  | )
|                                           |  |               |   |        
|Nine Months Ended September 30, 2003       |  |               |   |         |   |     |               |  |   |       |   |  |   |     |  
|Revenue                                    |  | $             |  |         | $ | 21  |               |  | $ |      |   |  | $ | 21  |  
|Loss from operations before taxes          |  |               |  |         |   | (18 | )             |  |   | (3    | ) |  |   | (21 | )
|Loss from operations after taxes           |  |               |  |         |   | (13 | )             |  |   | (2    | ) |  |   | (15 | )
|Gain on sale before taxes                  |  |               | 1 |         |   |    |               |  |   |      |   |  |   | 1   |  
|Gain on sale after taxes                   |  |               | 1 |         |   |    |               |  |   |      |   |  |   | 1   |  



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



In the first quarter 2004, we recognized $17 million of pre-tax income related to translation gains
on foreign currency in the U.K. Please see Note 4Risk Management Activities and Accumulated Other Comprehensive LossNet investment hedges in foreign operations for further discussion. In the second quarter 2004, we recognized a tax
expense of $20 million related to charges resulting from the conclusion of prior year tax audits. Please see Note 11Income Taxes for further discussion.



Note 3Restructuring Charges



In the nine months ended September 30, 2004, we recorded a $5 million pre-tax charge related to the impairment of one of our midstream assets.



In October 2002, we announced a restructuring plan designed to improve
operational efficiencies and performance across our lines of business. The following is a schedule of 2004 activity for the liabilities recorded in connection with this restructuring:



|                              |  |               |     |   |                                     |   |    |       |  |   |     |  
|----------------------------- |  | ------------- | --- | - | ----------------------------------- | - | -- | ----- |  | - | --- | -
|                              |  | Severance     |     |   | CancellationFees andOperatingLeases |   |    | Total | 
|                              |  | (in millions) |    
|Balance at December 31, 2003  |  | $             | 20  |   |                                     | $ | 28 |       |  | $ | 48  |  
|2004 adjustments to liability |  |               | 18  |   |                                     |   | 6  |       |  |   | 24  |  
|Cash payments                 |  |               | (36 | ) |                                     |   | (8 | )     |  |   | (44 | )
|                              |  |               |     |   |                                     |   |    |       |  |   |     |  
|Balance at September 30, 2004 |  | $             | 2   |   |                                     | $ | 26 |       |  | $ | 28  |  
|                              |  |               |     |   |                                     |   |    |       |  |   |     |  



The adjustment to the
accrued liability during 2004 primarily reflects increases in the severance accrual due to changes in our estimate of the probable loss associated with the severance claims of Dynegys former chief executive officer and Dynegys former
president. Cash payments during 2004 reflect payments made to Dynegys former chief executive officer and Dynegys former president. Please see Note 8Commitments and ContingenciesSeverance Arbitrations for further discussion
regarding the status of these claims and settlement payments.



We expect the $26 million accrual associated with cancellation fees and operating leases to be paid by the end of 2007 when the leases expire.



Note 4Risk Management Activities and Accumulated Other Comprehensive Loss



The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in
an attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more fully described in Note 5Risk Management Activities and Financial Instruments beginning on page F-22 of our Form 10-K.



Cash flow hedges. We enter into financial
derivative instruments that qualify as cash flow hedges. Instruments related to our GEN, CRM and NGL businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin. Interest rate swaps
are used to convert the floating interest-rate component of some obligations to fixed rates.



During the three and nine months ended September 30, 2004, we recorded a $3 million charge related to ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



of hedge effectiveness related to the hedge of future cash flows. During the three and nine months ended September 30, 2003, there was no material
ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three and nine months ended September 30, 2004, no material
amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring. During the three and nine months ended September 30, 2003, we recorded a $4 million charge related to the
reclassification of earnings in connection with forecasted transactions that were no longer considered probable of occurring.



The balance in cash flow hedging activities, net at September 30, 2004 is expected to be reclassified to future earnings, contemporaneously with the
related purchases of fuel, sales of electricity or natural gas liquids and payments of interest, as applicable to each type of hedge. Of this amount, after-tax losses of approximately $27 million are currently estimated to be reclassified into
earnings over the 12-month period ending September 30, 2005. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market conditions and other
factors.



Fair value hedges. We also enter into
derivative instruments that qualify as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into variable-rate debt. During the three and nine months ended September 30, 2004 and 2003, there was no
ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and nine months ended September 30, 2004, no amounts were recognized in relation to firm
commitments that no longer qualified as fair value hedges. During the three and nine months ended September 30, 2003, we recorded a $6 million gain related to firm commitments that no longer qualified as fair value hedges.



In July 2004, we entered into interest rate swaps with a notional value of
$500 million. These swaps were designated as fair value hedges and effectively convert a portion of our non-prepayable fixed-rate debt into variable-rate debt.



Net investment hedges in foreign operations. Although we have exited a substantial amount of our foreign operations, we continue to have
investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. In the past, we used derivative financial instruments, including foreign exchange forward contracts and cross-currency interest rate
swaps, to hedge this exposure. As of September 30, 2004, we had no net investment hedges in place.



During the first quarter 2003, our efforts to exit the U.K. CRM business were substantially completed. As required by SFAS No. 52, Foreign Currency
Translation, a significant portion of unrealized gains and losses resulting from translation and financial instruments utilized to hedge currency exposures previously recorded in stockholders equity were recognized in income, resulting
in an after-tax loss of approximately $5 million in the nine months ended September 30, 2003. During the first quarter 2004, we repatriated a majority of our cash from the U.K., resulting in the substantial liquidation of our investment in the U.K.
As such, we recognized approximately $17 million of pre-tax translation gains in income that arose since April 1, 2003 and had accumulated in stockholders equity.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Accumulated other comprehensive income (loss).Accumulated other comprehensive income
(loss), net of tax, is included in stockholders equity on the unaudited condensed consolidated balance sheets as follows:



|                                                          |  |                   |     |   |                  |   |    |  
|--------------------------------------------------------- |  | ----------------- | --- | - | ---------------- | - | -- | -
|                                                          |  | September 30,2004 |     |   | December 31,2003 |  
|                                                          |  | (in millions)     |    
|Cash flow hedging activities, net                         |  | $                 | (23 | ) |                  | $ | 10 |  
|Foreign currency translation adjustment                   |  |                   | 14  |   |                  |   | 26 |  
|Minimum pension liability                                 |  |                   | (15 | ) |                  |   | (3 | )
|                                                          |  |                   |     |   |                  |   |    |  
|Accumulated other comprehensive income (loss), net of tax |  | $                 | (24 | ) |                  | $ | 33 |  
|                                                          |  |                   |     |   |                  |   |    |  



Note 5Unconsolidated
Investments



A summary of our unconsolidated investments
is as follows:



|                                 |  |                   |     |                  |   |    
|-------------------------------- |  | ----------------- | --- | ---------------- | - | ---
|                                 |  | September 30,2004 |     | December 31,2003
|                                 |  | (in millions)    
|Equity affiliates:               |  |                   |     |                  |   |    
|GEN investments                  |  | $                 | 373 |                  | $ | 495
|NGL investments                  |  |                   | 78  |                  |   | 82 
|                                 |  |                   |     |                  |   |    
|Total unconsolidated investments |  | $                 | 451 |                  | $ | 577
|                                 |  |                   |     |                  |   |    



Summarized aggregate
financial information for West Coast Power and our equity share thereof was:



|                 |  |                                 |     |              |   |       |  |              |     |  |   |    
|---------------- |  | ------------------------------- | --- | ------------ | - | ----- |  | ------------ | --- |  | - | ---
|                 |  | Nine Months Ended September 30,
|                 |  | 2004                            |     | 2003        
|                 |  | Total                           |     | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)                  
|Revenues         |  | $                               | 962 |              | $ | 481   |  | $            | 834 |  | $ | 417
|Operating income |  |                                 | 246 |              |   | 123   |  |              | 204 |  |   | 102
|Net income       |  |                                 | 247 |              |   | 123   |  |              | 205 |  |   | 102



Summarized aggregate
financial information for unconsolidated equity investments, exclusive of the West Coast Power information above, and our equity share thereof was:



|                 |  |                                 |     |              |   |       |  |              |       |  |   |    
|---------------- |  | ------------------------------- | --- | ------------ | - | ----- |  | ------------ | ----- |  | - | ---
|                 |  | Nine Months Ended September 30,
|                 |  | 2004                            |     | 2003        
|                 |  | Total                           |     | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)                  
|Revenues         |  | $                               | 434 |              | $ | 179   |  | $            | 1,053 |  | $ | 406
|Operating income |  |                                 | 99  |              |   | 44    |  |              | 151   |  |   | 65 
|Net income       |  |                                 | 75  |              |   | 33    |  |              | 102   |  |   | 41 



Earnings from
unconsolidated investments of $117 million for the nine months ended September 30, 2004 include $123 million from West Coast Power and the $33 million above and gains on the sales of our equity investment in Oyster Creek and Hartwell of $15 million
and $2 million, respectively. These gains were partially



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



offset by a $45 million impairment of our investment in West Coast Power and an $8 million impairment of our Michigan Power equity investment discussed
below, as well as $3 million primarily due to amortization of the difference between the cost of our unconsolidated investments and our underlying equity in their net assets. Earnings from unconsolidated investments of $140 million for the nine
months ended September 30, 2003 consist of $102 million from West Coast Power and the $41 million above, partially offset by $3 million in losses due to impairments of cost investments.



In the third quarter 2004, we sold our unconsolidated investments in the Oyster Creek, Michigan Power and Hartwell
generating facilities for aggregate net cash proceeds of approximately $132 million. During the third quarter 2004, we recognized gains of $15 million and $2 million related to our sales of Oyster Creek and Hartwell, but did not recognize any gain
or loss on the sale of Michigan Power. However, during the nine months ended September 30, 2004, we recorded an impairment on our investment in Michigan Power totaling $8 million, to adjust our book value to the sale price.



In July 2004, we entered into an agreement to sell our unconsolidated
investment in the Commonwealth generating facility. Closing of this transaction, targeted for the fourth quarter 2004, is subject to regulatory and other approvals. Under the terms of this agreement, we do not expect to recognize a material gain or
loss on this sale.



Additionally, in September 2004, we
recorded an impairment of $45 million on our investment in West Coast Power, primarily due to the upcoming expiration of the CDWR contract in December 2004. As the remaining value of the CDWR contract is realized throughout 2004, the fair value of
our investment in West Coast Power has declined. We will continue to evaluate our investment in West Coast Power, and we anticipate that an additional impairment charge may become necessary in the fourth quarter 2004.



Note 6Debt



Revolvers. During the three- and nine-month periods ended September 30, 2004, we reduced an aggregate of
approximately $53 million and $70 million, respectively, of letters of credit under our revolving credit facilities, resulting in a total of $118 million utilized at September 30, 2004. As of September 30, 2004, there were no borrowings outstanding
under our $700 million revolving credit facility. During the period from September 30,2004 through November 8, 2004, we reduced our outstanding letters of credit under this facility by $5 million.



Effective May 28, 2004, we entered into a $1.3 billion credit facility
consisting of:



| |  | a $700 million secured revolving credit facility that matures on May 28, 2007; and
| | - | ----------------------------------------------------------------------------------



| |  | a $600 million secured amortizing term loan that matures on May 28, 2010.
| | - | -------------------------------------------------------------------------



The credit facility replaced our $1.1 billion revolving credit facility, which was scheduled to mature in February 2005.



The revolving credit facility provides funding for general corporate purposes
and is also available for the issuance of letters of credit. Borrowings under the revolving credit facility bear interest, at our option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus 4.00% per annum. A letter of credit fee is payable
on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.00% of such undrawn amount. We also incur additional fees for issuing letters of credit. An unused commitment fee of 0.50% will be payable on the unused
portion of the revolving credit facility.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Of the $600 million in proceeds from the term loan drawn at closing, a portion was used to post cash
collateral in lieu of letters of credit, while approximately $19 million was used to pay upfront fees incurred in connection with the new facility. These fees have been capitalized and are being amortized over the term of the credit facility. In
August 2004, $154 million of the proceeds from the $600 million term loan were used to pre-pay all outstanding indebtedness and other amounts owed in connection with the ABG Gas Supply financing. The remaining proceeds, subject to specified
restrictions in the credit facility, are available for general corporate purposes. Borrowings under the term loan bear interest, at our option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus 4.00% per annum.



The credit facility contains mandatory prepayment events associated with
specified asset sales and recovery events (i.e., certain payments in respect of insurance claims or condemnation proceedings). We must offer to repay the term loan or permanently reduce the revolving credit facility with 100% of the net cash
proceeds of all asset sales or any proceeds from recovery events, excluding (i) proceeds from sales of designated assets and the minority GEN investments currently targeted for sale; (ii) up to $100 million of net cash proceeds from other asset
sales as designated by us; and (iii) up to $900 million of proceeds from asset sales and recovery events that are reinvested in the business, subject to specified restrictions. Sales of assets over a specified threshold require written confirmation
from both Standard & Poors Ratings Service and Moodys Investors Service that the credit ratings of the credit facility will not be lowered as a result. Further, any sale of our Baldwin facility or all or substantially all of our DMS
assets would require the written consent of a majority of the lenders under the new credit facility.



The credit facility provides for no amortization of principal amounts outstanding prior to the maturity dates except (i) upon the occurrence of a
mandatory prepayment event and (ii) term loan amortization of 1% per annum.



The credit facility is secured by substantially the same collateral as the $1.1 billion facility it replaced, including a first priority interest in substantially all our assets and the assets of our subsidiaries and
on substantially all of the equity of our subsidiaries in each case to the extent permitted by other applicable agreements. Dynegy Inc. and substantially all of its subsidiaries also guarantee this facility.



The credit facility contains affirmative and negative covenants, including
negative covenants relating to the following which restrict us and our subsidiaries but do not restrict Dynegy: liens; investments; indebtedness; dispositions; restricted payments; burdensome agreements; amendments to organizational documents;
prepayments of indebtedness; and swap contracts. The credit facility also contains the financial and capital expenditure-related covenants described below. We are currently in compliance with these restrictive covenants, with the exception of our
filing of this report without (i) the requisite review of the accompanying financial statements by our independent auditor and (ii) the certifications mandated by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 and Rule 13a-14 and 15d-14 of
the Securities Exchange Act of 1934, as amended, which may not constitute compliance with our obligation under the indenture to file with the SEC a quarterly report prepared in all material respects in accordance with all of the rules and
regulations applicable thereto. Notwithstanding this possible non-compliance, we expect to file an amendment to this report with the required review and certifications prior to the expiration of the applicable cure period in the indenture.



The credit facility generally prohibits us and our
subsidiaries, subject to specified exceptions, from incurring additional debt. Notwithstanding this restriction, we may issue, to the extent permitted by the more restrictive covenants with respect to secured debt in the indenture governing our
second priority senior secured notes, (i) up to $700 million of additional second lien or junior secured debt or unsecured debt, provided such additional debt matures at least six months after the term loan, and (ii) permitted refinancing
indebtedness.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



The credit facility generally prohibits us and our subsidiaries from pre-paying, redeeming or
repurchasing its outstanding debt or preferred stock. Notwithstanding this restriction, we may pre-pay, repurchase or redeem our remaining 2005 and 2006 senior notes and the Riverside facility. We also may pre-pay, repurchase or redeem our other
senior unsecured notes and our second priority senior secured notes, subject to specified conditions.



Dynegy and its subsidiaries, excluding Illinois Power and its subsidiaries, are also prohibited from (i) permitting our Secured Debt/EBITDA Ratio (as
defined in the credit facility) on and after September 30, 2004 to exceed specified ratios; (ii) permitting our liquidity to be less than $200 million for a period of more than ten consecutive business days; or (iii) making capital expenditures
during each four fiscal quarter period in excess of a designated amount, subject to specified exceptions.



The terms and conditions of the credit facility are described in more detail in the definitive agreements governing the credit facility, which are filed
and/or incorporated by reference as exhibits to our second quarter 2004 Form 10-Q.



Tilton Capital Lease.In September 1999, Illinois Power entered into an operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. This facility
consists of peaking units totaling 176 MWs of capacity. Illinois Power sublet the turbines to DMG in October 1999.



In September 2003, Illinois Power delivered notice of its intent to exercise its option in order for DMG to purchase the turbines upon the expiration of
the operating lease in September 2004. Based on Dynegys and our intent to purchase, GAAP required that we reflect the asset and the associated debt on our balance sheets as a capital lease.



In July 2004, Illinois Power terminated its lease arrangement, and DMG
purchased the turbines for $81 million. This action resulted in a reduction of debt of $78 million. The difference between the purchase price and the debt balance was recorded as an increase to property, plant and equipment of $3 million in our
unaudited condensed consolidated balance sheets and represents the accretion to the end of the term of the original lease agreement.



ABG Gas Supply Credit Agreement.During 2004, we made scheduled payments of approximately $45 million related to our ABG Gas Supply
financing. Additionally, in August 2004, we used $154 million in proceeds from our $600 million term loan to pre-pay all remaining indebtedness and other obligations under our ABG Gas Supply financing as required by the terms of our credit facility.



Note 7Related Party Transactions



We routinely engage in business transactions with subsidiaries of
Dynegy that are not part of our consolidated group. These transactions included among others, sales of energy and capacity to Illinois Power under a power purchase agreement, as well as purchases of natural gas from Illinois power. Please read Note
13Related Party TransactionsOther beginning on page F-37 of our Form 10-K for further discussion. Additionally, we engage in transactions with ChevronTexaco Corporation and its affiliates, including purchases and sales of natural gas and
natural gas liquids, which we believe are executed on terms that are fair and reasonable. Please read Note 13Related Party Transactions beginning on page F-36 of our Form 10-K for further discussion.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Note 8Commitments and Contingencies



Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party
to legal proceedings arising in the ordinary course of business. In managements opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of operations or cash flows.



We record reserves for estimated losses from contingencies
when information available indicates that a loss is probable and the amount of the loss is reasonably estimable under SFAS No. 5. During the first nine months of 2004, we recorded pre-tax legal and settlement charges of $57 million, including cash
payments made in the period in excess of our then-existing accruals. The charges recorded relate to contingencies for which, during the period, either the amount of loss became probable and reasonably estimable or our previous loss estimates were
adjusted.



For environmental matters, we record liabilities
when remedial efforts are probable and the costs can be reasonably estimated. Please read Note 1Accounting PoliciesOther Contingencies for further discussion of our reserve policies. Environmental reserves do not reflect
managements assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the amount of any reserves or potential
insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.



With respect to some of the items listed below, management has determined that a loss is not probable or that any such loss,
to the extent probable, is not reasonably estimable. In some cases, management is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed each of these
matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Managements judgment may, as a result of
facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.



Summary of Recent Developments. As described in greater detail
below, the following significant developments involving our material legal proceedings occurred since the filing of our second quarter 2004 Form 10-Q:



| |  | Dynegy received the final approval from the FERC in October 2004 of the previously announced agreement on a comprehensive settlement of numerous contested FERC claims relating to
western electric energy market transactions that occurred between January 2000 and June 2001. As part of the settlement, West Coast Power will forego its right to collect approximately $259 million in past-due receivables, plus interest, from the
Cal ISO and the Cal PX related to the settlement period and pay $22.5 million in exchange for the dismissal of claims against Dynegy and West Coast Power related to the settlement period.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | The judge presiding over Dynegys shareholder class action lawsuit entered an order in October 2004 dismissing a portion of the claims asserted by the plaintiff and
substantially narrowing the class period to March 2001 through May 2002. Also in October 2004, the plaintiff dismissed its claim relating to a debt offering. The trial has been scheduled to begin in May 2005.
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| |  | Dynegy reached a settlement with the plaintiff in our ERISA class action lawsuit, and the court granted preliminary approval of the settlement agreement in October 2004, scheduling
a fairness hearing for December 2004. Under this proposed settlement, Dynegy would pay the plaintiff $30.75 million for a full and final release of all claims. Dynegy expects to pay this amount using insurance proceeds.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Atlantigas Corporation, which recently dismissed its Maryland federal lawsuit, filed a class action lawsuit in West Virginia state court and filed an amended complaint in October
2004 naming us as a defendant. Plaintiff seeks unspecified compensatory and punitive damages resulting from allegations that, among other things, we conspired with the other defendants to receive preferential natural gas storage and transportation
services at off-tariff prices.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The above
summary of recent developments is qualified in its entirety by, and should be read in conjunction with, the following description of our significant legal proceedings.



Shareholder Litigation. We and Dynegy are defending a class action lawsuit filed on behalf of purchasers of
Dynegys publicly traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit principally asserts that we and Dynegy, certain of our current and former officers and directors violated
the federal securities laws in connection with our disclosures, including accounting disclosures, regarding Project Alpha (a structured natural gas transaction entered into by us in April 2001), round-trip trading, the submission of false trade
reports to publications that calculate natural gas index prices, the alleged manipulation of the California power market and the restatement of our financial statements for 1999-2001. The Regents of the University of California are lead plaintiff
and Lerach Coughlin Stoia & Robbins, LLP is class counsel. The plaintiff filed an amended complaint in January 2004 and, in March 2004, we filed motions to dismiss. Briefing on our motions was completed in June 2004. The judge entered an order
on our motion in October 2004 dismissing all claims brought by the plaintiff under the Securities Act of 1933, except those relating to our March 2001 note offering and December 2001 common stock offering, and the Securities Exchange Act of 1934,
except those dealing with Project Alpha and two alleged round-trip trades. The judge also narrowed the class period to cover purchasers of our publicly traded securities from March 2001 through May 2002 and scheduled the trial to commence in May
2005. Also in October 2004, the plaintiff voluntarily dismissed its claim under the Securities Act of 1933 relating to our March 2001 note offering. An adverse result in this litigation could have a material adverse effect on our financial
condition, results of operations and cash flows. Reserves have been provided in connection with this litigation.



In addition, Dynegy is a nominal defendant in several derivative lawsuits brought by shareholders on Dynegys behalf against certain of its former
officers and current and former directors whose claims are similar to those described above. These lawsuits have been consolidated into two groupsone pending in federal court and the other pending in state court. A motion to dismiss the
federal derivative claim is currently pending and is set for hearing in January 2005. We do not expect to incur any material liability with respect to these claims.



ERISA/401(k) Litigation. Dynegy is defending a purported class action complaint filed in federal district
court on behalf of participants holding Dynegy common stock in the Dynegy 401(k) Savings Plan during the period from April 1999 to January 2003. This complaint alleges violations of ERISA in connection with Dynegys 401(k) Savings Plan,
including claims that Dynegys Board and certain of Dynegys former and current officers, past and present members of Dynegys Benefit Plans Committee, former employees who served on a predecessor committee to its Benefit Plans
Committee, and Vanguard Fiduciary Trust Company and CG Trust Company (trustees of the trust that held Plan assets for portions of the class period) breached their fiduciary duties to the Plans participants and beneficiaries in connection with
the Plans investment in Dynegy common



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stockin particular with respect to Dynegys financial statements, Project Alpha, round-trip trades and gas price index reporting. The lawsuit
seeks unspecified damages for the losses to the Plan, as well as attorneys fees and other costs. In July 2003, Dynegy filed a motion to dismiss this action. The judge entered an order on this motion in March 2004, dismissing several of the
plaintiffs claims and all of the defendants except Dynegy and the members of its Benefit Plans Committee from January 2002 to January 2003, the substantially reduced class period established by the order. In May 2004, in response to the
plaintiffs request, the judge ordered the parties to engage in mediation. The parties mediated for two months, and ultimately reached a settlement under which the defendants agreed to pay $30.75 million to the plaintiff for a full and final
release of all claims. This amount falls within Dynegys applicable insurance limits, and Dynegy expects that the settlement will be paid by insurance proceeds. The Court granted preliminary approval of the settlement agreement in October 2004,
tentatively scheduling a fairness hearing for December 2004 at which class members can participate and file any objections. We cannot predict with certainty what actions the Court may take in response to objections raised at the fairness hearings
or, in the event the settlement is ultimately rejected, whether we will incur any liability, nor can we estimate the damages, if any, that might be incurred in connection with this lawsuit absent the proposed settlement. In any case, we do not
believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Baldwin Station Litigation. Illinois Power and DMG are the subject of an NOV from the EPA and a complaint
filed by the EPA and the Department of Justice in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations. Similar notices and complaints were filed against other owners of coal-fired power plants
in what we refer to as the Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at our three Baldwin Station generating units constituted major
modifications under the PSD regulations, the NSPS regulations and applicable Illinois regulations, and that we failed to obtain required operating permits under applicable Illinois regulations. When activities which are not otherwise exempt
result in an increase in annual emissions that exceeds the amount deemed significant under the PSD regulations, those activities are considered major modifications. When activities meeting this definition occur, the Clean Air Act and
related regulations generally subject those activities to PSD review and permit requirements and require that the generating facilities where the activities occur meet more stringent emissions standards, which may entail the installation of
potentially costly pollution control equipment.



We have
significantly reduced emissions of sulphur dioxide and nitrogen oxides at the Baldwin Station since the 1999 complaint by converting it from high to low sulfur coal and installing selective catalytic reduction equipment. However, the EPA may seek to
require the installation of the best available control technology, or the equivalent, at the Baldwin Station, which we estimate could require us to incur capital expenditures of up to $410 million. The EPA also has the authority to seek
penalties for the alleged violations at the rate of up to $27,500 per day for each violation.



In February 2003, the Court granted our motion for partial summary judgment based on the five-year statute of limitations. As a result, the EPA is not permitted to seek any monetary civil penalties for claims related
to construction without a permit under the PSD regulations. The Courts ruling also precludes monetary civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. We believe that we have
meritorious defenses against the remaining claims and vigorously defended against them at trial. The trial to resolve claims of liability began in June 2003 and closing arguments occurred in September 2003. Shortly after closing arguments, several
interveners were granted the right to file briefs in support of arguments they believe the United States ceased to pursue.



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In October 2004, following the closing of the Illinois Power sale, Ameren caused Illinois Power to
file a motion to stay the proceedings and to request a status conference in order to present its position on the claims asserted against it. These interventions, delays in post-trial briefing and the recent Illinois Power motion have postponed the
issuance of the liability order, and we cannot predict with certainty when a decision will be rendered. Reserves have been provided in an aggregate amount we consider reasonable for potential penalties that could be imposed if the Court finds us
liable and the EPA prosecutes successfully the remaining claims for penalties.



In August 2003, two significant decisions were handed down in other cases that are part of the Utility Enforcement Initiative. The court in United States v. Ohio Edison applied the EPAs narrow
interpretation of the routine maintenance, repair and replacement exclusion, which defines it with respect to what is routine for the specific unit where the projects occurred, while the court in United States v. Duke Energy
Company rejected the EPAs narrow interpretation, holding that the exclusion should be defined relative to what is routine for the particular industry. The Duke court also held that the hours and conditions of a units
operations must be held constant when measuring emissions increases. Under this rationale, an increase in maximum hourly emissions is required before activities would be considered major modifications. We are unable to predict the
significance of these cases to our Baldwin Station litigation as they are pending in other jurisdictions and are not binding authority.



None of our other facilities are covered in the complaint and NOV, but the EPA previously requested information, which we provided, concerning activities
at our Vermilion, Wood River, Hennepin, Danskammer and Roseton plants. Although the EPA could eventually commence enforcement actions based on activities at these plants, we are unable to assess the likelihood of any such additional EPA enforcement
actions.



California Market Litigation. We and/or
Dynegy and numerous other power generators and marketers are the subject of numerous lawsuits arising from our participation in the western power markets during the California energy crisis. Eight of these lawsuits, which primarily allege
manipulation of the California wholesale power markets and seek unspecified treble damages, were consolidated before a single federal judge. That judge dismissed two of the cases in the first quarter 2003 on the grounds of FERC preemption and the
filed rate doctrine. The Ninth Circuit Court of Appeals affirmed these dismissals in June 2004 and September 2004, respectively. An appeal from the Ninth Circuits affirmation of the September 2004 dismissal has been taken to the United States
Supreme Court. Regarding the remaining six consolidated cases, we are awaiting a ruling from the Ninth Circuit, which we expect to occur prior to the end of 2004, on our appeal of a prior decision to remand those cases to state court.



In addition to the eight consolidated lawsuits discussed above, nine other
putative class actions and/or representative actions were filed in state and federal court on behalf of business and residential electricity consumers against us and/or Dynegy and numerous other power generators and marketers between April and
October 2002. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek an injunction, restitution and unspecified damages. While some of the allegations in these lawsuits
are similar to the allegations in the eight lawsuits described above, these lawsuits include additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. The court dismissed eight
of these nine actions, although the plaintiffs have appealed, and the briefing on that appeal was completed in October 2004. A hearing on the appeal is scheduled for December 2004. The ninth case was remanded to state court, where a newly added
defendant filed a motion in February 2004 to remove the case back to federal court. In September 2004, the court requested additional briefing on the remand issue, and the parties are complying with that request. Once a decision is made on this
motion, we intend to file a motion to dismiss this case.



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In December 2002, two additional actions were filed with similar allegations on behalf of residents
of Washington and Oregon. In May 2003, the plaintiffs voluntarily dismissed these actions and refiled them in California Superior Court as a class action complaint. The complaint, which was brought on behalf of consumers and businesses in Oregon,
Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleges violations of the Cartwright Act and unfair business practices. This action has been removed from state court and consolidated
with existing actions pending before the United States District Court for the Northern District of California. The hearing on plaintiffs appeal to remand to state court occurred in February 2004. The judge stayed his ruling on the appeal
pending the Ninth Circuits ruling on the six consolidated cases referenced above.



In May 2004, Wah Chang, a division of TDY Industries, Inc., filed suit in Oregon federal court against several energy companies, including Dynegy Power
Marketing, Inc., seeking more than $30 million in compensatory damages resulting from alleged manipulation of the California wholesale power markets. We filed a motion to dismiss this lawsuit in October 2004.



In June 2004, the City of Tacoma public utility filed a lawsuit in Washington
federal court against a number of energy companies, including us, alleging it paid inflated prices for electricity due to the defendants manipulation of the California wholesale power markets. The Court has not yet set a schedule for this
matter.



In July 2004, the County of Santa Clara and the County
and City of San Francisco filed two separate actions in California state court against us and several other defendants alleging that the defendants violated Californias anti-trust and deceptive business practices statutes by manipulating the
California wholesale power markets through, among other things, providing false information to gas index publications and engaging in multiple transactions in a short period of time to artificially inflate gas prices. In September 2004, these cases
were consolidated into the In re Western States Wholesale Natural Gas Anti-Trust Litigation. Please read Gas Index Pricing Litigation below for further discussion.



In September 2004, Dan Older, a retail consumer of natural gas, filed a
purported class action against us and several other energy company defendants and utilities alleging that plaintiff paid artificially inflated prices as a result of the defendants illegal conduct. The plaintiffs complaint raises
allegations similar to those described in the preceding paragraph. Plaintiff seeks unspecified compensatory damages, as well as treble damages. In September 2004, this case was consolidated into the In re Western States Wholesale Natural Gas
Anti-Trust Litigation. Please read Gas Index Pricing Litigation below for further discussion.



In October 2004, Preferred Energy Services, an independent electric services provider in California, filed suit against us and several other defendants
alleging that the defendants, in violation of the California anti-trust and unfair business practices statutes, engaged in unfair, unlawful and deceptive practices in the California wholesale energy market from May 2000 through December 2001.
Plaintiff, which formerly sold electricity generated from renewable sources in the California market, claims to have been forced out of business by the defendants conduct and is seeking $5 million in compensatory damages, as well as treble
damages. We have not yet been served with this lawsuit.



In
November 2004, each of Nurserymens Exchange, Inc., School Project for Utility Rate Reduction and the County of Alameda, California served Dynegy with lawsuits alleging price fixing, unfair competition and unjust enrichment arising from, among
other things, the provision of false information to gas index publications which inflated the retail prices for intra-state gas sales. We anticipate that these cases will be consolidated into the In re Western States Wholesale Natural Gas
Anti-Trust Litigation referenced above.



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We believe that we have meritorious defenses to these claims and intend to defend against them
vigorously. We cannot predict with certainty whether we will incur any liability or estimate the range of possible loss, if any, that we might incur in connection with these lawsuits. However, given the nature of the claims, an adverse result in any
of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.



FERC and Related Regulatory InvestigationsRequests for Refunds. In October 2004, the FERC approved in all respects the agreement
announced by Dynegy and West Coast Power in April 2004 which provides for the settlement of FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001, including:



| |  | the FERCs June 2003 order to show cause why the activities of certain participants in the California power markets from January 2000 to June 2001, including Dynegy, did not
constitute gaming and/or anomalous market behavior as defined in the Cal ISO and Cal PX tariffs, which matter was resolved by the January 2004 settlement providing that West Coast Power will pay approximately $3 million into a fund for the benefit
of California and Western electricity consumers. This January 2004 settlement has been incorporated into the broader settlement described below; and
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the FERCs July 2001 hearings and October 2003 orders relating to the establishment of (i) refunds to electricity customers, or offsets against amounts owed to electricity
suppliers, during the period of October 2000 through June 2001 and (ii) a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The parties to this settlement other than Dynegy and West Coast Power include the FERC, Pacific Gas and Electric Company,
Southern California Edison, San Diego Gas & Electric Company, the CDWR, the California Electricity Oversight Board and the California Attorney General. Other market participants may opt into this settlement and share in the distribution of the
settlement proceeds. As part of the settlement agreement, West Coast Power will (i) forego its right to collect approximately $259 million in past-due receivables, plus interest, from the Cal ISO and the Cal PX related to the settlement period, (ii)
forego natural gas cost recovery claims against the California settling parties related to the settlement period, and (iii) place into escrow accounts a total of $22.5 million, which includes the above-referenced $3 million settlement with the FERC
staff, for subsequent distribution to various California energy purchasers. In exchange, the other settling parties will forego (i) all claims relating to refunds or other monetary damages for sales of electricity during the settlement period, and
(ii) claims alleging receipt of unjust or unreasonable rates for the sale of electricity during the settlement period.



The settlement does not apply to the ongoing civil litigation related to the California energy markets described above in which we and/or Dynegy and West
Coast Power are defendants. The settlement also does not apply to the pending appeal by the CPUC and the California Electricity Oversight Board of the FERCs prior decision to affirm the validity of the West Coast Power-CDWR contract. We are
currently awaiting a ruling on this appeal and related filings and cannot predict their outcome.



West Coast Power. Through our interest in West Coast Power, we have credit exposure for transactions to the Cal ISO, which rely on cash
payments from California utilities to in turn pay their bills. In addition, West Coast Power currently sells directly to the CDWR pursuant to a long-term sales agreement which expires at the end of December 2004.



At September 30, 2004, our portion of the receivables owed to West Coast
Power by the Cal ISO and Cal PX approximated $214 million. Management periodically assesses our exposure through West Coast Power,



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relative to our California receivables and establishes and maintains reserves under SFAS 5. Our share of the total reserve taken by West Coast Power, at
September 30, 2004, with respect to receivables arising during the settlement period from January 2000 through June 2001 was approximately $194 million. The approval by the FERC in October 2004 of the above-described settlement resolved the claims
and disputes which initially gave rise to this reserve at West Coast Power.



Enron Trade Credit Litigation. Shortly before their bankruptcy filing in the fourth quarter 2001, we determined that Enron Corp. and its affiliates had net exposure to us, including certain liquidated
damages and other amounts relating to the termination of commercial transactions among the parties, of approximately $84 million. This exposure was calculated by setting off approximately $230 million owed from Dynegy entities to Enron entities
against approximately $314 million owed from Enron entities to Dynegy entities. The master netting agreement between Enron and us and the valuation of the commercial transactions covered by the agreement, which valuation is based principally on the
parties assessment of market prices for such period, remain subject to dispute by Enron. We are engaged in an ongoing process with Enron to reconcile the differences between our respective valuations of the transactions and accounts
receivable. As a result of ongoing refinement of the values of past transactions, we reduced the $84 million amount that we originally believed we are owed by Enron to approximately $41 million, including the liabilities under the gas transportation
agreement related to the Sithe Independence power tolling arrangement. This change in value had no impact on our results, as the net receivable was fully reserved in the fourth quarter 2001. As required by the master netting agreement, we instituted
arbitration proceedings against those Enron parties not in bankruptcy in 2002 and filed a motion with the Bankruptcy Court requesting that we be allowed to proceed to arbitration against those Enron parties that are in bankruptcy. The Enron parties
opposed our request and filed an adversary proceeding against us, alleging that the master netting agreement should not be enforced and that the Enron companies should recover approximately $230 million from us. We have disputed such allegations and
are vigorously defending our position regarding the setoff rights contained in the master netting agreement, although the Bankruptcy Court has yet to rule on the enforceability of the master netting agreement.



In November 2003, we gave notice of our intent to pursue arbitration against
Enron Canada Corp. as a non-bankrupt party to the master netting agreement. In response, Enron Canada Corp. filed a lawsuit in Canadian District Court to recover the amounts that it claims to be owed by our Canadian subsidiary under the master
netting agreement, contingent upon a Bankruptcy Court ruling on the enforceability of the master netting agreement. In December 2003, Enron filed an application with the Bankruptcy Court for an injunction to prohibit this arbitration; the Bankruptcy
Court ruled that the automatic stay of the bankruptcy applied to our request to pursue arbitration against Enron Canada Corp. under the master netting agreement. Consequently, we are currently prohibited from enforcing the master netting agreement
by arbitration. In March 2004, we appealed the enforcement of the automatic stay and requested permission from the appellate court to proceed with arbitration against Enron Canada Corp. We also filed a motion with the Bankruptcy Court requesting a
trial to determine the enforceability of the master netting agreement under the U.S. Bankruptcy Code. We are currently awaiting rulings on the appeal and the motion. The Bankruptcy Court has ordered the parties to a second mediation, which is
scheduled to occur in November 2004.



If the setoff rights are
modified or disallowed, either by agreement or otherwise, the amount available for our entities to set off against sums that might be due Enron entities could be reduced materially. In fact, we could be required to pay to Enron the full amount that
it claims to be owed, while we would be an unsecured creditor of Enron to the extent of our claim. We cannot predict with certainty whether we will incur any liability in connection with these disputes. However, given the size of the claims at
issue, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.



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Severance Arbitrations. Dynegys former CEO, Chuck Watson, former President, Steve
Bergstrom, and former CFO, Rob Doty, each filed for arbitration pursuant to the terms of their employment/severance agreements. These former officers made arbitration claims seeking payments of up to approximately $28.7 million, $10.4 million and
$3.4 million, respectively. In May 2004, following arbitration, Dynegy paid Mr. Bergstrom $10.4 million plus attorneys fees, costs and interest in accordance with the arbitration panels decisions. Shortly after the panels decisions
in the Bergstrom matter and following mediation, Dynegy paid Mr. Watson $22 million to settle his severance claims. We recorded an expense in the second quarter 2004 in the amount of the difference between this settlement amount and our severance
accrual for this matter. Please read Note 3Restructuring Charges for further discussion regarding the accrual relating to Mr. Watson.



The arbitration with respect to Mr. Doty is scheduled to commence in May 2005. Mr. Dotys agreement is subject to interpretation and Dynegy maintains
that the amount owed is substantially lower than the amount sought. We recorded a severance accrual we consider reasonable relating to this proceeding.



Farnsworth Litigation. In August 2002, Bradley Farnsworth filed a lawsuit against Dynegy in state court claiming breach of contract and that
he was demoted and ultimately fired from the position of Controller for refusing to participate in illegal activities. Specifically, Mr. Farnsworth alleged, in the words of his amended complaint, that certain of Dynegys former executive
officers requested that he shave or reduce for accounting purposes the forward price curves associated with the natural gas business in the United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a
reduction in our mark-to-market losses. In March 2004, the judge dismissed Mr. Farnsworths claim that he was asked to shave forward price curves. Under his remaining breach of contract claim, Mr. Farnsworth alleges he is entitled
to a termination payment under his employment agreement, which he estimates at $11 million, equal to 2.99 times the greater of his average base salary and incentive compensation for the highest three calendar years preceding termination or his base
salary and target bonus amount for the year of termination. The agreement is subject to interpretation and we maintain that the amount owed is substantially lower than the amount sought. Trial on the breach of contract claim is scheduled to commence
in November 2004. We are defending this claim vigorously. Although reserves have been provided with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect
on our financial condition, results of operations or cash flows.



Apache Litigation. In May 2002, Apache Corporation filed suit in state court against Versado, as purchaser and processor of Apaches gas, and DMS, as operator of the Versado assets in New Mexico, seeking more than $9
million in damages. The plaintiffs petition, as amended, alleges (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that Versado engaged in sham transactions with affiliates, resulting in Versado not
receiving fair market value when it sells gas and liquids, and (iii) that the formula for calculating the amount Versado receives from its buyers of gas and liquids is flawed since it is based on gas price indexes that these same affiliates are
alleged to have manipulated by providing false price information to the index publisher. At trial, the plaintiffs claim with respect to the alleged sham transactions and index manipulation, among others, were severed by the court
and abated for a future trial, and the jury found in favor of the plaintiff on the remaining lost gas claim, awarding approximately $1.6 million in damages. In May 2004, our motion to set aside this judgment was granted by the court and the
jurys award to the plaintiff was vacated. The plaintiff filed its appeal with the court in October 2004. We do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial
condition, results of operations or cash flows.



Gas
Index Pricing Litigation. We are defending the following suits claiming damages resulting from the alleged manipulation of gas index publications and prices by us and others: Sierra Pacific Resources and Nevada



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Power Company v. El Paso Corp. et al.; Bustamante v. The McGraw Hill Companies et al.; In re Natural Gas Commodity Litigation (a
consolidation of two cases); People of the State of Montana et al. v. Williams Energy Marketing et al; In re Western States Wholesale Natural Gas Anti-Trust Litigation(a consolidation of seven cases); and Nelson Brothers LLC v.
Cherokee Nitrogen v. Dynegy Marketing and Trade and Dynegy Inc.In each of these suits, the plaintiffs allege that we and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to gas
index publications, thereby manipulating the price. All of the complaints rely heavily on the FERC and CFTC investigations into and report concerning index-reporting manipulation in the energy industry. The plaintiffs generally seek unspecified
actual and punitive damages relating to costs they claim to have incurred as a result of the alleged conduct. These cases are in varying procedural stages, although we have not been served in the Montana case.



We are analyzing all of these claims and intend to defend against them
vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with these lawsuits. We do not believe that any liability that we might incur as a result of
this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Atlantigas Corp. Litigation. In November 2003, Atlantigas Corporation filed suit in Maryland against us and several other defendants
alleging certain conspiracies between natural gas shippers and storage facilities. The complaint alleged that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate in return
for percentages of the profits reaped by the marketing affiliate and that such conduct violated applicable FERC regulations and the federal antitrust laws and constituted common law tortious interference with contractual and business relations. In
addition, the complaint claimed we conspired with the other defendants to receive preferential natural gas storage and transportation services at off-tariff prices. The complaint sought unspecified compensatory and punitive damages. In January 2004,
the defendants filed motions to dismiss the plaintiffs claims. In July 2004, prior to the Courts ruling on the defendants motions, the plaintiff voluntarily dismissed the Maryland federal court action against all defendants.
Shortly thereafter, plaintiff filed a class action lawsuit in a West Virginia state court against several defendants, excluding us, on similar grounds to the previous Maryland federal action. In October 2004, the plaintiff filed an amended class
action complaint naming us as a defendant in the litigation. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that
might be incurred in connection with these lawsuits. We do not believe that any liability that we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Alleged Marketing Contract Defaults. We have
posted collateral to support a portion of our obligations in our CRM business, including our obligations under one of our power tolling arrangements. While we worked with various counterparties to provide mutually acceptable collateral or other
adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral in support of our obligations under our power tolling
arrangements with either of these two parties. Although we are current on all contract payments to these counterparties, we previously received a notice of default from each such party with regard to collateral. Despite receiving these notices, all
parties are continuing to perform and we have fulfilled our economic commitments under these contracts. Our average annual capacity payments under these two arrangements approximate $75 million and $63 million, respectively, and the contracts extend
through 2014 and 2012, respectively, with a five-year extension option for Sterlington. If these two parties were successfully to pursue claims that we defaulted on these contracts, they could declare a termination of their respective contracts,
which generally



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Ended September 30, 2004 and 2003



provide for termination payments based on the agreed mark-to-market value of the contracts. Because of the effects of changes in commodity prices on the
mark-to-market value of these contracts, as well as the likelihood that we would differ with our counterparties as to the estimated value of these contracts, we cannot predict with any degree of certainty the amounts of termination payments that
could be required under these two contracts. Disputes relating to these two contracts, if resolved against us, could materially adversely affect our financial condition, results of operations and cash flows.



U.S. Attorney Investigations. The U.S. Attorneys office
in Houston is continuing its investigation of our actions relating to Project Alpha and our gas trade reporting practices. We have produced documents and witnesses for interviews in connection with this investigation. Seven of our natural gas
traders were terminated in the fourth quarter 2002 for violating our Code of Business Conduct after an ongoing internal investigation conducted by Dynegys Audit and Compliance Committee in collaboration with independent counsel discovered that
inaccurate information regarding natural gas trades had been reported to various energy industry publications. In January 2003, one of our former natural gas traders was indicted in Houston on three counts of knowingly causing the transmission of
false trade reports used to calculate the index price of natural gas and four counts of wire fraud. In August 2003, however, several of these counts were dismissed as unconstitutional. Upon request by the U.S. Attorneys office for
reconsideration of this ruling, the judge reinstated the dismissed counts. The case was originally set for trial in January 2004; however, both the U.S. Attorneys office and the defense have appealed the courts rulings regarding the
dismissed and reinstated charges. The Fifth Circuit Court of Appeals heard argument on these matters in October 2004, and the parties are awaiting its ruling.



In June 2003, three former Dynegy employees were indicted on charges of conspiracy, securities fraud and mail and wire fraud related to the Project
Alpha transaction. Subsequently, two of these former employees plead guilty to conspiracy to commit securities fraud. These former employees have not been sentenced pending the completion of the governments investigation. Trial on the
indictment against the third employee was held in November 2003. The defendant was convicted on all charges and, in March 2004, sentenced to a term of approximately 24 years in federal prison.



We are cooperating fully with the U.S. Attorneys office in its
continuing investigation of these matters and cannot predict the ultimate outcome of these investigations.



Additionally, the United States Attorneys office in the Northern District of California has issued a Grand Jury subpoena requesting information
related to our activities in the California energy markets in November 2002. We have been, and intend to continue, cooperating fully with the U.S. Attorneys office in its investigation of these matters, including production of substantial
documents responsive to the subpoena and other requests for information. We cannot predict the ultimate outcome of this investigation.



Department of Labor Investigation. In August 2002, the U.S. Department of Labor commenced an official investigation pursuant to Section 504
of ERISA with respect to the benefit plans maintained by Dynegy and its ERISA affiliates. Dynegy has cooperated with the Department of Labor throughout this investigation, which remains ongoing. As of this date, the investigation has focused on a
review of plan documentation, plan reporting and disclosure, plan recordkeeping, plan investments and investment options, plan fiduciaries and third-party service providers, plan contributions and other operational aspects of the plans. The
Department of Labor has not yet provided definitive findings resulting from its investigation.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Note 9Regulatory Issues



We are subject to regulation by various federal, state, local and foreign agencies, including extensive rules and
regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and
administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations. In addition, the United States Congress
has before it a number of bills that could impact regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these bills or other regulatory developments or the effects that they might have on our
business.



Danskammer Water Permit. As previously
disclosed, the state-issued water intake and discharge permit associated with our Danskammer facility expired in 1992. However, under New York State law, each permit remains in effect and allows for continued operation under the terms of the
original permit, provided that a timely and sufficient application requesting renewal has been filed as required. In May 1992, the then owner of the Danskammer facility filed a renewal application which we believe was timely and sufficient.



In November 2002, several environmental groups filed suit in
the Supreme Court of the State of New York seeking, among other things, a declaratory judgment that the Danskammer water intake and discharge permit expired because of alleged deficiencies in the renewal application process. In September 2004, the
Court ruled that the water intake and discharge permit for our Danskammer facility is void, but stayed the enforcement of the decision pending further review by the Court or by the Appellate Division.



In October 2004, we filed our appeal of the Courts decision with the
Appellate Division, and we intend to pursue vigorously our challenge to the Courts ruling voiding our permit. We will also continue to seek approval of our application to renew the water intake and discharge permit in proceedings before the
New York State Department of Environmental Conservation. If our appeal is ultimately unsuccessful, we may be required to curtail operations at our Danskammer facility pending receipt of final approval of the renewal of our water intake and discharge
permit. We cannot predict with any certainty the outcome of these proceedings; however, an adverse outcome, particularly a requirement that we curtail operations at our Danskammer facility for any period of time, could have a material adverse effect
on our financial condition, results of operations and cash flows.



FERC Market-Based Rate Authority. Market-based rate authority allows the sale of power at negotiated rates through the bilateral market or within an organized energy market. In April 2004, the FERC issued an order concerning
the ability of companies to sell electricity at market-based rates. In this order, the FERC adopted two new tests for assessing generation market power. If an applicant for market-based rate authority is found to possess generation market power
under these tests and is unsuccessful in challenging that finding, the applicant may either propose mitigation measures or adopt cost-based rates. If the FERC finds that the proposed mitigation measures fail to eliminate the ability to exercise
market power, the applicants market-based rate authority will be revoked and the applicant will be subject to cost-based default rates, or other cost-based rates proposed by the applicant and approved by the FERC. The FERC issued a follow up
order in May 2004, which (i) addressed the implementation process for pending and new market-based rate applications and (ii) established a timeline for entities with FERC market-based rate authority to provide the FERC with their market power
assessment. Despite challenges from numerous industry participants, in July 2004 the FERC upheld the April 2004 order. These orders require entities that were previously granted market-based rate authority by the FERC, including several of our
entities with applications pending since February 2002, to resubmit their market power applications in accordance with the new directive by February 5, 2005. Although we cannot predict with any



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



certainty whether these applications will be approved or the loss of revenues that would result from the imposition of cost-based rates, an adverse outcome
with respect to these applications, and the resulting requirement that we charge cost-based rates, could have a material adverse effect on our financial condition, results of operations and cash flows.



Note 10Employee Compensation, Savings and Pension Plans



We have various defined benefit pension plans and post-retirement benefit
plans, which are more fully described in Note 19Employee Compensation, Savings and Pension Plans beginning on page F-53 of our Form 10-K.



Components of Net Periodic Benefit Cost.The components of net periodic benefit cost were:



|                                              |  |                                  |      |   |                |   |      |      |  |      |     |  |   |      |  
|--------------------------------------------- |  | -------------------------------- | ---- | - | -------------- | - | ---- | ---- |  | ---- | --- |  | - | ---- | -
|                                              |  | Pension Benefits                 |      |   | Other Benefits |  
|                                              |  | Three Months Ended September 30, |     
|                                              |  | 2004                             |      |   | 2003           |   |      | 2004 |  | 2003 |    
|                                              |  | (in millions)                    |     
|Service cost benefits earned during period    |  | $                                | 1.8  |   |                | $ | 1.7  |      |  | $    | 0.2 |  | $ | 0.3  |  
|Interest cost on projected benefit obligation |  |                                  | 1.0  |   |                |   | 1.0  |      |  |      | 0.2 |  |   | 0.1  |  
|Expected return on plan assets                |  |                                  | (0.7 | ) |                |   | (0.6 | )    |  |      |    |  |   |     |  
|Recognized net actuarial (gain) loss          |  |                                  | 0.3  |   |                |   |     |      |  |      | 0.1 |  |   | (0.1 | )
|                                              |  |                                  |      |   |                |   |      |      |  |      |     |  |   |      |  
|Total net periodic benefit cost               |  | $                                | 2.4  |   |                | $ | 2.1  |      |  | $    | 0.5 |  | $ | 0.3  |  
|                                              |  |                                  |      |   |                |   |      |      |  |      |     |  |   |      |  
|                                              |  |                                 
|                                              |  | Pension Benefits                 |      |   | Other Benefits |  
|                                              |  | Nine Months Ended September 30,  |     
|                                              |  | 2004                             |      |   | 2003           |   |      | 2004 |  | 2003 |    
|                                              |  | (in millions)                    |     
|Service cost benefits earned during period    |  | $                                | 6.0  |   |                | $ | 5.5  |      |  | $    | 0.6 |  | $ | 0.5  |  
|Interest cost on projected benefit obligation |  |                                  | 2.8  |   |                |   | 2.4  |      |  |      | 0.6 |  |   | 0.5  |  
|Expected return on plan assets                |  |                                  | (1.9 | ) |                |   | (1.8 | )    |  |      |    |  |   |     |  
|Recognized net actuarial loss                 |  |                                  | 0.7  |   |                |   | 0.2  |      |  |      | 0.1 |  |   | 0.1  |  
|                                              |  |                                  |      |   |                |   |      |      |  |      |     |  |   |      |  
|Total net periodic benefit cost               |  | $                                | 7.6  |   |                | $ | 6.3  |      |  | $    | 1.3 |  | $ | 1.1  |  
|                                              |  |                                  |      |   |                |   |      |      |  |      |     |  |   |      |  



Contributions.In Note 19Employee Compensation, Savings and Pension PlansContributions beginning on page F-57 of our Form 10-K, we reported that we expected to contribute approximately $1 million to our pension and other postretirement benefit
plans in 2004. However, under the terms of Dynegys agreement to sell Illinois Power to Ameren, we accelerated approximately $7 million of future cash funding requirements in September 2004.



Note 11Income Taxes



Prior Year Tax Audits.In the second quarter 2004, we
recognized an expense of $17 million associated with the conclusion of prior year federal tax audits. A charge of $20 million related to our discontinued U.K. CRM business is included in Loss from discontinued operations on our unaudited condensed
consolidated statements of operations for the nine months ended September 30, 2004. An offsetting benefit of $3 million is reflected in Income tax benefit (expense) on our unaudited condensed consolidated statements of operations.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Note 12Segment Information



We report our operations in the following segments: GEN, NGL and CRM. All direct general and administrative expenses and
other income (expense) items incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred.



Prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business,
referred to as the WEN segment. Most, but not all, of the WEN third-party purchase and sale contracts were held by a subsidiary that became part of the CRM segment. When we began reporting results for the GEN and CRM segments, CRM continued to
transact with third parties on behalf of GEN. When transacting on behalf of GEN and our other segments, CRM would record third party revenue related to GEN and our other segments, together with its other third-party marketing and trading positions
unrelated to our other segments. Transfer pricing between CRM and our other segments was set at the actual amount received or paid for the purchases and sales to the third parties. Therefore, our other segments intersegment revenues included the
effects of intra-month market price volatility, and represented amounts actually received from or paid to third parties.



Effective July 1, 2004, GEN began transacting directly with third parties on its own behalf. Therefore, certain generation capacity, forward sales, and
related market positions previously sold by GEN to CRM are now sold by GEN directly to third parties. The GEN segment now records revenues for such third party sales as unaffiliated revenues.



Pursuant to EITF Issue 02-03, all gains and losses on third-party
energy-trading contracts in the CRM segment, whether realized or unrealized, are presented net in the unaudited condensed consolidated statements of operations. For the purpose of the segment data presented below, intersegment transactions between
CRM and our other segments are presented net in CRM intersegment revenues but are presented gross in the intersegment revenues of our other segments, as the activities of our other segments are not subject to the net presentation requirements
contained in EITF Issue 02-03. If transactions between CRM and our other segments result in a net intersegment purchase by CRM, the net intersegment purchases and sales are presented as negative revenues in CRM intersegment revenues. In addition,
intersegment hedging activities are presented net pursuant to SFAS No. 133.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Reportable segment information for the three- and nine-month periods ended September 30, 2004 and
2003 is presented below:



Dynegys Segment Data for the
Quarter Ended September 30, 2004

(in millions)



|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|----------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | --- | - |  | - | ------ | -
|                                                |  | GEN |       |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |    
|Unaffiliated revenues:                          |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Domestic                                        |  | $   | 273   |   |     | $ | 920   |     |  | $ | 94                    |   |  | $     |    |   |  | $ | 1,287  |  
|Other                                           |  |     |      |   |     |   |      |     |  |   | (14                   | ) |  |       |    |   |  |   | (14    | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|                                                |  |     | 273   |   |     |   | 920   |     |  |   | 80                    |   |  |       |    |   |  |   | 1,273  |  
|Affiliated revenues                             |  |     | 114   |   |     |   |      |     |  |   |                      |   |  |       |    |   |  |   | 114    |  
|Intersegment revenues                           |  |     | 42    |   |     |   | 76    |     |  |   | (71                   | ) |  |       | (47 | ) |  |   |       |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Total revenues                                  |  | $   | 429   |   |     | $ | 996   |     |  | $ | 9                     |   |  | $     | (47 | ) |  | $ | 1,387  |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Depreciation and amortization                   |  | $   | (50   | ) |     | $ | (21   | )   |  | $ | (1                    | ) |  | $     | (6  | ) |  | $ | (78    | )
|                                                |  |     |       |   |    
|Operating income (loss)                         |  | $   | 71    |   |     | $ | 72    |     |  | $ | (32                   | ) |  | $     | (54 | ) |  | $ | 57     |  
|Earnings from unconsolidated investments        |  |     | 23    |   |     |   | 3     |     |  |   |                      |   |  |       |    |   |  |   | 26     |  
|Other items, net                                |  |     |      |   |     |   | (6    | )   |  |   | (3                    | ) |  |       | (1  | ) |  |   | (10    | )
|Interest expense                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (85    | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Loss from continuing operations before taxes    |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (12    | )
|Income tax benefit                              |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | 6      |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Loss from continuing operations                 |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (6     | )
|Loss from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (2     | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Net loss                                        |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  | $ | (8     | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Identifiable assets:                            |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Domestic                                        |  | $   | 5,181 |   |     | $ | 1,708 |     |  | $ | 1,737                 |   |  | $     | 876 |   |  | $ | 9,502  |  
|Other                                           |  |     |      |   |     |   | 4     |     |  |   | 754                   |   |  |       | 8   |   |  |   | 766    |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Total                                           |  | $   | 5,181 |   |     | $ | 1,712 |     |  | $ | 2,491                 |   |  | $     | 884 |   |  | $ | 10,268 |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Unconsolidated investments                      |  | $   | 373   |   |     | $ | 78    |     |  | $ |                      |   |  | $     |    |   |  | $ | 451    |  
|Capital expenditures                            |  | $   | (20   | ) |     | $ | (14   | )   |  | $ |                      |   |  | $     | (5  | ) |  | $ | (39    | )



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Dynegys Segment Data for the Quarter Ended September 30, 2003

(in millions)



|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | --- | - |  | - | ------ | -
|                                                  |  | GEN |       |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |    
|Unaffiliated revenues:                            |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Domestic                                          |  | $   | 65    |   |     | $ | 620   |     |  | $ | 325                   |   |  | $     |    |   |  | $ | 1,010  |  
|Other                                             |  |     |      |   |     |   | 3     |     |  |   | (49                   | ) |  |       |    |   |  |   | (46    | )
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|                                                  |  |     | 65    |   |     |   | 623   |     |  |   | 276                   |   |  |       |    |   |  |   | 964    |  
|Affiliate revenues                                |  |     | 124   |   |     |   |      |     |  |   | 86                    |   |  |       |    |   |  |   | 210    |  
|Intersegment revenues                             |  |     | 286   |   |     |   | 58    |     |  |   | (360                  | ) |  |       | 16  |   |  |   |       |  
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Total revenues                                    |  | $   | 475   |   |     | $ | 681   |     |  | $ | 2                     |   |  | $     | 16  |   |  | $ | 1,174  |  
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Depreciation and amortization                     |  | $   | (48   | ) |     | $ | (19   | )   |  | $ |                      |   |  | $     | (12 | ) |  | $ | (79    | )
|                                                  |  |     |       |   |    
|Operating income (loss)                           |  | $   | 78    |   |     | $ | 31    |     |  | $ | (26                   | ) |  | $     | (46 | ) |  | $ | 37     |  
|Earnings (losses) from unconsolidated investments |  |     | 51    |   |     |   | 2     |     |  |   | (2                    | ) |  |       |    |   |  |   | 51     |  
|Other items, net                                  |  |     | 1     |   |     |   | (2    | )   |  |   | 4                     |   |  |       | (4  | ) |  |   | (1     | )
|Interest expense                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (103   | )
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Loss from continuing operations before taxes      |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (16    | )
|Income tax benefit                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | 6      |  
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Loss from continuing operations                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (10    | )
|Loss from discontinued operations, net of taxes   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   | (4     | )
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Net loss                                          |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  | $ | (14    | )
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Identifiable assets:                              |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Domestic                                          |  | $   | 6,228 |   |     | $ | 1,349 |     |  | $ | 2,709                 |   |  | $     | 129 |   |  | $ | 10,415 |  
|Other                                             |  |     |      |   |     |   |      |     |  |   | 354                   |   |  |       |    |   |  |   | 354    |  
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Total                                             |  | $   | 6,228 |   |     | $ | 1,349 |     |  | $ | 3,063                 |   |  | $     | 129 |   |  | $ | 10,769 |  
|                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Unconsolidated investments                        |  | $   | 528   |   |     | $ | 95    |     |  | $ |                      |   |  | $     |    |   |  | $ | 623    |  
|                                                  |  |     |       |   |    
|Capital expenditures                              |  | $   | (23   | ) |     | $ | (11   | )   |  | $ |                      |   |  | $     | (2  | ) |  | $ | (36    | )



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Dynegys Segment Data for the Nine Months Ended September 30, 2004

(in millions)



|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|----------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ------ | -
|                                                |  | GEN |       |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |     
|Unaffiliated revenues:                          |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                        |  | $   | 373   |   |     | $ | 2,440 |     |  | $ | 862                   |   |  | $     |     |   |  | $ | 3,675  |  
|Other                                           |  |     |      |   |     |   | 2     |     |  |   | (84                   | ) |  |       |     |   |  |   | (82    | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|                                                |  |     | 373   |   |     |   | 2,442 |     |  |   | 778                   |   |  |       |     |   |  |   | 3,593  |  
|Affiliated revenues                             |  |     | 346   |   |     |   |      |     |  |   | 6                     |   |  |       |     |   |  |   | 352    |  
|Intersegment revenues                           |  |     | 564   |   |     |   | 221   |     |  |   | (619                  | ) |  |       | (166 | ) |  |   |       |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total revenues                                  |  | $   | 1,283 |   |     | $ | 2,663 |     |  | $ | 165                   |   |  | $     | (166 | ) |  | $ | 3,945  |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Depreciation and amortization                   |  | $   | (145  | ) |     | $ | (66   | )   |  | $ | (1                    | ) |  | $     | (26  | ) |  | $ | (238   | )
|Impairment and other charges                    |  |     |      |   |     |   | (5    | )   |  |   |                      |   |  |       | (24  | ) |  |   | (29    | )
|                                                |  |     |       |   |    
|Operating income (loss)                         |  | $   | 158   |   |     | $ | 214   |     |  | $ | 45                    |   |  | $     | (194 | ) |  | $ | 223    |  
|Earnings from unconsolidated investments        |  |     | 110   |   |     |   | 7     |     |  |   |                      |   |  |       |     |   |  |   | 117    |  
|Other items, net                                |  |     |      |   |     |   | (15   | )   |  |   | (1                    | ) |  |       | 3    |   |  |   | (13    | )
|Interest expense                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (275   | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Income from continuing operations before taxes  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 52     |  
|Income tax benefit                              |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (13    | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Income from continuing operations               |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 39     |  
|Loss from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (9     | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Net income                                      |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  | $ | 30     |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Identifiable assets:                            |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                        |  | $   | 5,181 |   |     | $ | 1,708 |     |  | $ | 1,737                 |   |  | $     | 876  |   |  | $ | 9,502  |  
|Other                                           |  |     |      |   |     |   | 4     |     |  |   | 754                   |   |  |       | 8    |   |  |   | 766    |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total                                           |  | $   | 5,181 |   |     | $ | 1,712 |     |  | $ | 2,491                 |   |  | $     | 884  |   |  | $ | 10,268 |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Unconsolidated investments                      |  | $   | 373   |   |     | $ | 78    |     |  | $ |                      |   |  | $     |     |   |  | $ | 451    |  
|                                                |  |     |       |   |    
|Capital expenditures                            |  | $   | (78   | ) |     | $ | (41   | )   |  | $ |                      |   |  | $     | (10  | ) |  | $ | (129   | )



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Dynegys Segment Data for the Nine Months Ended September 30, 2003

(in millions)



|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|------------------------------------------------------------------ |  | --- | ----- | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ------ | -
|                                                                   |  | GEN |       |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |     
|Unaffiliated revenues:                                             |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                           |  | $   | 285   |   |     | $ | 2,218 |     |  | $ | 610                   |   |  | $     |     |   |  | $ | 3,113  |  
|Other                                                              |  |     |      |   |     |   | 3     |     |  |   | (46                   | ) |  |       |     |   |  |   | (43    | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|                                                                   |  |     | 285   |   |     |   | 2,221 |     |  |   | 564                   |   |  |       |     |   |  |   | 3,070  |  
|Affiliate revenues                                                 |  |     | 356   |   |     |   |      |     |  |   | 86                    |   |  |       |     |   |  |   | 442    |  
|Intersegment revenues                                              |  |     | 584   |   |     |   | 193   |     |  |   | (790                  | ) |  |       | 13   |   |  |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total revenues                                                     |  | $   | 1,225 |   |     | $ | 2,414 |     |  | $ | (140                  | ) |  | $     | 13   |   |  | $ | 3,512  |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Depreciation and amortization                                      |  | $   | (136  | ) |     | $ | (60   | )   |  | $ | (1                    | ) |  | $     | (50  | ) |  | $ | (247   | )
|                                                                   |  |     |       |   |    
|Operating income (loss)                                            |  | $   | 178   |   |     | $ | 121   |     |  | $ | (348                  | ) |  | $     | (190 | ) |  | $ | (239   | )
|Earnings from unconsolidated investments                           |  |     | 133   |   |     |   | 7     |     |  |   |                      |   |  |       |     |   |  |   | 140    |  
|Other items, net                                                   |  |     | 4     |   |     |   | (12   | )   |  |   | 27                    |   |  |       | (6   | ) |  |   | 13     |  
|Interest expense                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (239   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Loss from continuing operations before taxes                       |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (325   | )
|Income tax benefit                                                 |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 121    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Loss from continuing operations                                    |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (204   | )
|Loss on discontinued operations, net of taxes                      |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (14    | )
|Cumulative effect of change in accounting principles, net of taxes |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 57     |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Net loss                                                           |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  | $ | (161   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Identifiable assets:                                               |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                           |  | $   | 6,228 |   |     | $ | 1,349 |     |  | $ | 2,709                 |   |  | $     | 129  |   |  | $ | 10,415 |  
|Other                                                              |  |     |      |   |     |   |      |     |  |   | 354                   |   |  |       |     |   |  |   | 354    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total                                                              |  | $   | 6,228 |   |     | $ | 1,349 |     |  | $ | 3,063                 |   |  | $     | 129  |   |  | $ | 10,769 |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Unconsolidated investments                                         |  | $   | 528   |   |     | $ | 95    |     |  | $ |                      |   |  | $     |     |   |  | $ | 623    |  
|Capital expenditures                                               |  | $   | (116  | ) |     | $ | (36   | )   |  | $ |                      |   |  | $     | (5   | ) |  | $ | (157   | )



Note 13Subsequent Events



On October 22, 2004, the American Jobs Creation Act of
2004 was signed into law. This legislation contains a number of changes to the Internal Revenue Code that may affect us. We are in the process of analyzing the law in order to determine its effects. At this time we do not expect any material impact
on our consolidated financial statements from this legislation.



In November 2004, Dynegy entered into an agreement to purchase from Exelon Corporation all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies and Sithe Independence, L.P. Please read Note
2Acquisitions, Dispositions, Contract Terminations and Discontinued OperationsAcquisitionsSithe Energies for further discussion.



In November 2004, we sold our Sherman natural gas processing facility located in Sherman, Texas. Please read Note 2Acquisitions, Dispositions,
Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSherman.



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DYNEGY HOLDINGS INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



On November 18, 2004, DPM entered into a power purchase agreement with Constellation Energy
Commodities Group, Inc. under which Constellation will receive DPMs rights to purchase approximately 570 megawatts of capacity and energy arising under DPMs tolling contract with LSP-Kendall Energy, LLC for a four year term from December
2004 through November 2008. DPM will remain party to the Kendall tolling contract, but will receive offsetting payments from Constellation during the four year term.



Concurrently with the execution of the power purchase agreement, DPM and Constellation entered into an assignment agreement
pursuant to which DPM would transfer to Constellation all of its rights and obligations under the Kendall tolling contract through November 2008. The assignment will only become effective upon the satisfaction of a number of conditions, including
the receipt of LSP-Kendalls consent, and upon such effectiveness the Constellation power purchase agreement would terminate.



In connection with these transactions, DPM paid to Constellation $117.5 million in cash and effectively eliminated approximately $165 million in our
future fixed payment obligations under the Kendall tolling contract through November 2008.



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DYNEGY HOLDINGS INC.



MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2004 and 2003



Item 2Managements Discussion and Analysis of Financial Condition and Results of Operations



The following discussion should be read together with the unaudited
condensed consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Form 10-K. As discussed in the Explanatory Note following the
Table of Contents, the financial information contained in this report has not been revised to reflect the effect of the restatements of our deferred income tax accounts. We expect to file amendments to our Form 10-K and first, second and third
quarter 2004 Form 10-Qs reflecting such item as soon as practicable after the date of this report. The following discussion contains forward-looking statements. Please read Factors Affecting Future Results of Operations and
Uncertainty of Forward-Looking Statements below for a discussion of the limitations inherent in these statements.



GENERAL



Summary



We are a
holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily in two areas of the energy industry: power generation and natural gas liquids. Because of the
diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. We also separately report the results of our customer risk management business, which primarily
consists of our four remaining power tolling arrangements and related gas transportation contracts, as well as legacy gas and power trading positions. Our consolidated financial results also reflect corporate-level expenses such as general and
administrative, interest and depreciation and amortization, but because of their nature, these items are not reported as a separate segment.



Operationally, our performance during the third quarter 2004 reflected the continued sensitivity to commodity prices. Our GEN business had strong
operational performance and asset availability in the quarter, despite a 10% decrease in total volumes quarter over quarter, excluding volumes relating to our interests in non-core assets that have been sold or are in the process of being sold. This
decrease resulted primarily from our management of coal inventories at our Havana plant in anticipation of our conversion to PRB coal and our curtailment of production at our Roseton station in response to higher fuel oil prices. In our NGL segment,
high commodity prices and fractionation spreads positively impacted all aspects of the business. Additionally, strong asset availability allowed us to capture the benefits of these higher prices. Please read Results of Operations
for further discussion of the comparative results of our reportable business segments.



Recent Events



Since the filing of our second
quarter 2004 Form 10-Q in August 2004, we have continued to make progress toward the completion of our efforts to restructure our company to align more closely our asset base with our business strategy. Significant developments during this period
include the following:



| |  | In September 2004, we completed the sale of our 50% ownership interest in the Hartwell generating facility.
| | - | -----------------------------------------------------------------------------------------------------------



| |  | In November 2004, we completed the sale of our Sherman natural gas processing facility in Sherman, Texas. We realized a pre-tax gain on the sale of approximately $16 million.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | In November 2004, we entered into a power purchase agreement with Constellation Energy Commodities Group, Inc. under which Constellation will purchase from us the
capacity and energy we purchase under the Kendall tolling contract, effectively eliminating $165 million in our fixed future
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | payment obligations from December 2004 through November 2008. Please read Results of OperationsOutlookCRM Outlook for further
discussion of the Constellation power purchase agreement and related assignment agreement.
| | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Strategic Growth Opportunities



Although some issues remain to be addressed in connection with our restructuring, the consolidated enterprise is beginning to shift its focus toward the identification and evaluation of strategic growth opportunities. These opportunities
may include strategic acquisitions, such as Dynegys Sithe Energies acquisition described below, which enable us to expand our presence in key markets to take advantage of a sustained power market recovery, or industry consolidation. In the
power generation industry, in particular, we believe that consolidation is likely to occur within the next several years. We further believe that our efficient and scalable operations platform, together with our multi-fuel capabilities and
multi-region presence, position us to benefit from opportunities that might arise in connection with any acquisition or consolidation transactions. However, our desire or ability to participate in any such transactions is subject to a number of
factors beyond our control. As such, we cannot guarantee that any such transactions will occur, nor can we predict with any degree of certainty the impact of any such transactions on our financial condition or results of operations.



Sithe Energies. In November 2004, Dynegy entered into an
agreement to purchase from Exelon Corporation all of the outstanding capital stock of ExRes SHC, Inc. which serves as the parent company of Sithe Energies, Inc. and Sithe Independence, L.P. Through this acquisition, Dynegy will acquire the 1,042-MW,
7,211-Btu heat rate, combined-cycle Independence power generation facility located near Scriba, NY, four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. Sithe Independence holds a
750-megawatt firm capacity sales agreement with Con Edison, a subsidiary of Consolidated Edison, Inc., which runs through 2014 and provides annual cash receipts to Sithe Independence of approximately $100 million. Sithe Independence is also party to
tolling and financial swap contracts with one of our subsidiaries. At the time of closing, ExRes SHC, Inc. will not be consolidated by us. The acquisition transforms the tolling and swap contracts into Dynegy intercompany and our affiliate
agreements. Other than the reporting of the transactions with Sithe Independence, L.P. as affiliate transactions, we do not anticipate any other material impact to us from the transaction.



The transaction is subject to various closing conditions, including the
receipt of approvals from various federal and state regulatory entities, such as the FERC, and the New York Public Service Commission, as well as Hart-Scott-Rodino review by the Federal Trade Commission. The transaction is also subject to the
receipt by Sithe Independence of a waiver or amendment from its bondholders under its trust indenture.



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LIQUIDITY AND CAPITAL RESOURCES



Overview



In this section, we provide updates related to our liquidity and capital requirements and our internal and external liquidity and capital resources. Our
liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures, regulatory and legal settlements
and working capital needs. Examples of working capital needs include purchases of commodities, particularly natural gas, coal and natural gas liquids, cash collateral, facility maintenance costs (including required environmental expenditures) and
other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, asset sale proceeds and proceeds from capital market transactions.



Debt Obligations



We have a substantial amount of indebtedness, resulting in significant debt
service obligations. Accordingly, over the near and longer term, we expect to continue devoting a considerable portion of our liquidity and capital resources to debt service requirements. Please read Results of OperationsInterest
Expense below for further discussion of our debt service obligations.



With respect to our debt maturities, we continued our efforts to extend our maturity profile in the second quarter 2004 through, among other things, the restructuring of our primary credit facility. Specifically, in
May 2004, we entered into a $1.3 billion credit facility consisting of:



| |  | a $700 million secured revolving credit facility that matures on May 28, 2007; and
| | - | ----------------------------------------------------------------------------------



| |  | a $600 million secured amortizing term loan that matures on May 28, 2010.
| | - | -------------------------------------------------------------------------



The credit facility replaced our $1.1 billion revolving credit facility, which was scheduled to mature in February 2005.



In August 2004, $154 million of the proceeds from the $600 million term loan
were used to pre-pay all outstanding indebtedness and other amounts owed in connection with the ABG Gas Supply financing. The remaining proceeds, subject to specified restrictions in the credit facility, are available for general corporate purposes.
Please read Cash on Hand below for further discussion. Borrowings under the term loan bear interest, at our option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus 4.00% per annum. A letter of credit fee will be payable
on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.00% of such undrawn amount. We also incur additional fees for issuing letters of credit. An unused commitment fee of 0.50% is payable on the unused
portion of the revolving facility. Please read Note 6Debt for further discussion of our credit facility.



Other transactions impacting the change in our debt maturities in the third quarter 2004 include $78 million in payments relating to the termination of
the Tilton capital lease, which is further described in Note 6DebtTilton Capital Lease.



We have incurred significant debt service obligations in the course of extending our debt maturities. We also are subject to covenants in the related
transaction agreements that are substantially more restrictive than those typically found in financing agreements of borrowers with investment grade credit ratings, including covenants limiting our ability to incur additional debt and sell certain
assets. We are currently in compliance with these restrictive covenants, with the exception of our filing of this report without (i) the requisite review of the accompanying financial statements by our independent auditor and (ii) the certifications
mandated by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 and Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934, as amended, which may not constitute compliance with our obligation under the indenture to file with the SEC a
quarterly report prepared in all material respects in accordance with all of the rules and regulations applicable thereto. Notwithstanding this possible non-compliance, we expect to file an amendment to this report with the required review and
certifications prior to the expiration of the applicable cure period in the indenture.



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Our future financial condition and results of operations could be materially adversely affected by our ability to file the amended report prior to the
expiration of the applicable cure period and to otherwise comply with these restrictive covenants in the future.



Collateral Postings



We continue to use a significant portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands.
These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties views of our financing condition and ability to satisfy our performance obligations, as well as commodity prices and other factors.



The following table summarizes our consolidated collateral
postings to third parties by operating division and by type at November 8, 2004, September 30, 2004 and December 31, 2003:



|                       |  |                  |     |                   |   |                  |  |   |    
|---------------------- |  | ---------------- | --- | ----------------- | - | ---------------- |  | - | ---
|                       |  | November 8, 2004 |     | September 30,2004 |   | December 31,2003
|                       |  | (in millions)   
|By Operating Division: |  |                  |     |                   |   |                  |  |   |    
|GEN                    |  | $                | 276 |                   | $ | 202              |  | $ | 136
|CRM                    |  |                  | 117 |                   |   | 96               |  |   | 121
|NGL                    |  |                  | 144 |                   |   | 159              |  |   | 179
|Other                  |  |                  | 17  |                   |   | 16               |  |   | 8  
|                       |  |                  |     |                   |   |                  |  |   |    
|Total                  |  | $                | 554 |                   | $ | 473              |  | $ | 444
|                       |  |                  |     |                   |   |                  |  |   |    
|By Type:               |  |                  |     |                   |   |                  |  |   |    
|Cash                   |  | $                | 441 |                   | $ | 355              |  | $ | 256
|Letters of Credit      |  |                  | 113 |                   |   | 118              |  |   | 188
|                       |  |                  |     |                   |   |                  |  |   |    
|Total                  |  | $                | 554 |                   | $ | 473              |  | $ | 444
|                       |  |                  |     |                   |   |                  |  |   |    



The increase in
collateral postings since December 31, 2003, relates primarily to $140 million of additional collateral posted in support of our GEN segment primarily as a result of increased commodity prices, particularly the price of electricity, as well as
increased coal purchases and collateral posted in connection with new electric capacity sales transactions.



This increase in our collateral postings was offset by reductions in collateral postings in our other segments, including the $4 million reduction of
collateral posted in support of our CRM segment primarily resulting from (i) the termination of the ABG Gas Supply contract in August 2004 and (ii) the execution of a master netting agreement with a significant counter-party, which were offset by
increased natural gas prices. Additionally, the reduction of $35 million in collateral postings in support of our NGL segment was primarily due to the timing of settlements.



In addition to the increase in the total amount of collateral posted, we have also increased the proportion of cash used to
satisfy counterparty collateral demands. As of December 31, 2003, approximately 58% of the aggregate collateral posted (or approximately $256 million) consisted of cash, compared to approximately 75% cash collateral (or approximately $355 million)
as of September 30, 2004 and 80% cash collateral (or approximately $441 million) as of November 8, 2004. This increase is the result of the termination of the ABG Gas Supply contract and our ongoing efforts to post cash collateral in lieu of letters
of credit, to the extent economical, to avoid paying the 4.00% per annum letter of credit fee payable under our revolving credit facility.



Going forward, we expect counterparties collateral demands to continue to reflect changes in commodity prices, including seasonal changes in
weather-related demand, as well as their views of our creditworthiness. Considering current commodity price estimates, our credit ratings, the timing of contract settlements, the anticipated level of new capacity sales agreements and forward hedging
transactions, we believe that collateral requirements will be between $525 million and $550 million at year end 2004. We also believe that we have sufficient capital resources to satisfy counterparties collateral demands, including those for
which no collateral is currently posted, for at least the next twelve months. Over the longer term, we expect to achieve incremental reductions associated with the completion of our exit from the CRM business. Please see Results of
OperationsOutlookCRM Outlook below for a discussion of the expected collateral roll-off from this business.



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Disclosure of Contractual Obligations and Contingent Financial Commitments



We have incurred various contractual obligations and contingent financial
commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from
both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain pre-defined events
occur, such as financial guarantees.



Our contractual
obligations and contingent financial commitments have changed since December 31, 2003, with respect to which information is included in our Form 10-K. Over the nine-month period ended September 30, 2004, the following events have significantly
changed these contractual obligations and contingent financial commitments.



Gas Transportation Contracts. In June 2004, we reached agreements to exit four natural gas transportation agreements. We paid $20 million in June 2004 and are required to pay another $42 million in the
first quarter 2005 under these agreements, in exchange for which we will discharge our obligations to make fixed capacity payments aggregating $295 million from April 2005 through 2014. As a result, our capacity payments of $2,786 million as
reported on page 30 of our Form 10-K have been reduced by approximately $22 million in 2005, $31 million in each of the years ended 2006 through 2008, and $180 million thereafter. Please read Results of OperationsOperating Income
(Loss)CRM for a discussion of the $88 million pre-tax gain we recorded in the second quarter 2004 in connection with these agreements.



Gas-Fired Turbines. In February 2004, we terminated our conditional purchase obligation related to 14 gas-fired turbines as part of a
comprehensive settlement agreement with the manufacturer. No cash, other than $11 million previously paid to the manufacturer as a deposit, was provided as consideration for the termination. Therefore, our conditional purchase obligations of $615
million as reported on page 30 of our Form 10-K have been reduced by approximately $5 million in 2004, $144 million in 2005, $193 million in 2006, $113 million in 2007 and $24 million in 2008.



Please also read Note 6Debt and Liquidity and Capital
ResourcesDebt Obligations for a discussion of changes in our long-term debt obligations. There have been no other material changes to our contractual obligations and contingent financial commitments since December 31, 2003.



Internal Liquidity Sources



Our primary internal liquidity sources are cash flows from operations, cash
on hand and available capacity under our $700 million revolving credit facility, which is scheduled to mature in May 2007.



Cash Flows from Operations. We had operating cash outflows of $62 million for the nine months ended September 30, 2004. This consisted of
$545 million in operating cash flows from our GEN and NGL segments, reflecting positive earnings for the period offset by reductions in working capital from increased cash collateral postings. The cash flows from our operating segments were more
than offset by $607 million of cash outflows relating to our CRM business and corporate-level expenses. Please read Results of OperationsOperating Income and Cash Flow Disclosures for further
discussion of factors impacting our operating cash flows for the periods presented.



Much of our restructuring work has extended our significant debt maturities to 2008 and beyond, positioning us to benefit from the expected long-term recovery in the U.S. power markets. Our future financial condition
and results of operations will be materially adversely affected if the U.S. power markets fail to recover in accordance with our expectations or if we experience significant, prolonged pricing deterioration in our NGL business below price levels
experienced over the last few years. Please read Item 1. BusinessSegment DiscussionPower Generation beginning on page 3 of our Form 10-K for a discussion of our views on supply



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and demand in the regions where our GEN business operates. Please also read Managements Discussion and Analysis of Financial Condition and
Results of OperationsLiquidity and Capital ResourcesInternal Liquidity SourcesCash Flows from Operations beginning on page 34 of our Form 10-K for a discussion of our expectations regarding the financial impact of the
expected recovery.



Over the longer term, our operating cash
flows also will be impacted by, among other things, our ability to tightly manage our operating costs, including costs for fuel and maintenance. With respect to fuel costs, in January 2004, we entered into a new rail transportation contract that we
anticipate will reduce the fees associated with fuel procurement at our coal-fired generation facilities in the Midwest; however, these fee reductions were substantially offset by increased coal prices in the northeast and higher costs associated
with the purchase of emission credits. Our ability to achieve fuel-related and other targeted cost savings in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, will impact our future
operating cash flows. Please read Results of OperationsOutlookGEN Outlook for further discussion.



In addition, our CDWR power purchase agreement expires by its terms on December 31, 2004. Our share of West Coast Powers earnings during the nine
months ended September 30, 2004 totaled $123 million, approximately 73% of which was derived from the CDWR agreement. We are actively pursuing a renewal or replacement of this agreement; however, we cannot guarantee that an agreement can be reached
on similar terms, if at all. If we are unable to renew or replace this agreement, we will seek to sell the associated energy and capacity through other long-term arrangements or into the open market, where our operating cash flows would be dependent
on then prevailing market prices and the market for capacity in California. Because we expect that the generating facilities supporting the CDWR contract would be significantly less profitable as merchant facilities, we may consider other
alternatives if we are unable to enter into a renewal or replacement agreement, including shutting down one or more units if we no longer consider them commercially viable. Based on our ongoing evaluation of strategic alternatives for our West Coast
Power assets, we have determined that it is not economically feasible to continue to operate our Long Beach generation facility beyond the expiration of the CDWR contract. Therefore, we intend to retire the asset as of December 31, 2004. Please read
Results of OperationsOutlookGEN Outlook for further discussion of the CDWR agreement and the anticipated impairments relating to its scheduled expiration.



Cash on Hand. At November 8, 2004 and September 30, 2004, we had cash on hand of $284 million and $415
million, respectively, as compared to $328 million at the end of 2003.This increase in cash on hand at September 30, 2004 as compared to the end of 2003 is primarily attributable to the remaining proceeds that have yet to be deployed from
our $600 million secured term loan.



The decrease in cash
between September 30, 2004 and November 8, 2004 primarily reflects increased postings of cash collateral. We are currently exploring other possible uses of a portion of this cash. These possible uses include (i) redemption or repurchase of
outstanding debt securities (ii) settlement of pending litigation or (iii) settlement of one or more power tolling arrangements, if the opportunity is available to do so on terms we consider economically justifiable. Based on current expectations,
we estimate that we will have approximately $320 million in cash on hand at year end, excluding payment of $117.5 million to Constellation in November 2004 in connection with the power purchase agreement and assignment relating to our Kendall
tolling contract. Unforeseen events, such as legal judgments, regulatory requirements or matters impacting our operations, could negatively impact our cash position.



Revolver Capacity.In May 2004, we entered into a new $1.3 billion credit facility, consisting of a $600
million term loan and a $700 million revolving credit facility. This $700 million revolving credit facility, which is scheduled to mature in May 2007, is our primary credit facility. We currently have no drawn amounts under this facility, although
as of November 8, 2004, we had $113 million in letters of credit issued under the facility. Our ability to borrow and/or issue letters of credit under a revolving credit facility could become increasingly important to our liquidity and financial
condition, particularly if we are unable to generate operating cash flows relative to our substantial debt obligations and ongoing operating requirements. Please read Note 6Debt for further discussion of our credit facility.



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Current Liquidity.The following table summarizes our consolidated credit capacity and
liquidity position at November 8, 2004, September 30, 2004 and December 31, 2003:



|                                                              |  |                 |      |     |                   |   |      |                  |  |   |       |  
|------------------------------------------------------------- |  | --------------- | ---- | --- | ----------------- | - | ---- | ---------------- |  | - | ----- | -
|                                                              |  | November 8,2004 |      |     | September 30,2004 |   |      | December 31,2003 | 
|                                                              |  | (in millions)   |     
|Total Revolver Capacity                                       |  | $               | 700  | (1) |                   | $ | 700  | (1)              |  | $ | 1,100 |  
|Outstanding Letters of Credit Under Revolving Credit Facility |  |                 | (113 | )   |                   |   | (118 | )                |  |   | (188  | )
|                                                              |  |                 |      |     |                   |   |      |                  |  |   |       |  
|Unused Revolver Capacity                                      |  |                 | 587  |     |                   |   | 582  |                  |  |   | 912   |  
|Cash                                                          |  |                 | 284  | (2) |                   |   | 415  | (2)              |  |   | 328   |  
|                                                              |  |                 |      |     |                   |   |      |                  |  |   |       |  
|Total Available Liquidity                                     |  | $               | 871  |     |                   | $ | 997  |                  |  | $ | 1,240 |  
|                                                              |  |                 |      |     |                   |   |      |                  |  |   |       |  

---

|(1) | Please read Note 6Debt for a discussion of our credit facility.
|--- | ----------------------------------------------------------------

|(2) | The November 8, 2004 and September 30, 2004 amounts include approximately $46 million and $45 million, respectively, of cash that remains in Canada and the U.K. that is associated
primarily with contingent liabilities relating to our former Canadian and U.K. marketing and trading operations. The reduction in cash from September 30, 2004 to November 8, 2004 primarily results from increased postings of cash collateral.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



External Liquidity Sources



Our primary external liquidity sources are proceeds from asset sales and
other types of capital-raising transactions, including potential equity issuances.



Asset Sale Proceeds.During the first nine months of 2004, we received aggregate cash proceeds of $197 million from asset sales. Based on our current estimates, we expect that our operating cash flows
will continue to be insufficient to satisfy our capital expenditures, debt maturities, interest expenses and operating commitments for the foreseeable future.



In an effort to maximize our return on investment and to further clarify our business strategy, we have been pursuing the sale of assets that we do not
consider core to our operations. These assets primarily include our ownership interests in certain non-strategic domestic power generation facilities, which facilities are detailed in Item 1. BusinessSegment DiscussionPower Generation
beginning on page 3 of our Form 10-K, as well as our minority ownership interests in one or more upstream or downstream NGL facilities. Since the end of the second quarter 2004, we have sold or entered into definitive agreements to sell the
following assets:



| |  | We completed the sales of our 50% ownership interests in each of the 424 MW Oyster Creek generating facility, the 123 MW Michigan Power generating facility and the 310 MW Hartwell
generating facility. We received approximately $132 million in aggregate net cash proceeds from these transactions.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | We entered into an agreement to sell our 50% ownership in the 310 MW Commonwealth generating facility. We expect to close this transaction, which is subject to regulatory and bank
approvals and other closing conditions, in the fourth quarter 2004.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | In November 2004, we completed the sale of our Sherman natural gas processing facility. This sale resulted in a pre-tax gain of approximately $16 million.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------



Generally, the aggregate projected loss of earnings in 2004
associated with these assets is not considered material and is expected to be more than offset by net gains on sale in 2004. However, beginning in 2005, the lost earnings of approximately $26 million on an annual basis from these assets will no
longer be offset by gains on sale.



Our desire or ability to
effect the few remaining non core asset sales is subject to a number of factors, many of which are beyond our control, including the market for the assets and investments not yet subject to a sale



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agreement, the receipt of any regulatory and other approvals that may be required and the willingness of lenders and other counterparties to consent to a
proposed transaction. Accordingly, we cannot guarantee that the pending sale or any other sales will be consummated or that the expected proceeds will be received.



Capital-Raising Transactions.As part of Dynegys ongoing efforts to develop a capital structure that is
more closely aligned with the cash-generating potential of the consolidated enterprises asset-based businesses, each of which is subject to cyclical changes in commodity prices, Dynegy is continuing to explore additional capital-raising
transactions both in the near- and long-term. The timing of any capital-raising transaction may be impacted by unforeseen events, such as legal judgments or regulatory requirements, as well as strategic decisions relating to litigation settlements
or contract terminations (including settlement of one or more of our remaining power tolling arrangements), which would necessitate additional capital in the near-term.



These transactions may include capital markets transactions. Dynegys ability to issue public securities is enhanced by
its effective shelf registration statement, under which it has approximately $430 million in remaining availability, and which will be available for use after it completes its previously announced restatements. However, the receptiveness of the
capital markets to a public offering cannot be assured and may be negatively impacted by, among other things, Dynegys non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond its
control. Any issuance of equity likely would have other effects as well, including shareholder dilution. Further, our ability to issue debt securities is limited by our financing agreements, including our credit facility. Please read Note
6DebtRevolvers for further discussion.



Conclusion



For the foreseeable future, assuming continuation of the
current commodity pricing environment, we expect that our operating cash flows will be insufficient to satisfy our capital expenditures, debt maturities, interest expenses and operating commitments. However, we believe that our cash on hand,
together with proceeds from anticipated asset sales and capacity under our $700 million revolving credit facility, will be sufficient to discharge these obligations for at least the next twelve months.



Our liquidity position and financial condition will be materially affected by
a number of factors, including our ability, over the longer term, to generate cash flows from our asset-based energy businesses in relation to our substantial debt and commercial obligations, including increased interest expense, the fixed payment
obligations associated with our CRM business and counterparty collateral requirements.



Our ability to generate operating cash flows from our asset-based energy businesses will be impacted by a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for
power and natural gas, and the success of our ongoing efforts to manage operating costs, particularly fuel requirements, and capital expenditures. Over the longer term we believe that power prices will improve in some or all of the regions in which
we operate as the supply-demand imbalance for power decreases. Much of our restructuring work has extended our significant debt maturities to 2008 and beyond, positioning us to benefit from earnings and growth opportunities associated with an
expected recovery in the U.S. power markets. Additionally, our natural gas liquids business is currently operating in a highly favorable pricing environment. Our future financial condition and results of operations will be materially adversely
affected if the U.S. power markets fail to recover in accordance with our expectations or if we experience significant, prolonged pricing deterioration below price levels experienced over the last few years in our NGL segment.



Additionally, our longer term liquidity position and financial condition will
be impacted by our desire and ability to generate proceeds through capital markets transactions. We have significant long-term fixed payment obligations relating to the tolling arrangements that remain in our CRM business, in addition to potential
payment obligations relating to our securities litigation and other legal and regulatory matters. Our ability to continue to satisfy these obligations, through acquisition (as in the case of Sithe Energies), assignment (as in the



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case of our efforts with respect to the Kendall tolling contract), settlement or otherwise, will be impacted by our access to the capital markets and the
cash flow generating ability of our asset-based businesses. This is particularly important with respect to our long-term tolling arrangements, which we expect will continue to reduce our operating cash flows absent an early termination or
settlement. We expect that our liquidity position will trend downward as these obligations are satisfied or extinguished.



Our longer term liquidity position and financial condition will also be significantly impacted by the availability of, and our ability to pursue,
strategic growth opportunities, which may include strategic acquisitions, such as Dynegys Sithe Energies acquisition, in which we expand our presence in key markets to take advantage of a sustained power market recovery, or industry
consolidation. In the power generation industry, in particular, we believe that consolidation is likely to occur within the next several years. We further believe that our efficient and scalable operations platform, together with our multi-fuel
capabilities and multi-region presence, position us to benefit from opportunities that might arise in connection with any acquisition or consolidation transactions. However, as indicated above, our desire or ability to participate in any such
transactions is subject to a number of factors beyond our control. As such, we cannot guarantee that any such transactions will occur, nor can we predict with any degree of certainty the impact of any such transactions on our financial condition or
results of operations.



Please read Uncertainty of
Forward-Looking Statements and Information for additional factors that could impact our future operating results and financial condition.



FACTORS AFFECTING FUTURE RESULTS OF OPERATIONS



In Managements Discussion and Analysis of Financial Condition and Results of OperationsOverview beginning on page 25 of our Form
10-K, we detailed the primary factors that have impacted, and are expected to continue to impact, the earnings and cash flows from our business segments and other operations. Our results of operations during the remainder of 2004 and beyond may be
significantly affected by any or all of these factors, including the following factors in particular:



| |  | Changes in commodity prices, including the relationships between prices for power and natural gas or other power generating fuels, commonly referred to as the spark
spread, and the frac spread, which represents the relative difference in value between natural gas liquids and natural gas on a Btu basis;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Our ability to control our capital expenditures, which primarily are limited to maintenance, safety, environmental and reliability projects, and other costs through disciplined
management and safe, efficient operations;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | The impact of reduced market liquidity and counterparty collateral demands on our ability to sell our energy products through forward sales or similar transactions;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Our ability to address the substantial payment obligations associated with our four remaining long-term power tolling arrangements, including the Gregory tolling arrangement which
expires in July 2005, the restructuring or termination of one or more of which likely would require a significant cash payment, including our ability to (i) substantially eliminate the financial impact of the Sithe tolling arrangement through
Dynegys Sithe Energies acquisition and (ii) consummate the assignment of our rights and obligations under the Kendall tolling contract to Constellation through November 2008; and;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | The impact of increased interest expense primarily attributable to our non-investment grade credit ratings.
| | - | -----------------------------------------------------------------------------------------------------------



Please read Uncertainty of Forward-Looking Statements and
Information for additional factors that could impact our future operating results.



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RESULTS OF OPERATIONS



Overview and Discussion of Comparability of Results. In this section, we discuss our results of operations,
both on a consolidated basis and, where appropriate, by segment, for the three- and nine-month periods ended September 30, 2004 and 2003. We have also included our business outlook for each segment.



We report our operations in the following segments: GEN, NGL and CRM. Other
reported results include corporate overhead. All direct general and administrative expenses and other income (expense) items incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred.



Three Months Ended September 30, 2004 and 2003



The following tables provide summary financial data regarding our
consolidated and segmented results of operations for the three months ended September 30, 2004 and 2003, respectively.



Quarter Ended September 30, 2004



|                                                |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |     |  
|----------------------------------------------- |  | ------------- | -- | --- | - | -- | --- |  | - | --------------------- | - |  | ----- | --- | - |  | - | --- | -
|                                                |  | GEN           |    | NGL |   |    | CRM |  |   | Other andEliminations |   |  | Total |    
|                                                |  | (in millions) |   
|Operating income (loss)                         |  | $             | 71 |     | $ | 72 |     |  | $ | (32                   | ) |  | $     | (54 | ) |  | $ | 57  |  
|Earnings from unconsolidated investments        |  |               | 23 |     |   | 3  |     |  |   |                      |   |  |       |    |   |  |   | 26  |  
|Other items, net                                |  |               |   |     |   | (6 | )   |  |   | (3                    | ) |  |       | (1  | ) |  |   | (10 | )
|Interest expense                                |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (85 | )
|                                                |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |     |  
|Loss from continuing operations before taxes    |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (12 | )
|Income tax benefit                              |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | 6   |  
|                                                |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |     |  
|Loss from continuing operations                 |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (6  | )
|Loss from discontinued operations, net of taxes |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (2  | )
|                                                |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |     |  
|Net loss                                        |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  | $ | (8  | )
|                                                |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |     |  



Quarter Ended
September 30, 2003



|                                                  |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |      |  
|------------------------------------------------- |  | ------------- | -- | --- | - | -- | --- |  | - | --------------------- | - |  | ----- | --- | - |  | - | ---- | -
|                                                  |  | GEN           |    | NGL |   |    | CRM |  |   | Other andEliminations |   |  | Total |    
|                                                  |  | (in millions) |   
|Operating income (loss)                           |  | $             | 78 |     | $ | 31 |     |  | $ | (26                   | ) |  | $     | (46 | ) |  | $ | 37   |  
|Earnings (losses) from unconsolidated investments |  |               | 51 |     |   | 2  |     |  |   | (2                    | ) |  |       |    |   |  |   | 51   |  
|Other items, net                                  |  |               | 1  |     |   | (2 | )   |  |   | 4                     |   |  |       | (4  | ) |  |   | (1   | )
|Interest expense                                  |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (103 | )
|                                                  |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |      |  
|Loss from continuing operations before taxes      |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (16  | )
|Income benefit                                    |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | 6    |  
|                                                  |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |      |  
|Loss from continuing operations                   |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (10  | )
|Loss from discontinued operations, net of taxes   |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   | (4   | )
|                                                  |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |      |  
|Net loss                                          |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  | $ | (14  | )
|                                                  |  |               |    |     |   |    |     |  |   |                       |   |  |       |     |   |  |   |      |  



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The following table provides summary segmented operating statistics for the three months ended September
30, 2004 and 2003, respectively.



|                                                  |  |                             |         |      |   |        
|------------------------------------------------- |  | --------------------------- | ------- | ---- | - | -------
|                                                  |  | Quarter Ended September 30,
|                                                  |  | 2004                        |         | 2003
|Power Generation                                  |  |                             |         |      |   |        
|Million megawatt hours generatedgross            |  |                             | 9.5     |      |   | 10.4   
|Million megawatt hours generatednet              |  |                             | 9.0     |      |   | 9.7    
|Average natural gas priceHenry Hub ($/MMbtu) (1) |  | $                           | 5.49    |      | $ | 4.88   
|Average on-peak market power prices ($/MWh):      |  |                             |         |      |   |        
|Cinergy                                           |  | $                           | 43      |      | $ | 39     
|Commonwealth Edison (NI Hub)                      |  | $                           | 41      |      | $ | 39     
|Southern                                          |  | $                           | 50      |      | $ | 44     
|New YorkZone G                                   |  | $                           | 57      |      | $ | 61     
|ERCOT                                             |  | $                           | 50      |      | $ | 43     
|SP-15                                             |  | $                           | 57      |      | $ | 54     
|Natural Gas Liquids                               |  |                             |         |      |   |        
|Gross NGL production (MBbls/d):                   |  |                             |         |      |   |        
|Field plants                                      |  |                             | 58.9    |      |   | 61.5   
|Straddle plants                                   |  |                             | 29.6    |      |   | 23.4   
|                                                  |  |                             |         |      |   |        
|Total gross NGL production                        |  |                             | 88.5    |      |   | 84.9   
|                                                  |  |                             |         |      |   |        
|Natural gas (residue) sales (Bbtu/d)              |  |                             | 190.7   |      |   | 159.5  
|Natural gas inlet volumes (MMCFD):                |  |                             |         |      |   |        
|Field plants                                      |  |                             | 545.8   |      |   | 617.7  
|Straddle plants                                   |  |                             | 1,249.9 |      |   | 872.4  
|                                                  |  |                             |         |      |   |        
|Total natural gas inlet volumes                   |  |                             | 1,795.7 |      |   | 1,490.1
|                                                  |  |                             |         |      |   |        
|Fractionation volumes (MBbls/d)                   |  |                             | 257.2   |      |   | 186.8  
|Natural gas liquids sold (MBbls/d)                |  |                             | 290.4   |      |   | 276.1  
|Average commodity prices:                         |  |                             |         |      |   |        
|Crude oilWTI ($/Bbl)                             |  | $                           | 42.22   |      | $ | 30.45  
|Natural gasHenry Hub ($/MMbtu) (2)               |  | $                           | 5.76    |      | $ | 4.97   
|Natural gas liquids ($/Gal)                       |  | $                           | 0.75    |      | $ | 0.51   
|Fractionation spread ($/MMBtu)daily              |  | $                           | 2.93    |      | $ | 0.95   

---

|(1) | Calculated as the average of the daily gas prices for the period.
|--- | -----------------------------------------------------------------

|(2) | Calculated as the average of the first of the month prices for the period.
|--- | --------------------------------------------------------------------------



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The following tables summarize significant items on a pre-tax basis, with the exception of the 2004 tax
item, affecting net income for the periods presented.



|                                |  |                                  |     |   |     |   |     |  |       |   |  |       |     |   |  |   |     |  
|------------------------------- |  | -------------------------------- | --- | - | --- | - | --- |  | ----- | - |  | ----- | --- | - |  | - | --- | -
|                                |  | Quarter Ended September 30, 2004 |    
|                                |  | GEN                              |     |   | NGL |   | CRM |  | Other |   |  | Total |    
|                                |  | (in millions)                    |    
|Impairment of West Coast Power  |  | $                                | (45 | ) |     | $ |    |  | $     |  |  | $     |    |   |  | $ | (45 | )
|Gain on sale of Oyster Creek    |  |                                  | 15  |   |     |   |    |  |       |  |  |       |    |   |  |   | 15  |  
|                                |  |                                  |     |   |     |   |     |  |       |   |  |       |     |   |  |   |     |  
|Total                           |  | $                                | (30 | ) |     | $ |    |  | $     |  |  | $     |    |   |  | $ | (30 | )
|                                |  |                                  |     |   |     |   |     |  |       |   |  |       |     |   |  |   |     |  
|                                | 
|                                |  | Quarter Ended September 30, 2003 |    
|                                |  | GEN                              |     |   | NGL |   | CRM |  | Other |   |  | Total |    
|                                |  | (in millions)                    |    
|Acceleration of financing costs |  | $                                |    |   |     | $ |    |  | $     |  |  | $     | (20 | ) |  | $ | (20 | )
|                                |  |                                  |     |   |     |   |     |  |       |   |  |       |     |   |  |   |     |  
|Total                           |  | $                                |    |   |     | $ |    |  | $     |  |  | $     | (20 | ) |  | $ | (20 | )
|                                |  |                                  |     |   |     |   |     |  |       |   |  |       |     |   |  |   |     |  



Operating Income



Operating income was $57 million for the quarter
ended September 30, 2004, compared to $37 million for the quarter ended September 30, 2003.



GEN.Operating income for the GEN segment was $71 million for the quarter ended September 30, 2004, compared to $78 million for the quarter ended September 30, 2003.



Results in the Midwest region, where approximately 60% of our generation
volumes are produced, increased $15 million quarter over quarter. The regions results benefited by $32 million from higher power prices, with average on-peak prices up 5% compared with the third quarter 2003. However, volumes of 5.3 million
MWh for the third quarter 2004 were slightly lower than the 5.7 million MWh for the third quarter 2003, largely as a result of reduced production at our Havana facility, as we managed fuel inventories in anticipation of our switch to PRB coal.
Please read OutlookGEN Outlook for a discussion of the current fuel and transportation environment. This decline in volume reduced revenue for this region by $3 million. Operating expense increased by $5 million from $32
million for the third quarter 2003 to $37 million for the third quarter 2004, primarily as a result of the timing of maintenance expenditures. Additionally, the region recognized $5 million less in revenue from the sale of capacity in the third
quarter 2004, as compared with 2003. During the third quarter 2004, we recorded a $3 million charge to earnings in connection with hedge ineffectiveness.



Improved results in the Midwest were offset by the results in the Northeast region, where earnings decreased $13 million, from $25 million for the quarter
ended September 30, 2003 to $12 million for the quarter ended September 30, 2004. Results for the Northeast declined $3 million as a result of higher fuel and fuel transportation costs quarter over quarter. Further, aggregate volumes decreased from
1.8 million MWh for the quarter ended September 30, 2003 to 1.4 million MWh for the quarter ended September 30, 2004, primarily as a result of the higher cost of fuel oil this year compared with last year, which reduced run time. This decrease in
volume resulted in a $6 million decrease in earnings.



Results
in the Southeast region decreased by $7 million in the third quarter 2004 compared with the third quarter 2003, as a result of the loss of capacity revenues related to a contract that expired at the end of 2003.



Results in our other regions and businesses were reduced by approximately $4
million, due primarily to lower power prices and higher natural gas prices in Texas.



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GENs reported operating income for the 2004 period includes mark-to-market income of approximately
$4 million, compared with losses of approximately $4 million for the third quarter 2003 related to derivative contracts that did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market
basis.



NGL. Operating income for our NGL segment
was $72 million for the quarter ended September 30, 2004, compared to $31 million for the quarter ended September 30, 2003. Please read Item1. Business Segment DiscussionNatural Gas Liquids beginning on page 8 of our Form 10-K for a
detailed description of our NGL segment, including its contract portfolio.



The significant improvement in operating income was driven by natural gas, crude oil and natural gas liquids prices, which increased to historically high levels, a frac spread sufficiently high to make natural gas
liquids recovery economic under all contract settlements, and strong asset runtime across all NGL segments. This combination of price events has provided a unique window on the margin drivers across our NGL business. The following
discussion is intended to provide some perspective on how this business performs in this price environment.



Significantly higher commodity prices contributed approximately $24 million to our results as compared to the same quarter in 2003. Of the increase, $21
million relates to percentage of proceeds contracts in field processing and $3 million from natural gas liquids marketing contracts. An additional $9 million of operating income as compared to the same quarter in 2003 was recognized in marketing as
the direct result of the rapid rise in commodity prices over the quarter.



The frac spread was significantly higher in 2004 compared to the same quarter in 2003. At the end of July 2004, the increasing spread between natural gas liquids prices and natural gas prices reached levels sufficient
to support increased liquids recovery industry-wide, reversing an eighteen-month trend. For the 2004 quarter, the higher frac spread generated incremental results of approximately $15 million as compared to the same quarter in 2003. This increase
relates to the following: $2 million from additional gas volumes processed in our straddle plants under economic keep-whole settlement terms at our Stingray Plant; $5 million because contract settlements for existing gas volumes under hybrid
contracts switched from fee to percentage of liquids settlements; $1 million from increased volumes processed under hybrid and percentage of liquids contracts; and $7 million because increased industry-wide natural gas liquids recovery brought
additional volumes to our fee-based liquids gathering systems, fractionators, storage and distribution systems and marketing activities.



Gathering and processing operating results increased by $19 million for the quarter ended September 30, 2004 compared to the quarter ended September 30,
2003, primarily benefiting from 16% higher absolute commodity prices for natural gas and 47% higher absolute commodity prices for natural gas liquids compared to the same quarter in 2003. At our field plants, results increased $14 million. Our
current contract portfolio of nearly 98% percentage of proceeds, percentage of liquids and fee-based contracts benefited from higher prices in the third quarter 2004. However, gross and net natural gas liquids production declines due to the sale of
our interest in the Indian Basin plant in April 2004, lost opportunity on hedged volumes and the impacts of pipeline, compressor and process unit maintenance at our facilities partially offset the commodity price gains. At our straddle plants,
results increased $7 million. A major factor improving profitability was the impact of higher natural gas liquids prices under our percentage of liquids contract settlements. Additionally, beginning in late July, higher frac spreads made it
profitable to recover liquids under keep-whole agreements and caused hybrid contracts to switch from fee to percentage of liquids settlements. The Stingray facility, our only plant that settles under a keep-whole contract structure, operated in the
third quarter 2004, while it was idled in the third quarter 2003. We also experienced higher volumes at our other straddle plants where most of the gas settles under hybrid contracts and only a small portion of the gas that settles under keep-whole
contracts. Straddle plant inlet volumes increased 43% and net barrels produced increased 27%.



As a result of our percentage of proceeds and percentage of liquids contracts, we take ownership of natural gas and natural gas liquids as payment for our services. We have a comprehensive hedging strategy and related



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control procedures to manage price risk on these equity volumes. We limit volume considered for hedging and forward selling to Dynegy-owned volumes received
at our field processing facilities that must operate for gas to meet natural gas pipeline quality specifications. The portion of equity natural gas and natural gas liquids that we hedge is monitored closely against our field processing plant
operations to ensure we hedge no more than the volume we own. We seek to mitigate correlation risk by hedging each natural gas liquid product against our physical production of that product. Realized income on hedged volumes was $1.9 million below
the average realized price for unhedged volumes for the third quarter 2004 as compared to $0.3 million below the average realized price for unhedged volumes for the third quarter 2003.



Results for our fractionation, storage and terminaling and transportation and logistics businesses increased $7 million for
the quarter ended September 30, 2004 compared to the quarter ended September 30, 2003. Volumes increased at both of our fractionators due to industry-wide increased liquids production primarily as a result of higher frac spreads. These higher
volumes also increased operating income in our supporting storage and natural gas liquids pipeline operations.



Wholesale marketing results increased approximately $2 million for the quarter ended September 30, 2004 compared to the same quarter in 2003. Wholesale
marketing results were favorably impacted by rising liquids prices.



Distribution and marketing services results increased approximately $13 million for the quarter ended September 30, 2004 compared to the same quarter ended September 30, 2003. Our results for this business were favorably impacted by steeply
rising liquids prices during the quarter ended September 30, 2004. In the marketing business, raw or mixed natural gas liquids volumes are purchased daily at the tailgate of gas processing plants. The mixed stream flows to our fractionation
facilities where the liquids are separated into specification products. Sales are made later in the period. In a rising commodity price environment, such as that experienced in the third quarter 2004, this results in a lower cost of goods relative
to the corresponding sales price. During periods when commodity prices fall, our distribution and marketing services business experiences the opposite effect. In times when natural gas liquids prices are relatively stable, there is little impact on
marketing operating income in either direction. This business also benefited in the third quarter 2004 from higher marketing fees.



CRM.Operating loss for the CRM segment was $32 million for the quarter ended September 30, 2004, compared to a loss of $26 million for the
quarter ended September 30, 2003. Results for both periods include losses associated with fixed payments on power tolling arrangements in excess of realized margins on power generated and sold pursuant to these agreements.



Other. Other operating loss was $54 million for the quarter
ended September 30, 2004, compared to a loss of $46 million for the quarter ended September 30, 2003. The increase in operating loss from 2003 to 2004 related to increased legal charges in 2004, as well as the reversal of a legal reserve in 2003.



Earnings from Unconsolidated Investments



Our earnings from unconsolidated investments were
approximately $26 million for the third quarter ended September 30, 2004, compared to $51 million for the quarter ended September 30, 2003.



GEN. GENs earnings from unconsolidated investments were approximately $23 million for the quarter ended September 30, 2004, compared
to $51 million for the quarter ended September 30, 2003. Earnings for the third quarter ended September 30, 2004 include a gain of $15 million on the sale of our 50% interest in the Oyster Creek facility. For the quarter ended September 30, 2004,
our equity earnings of $42 million from our investment in West Coast Power were offset by a $45 million impairment charge, resulting in a $3 million net loss. Please read OutlookGEN Outlook for further discussion of the
investment in West Coast Power.



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For the quarter ended September 30, 2003, earnings of $37 million from our West Coast Power investment
were the primary driver of results. Please read Item 1. BusinessSegment DiscussionPower GenerationWest regionWestern Electricity Coordinating Council (WECC) beginning on page 7 of our Form 10-K for further discussion of West
Coast Powers CDWR contract.



CRM.CRMs losses from unconsolidated investments were zero for the quarter ended September 30, 2004, compared to $2 million for the quarter ended September 30, 2003. As of December 31, 2003, CRM had no material unconsolidated investments.
As such, 2004 and future results are expected to be de minimis. The earnings in 2003 primarily related to our Nicor Energy joint venture, the operations of which were sold in the first half of 2003.



Interest Expense



Interest expense totaled $85 million for the quarter ended September 30,
2004, compared to $103 million for the quarter ended September 30, 2003. The decrease in 2004, as compared to 2003, is primarily due to $20 million in charges associated with deferred financing costs which were expensed in 2003 as a result of the
third quarter 2003 debt restructuring.



Other Items, net



Other items, net consists of other income and expense
items, net; minority interest income (expense) and accumulated distributions associated with trust preferred securities. Other items, net totaled an expense of $10 million for the quarter ended September 30, 2004, compared to $1 million for the
quarter ended September 30, 2003. The decrease in 2004, as compared to 2003, is due to increased minority interest expense.



Income Tax Benefit



We reported an income tax benefit for the quarter ended September 30, 2004 of $6 million. The effective tax rate for the quarter ended September 30,2004
was 54%, compared to 37% in 2003. The 2004 tax expense includes a $2 million benefit related to the release of reserves for tax contingencies. Excluding this item from the 2004 calculation would result in an effective tax rate of 36%. In general,
differences between these effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences.



Discontinued Operations



Discontinued operations includes our global liquids business in the NGL
segment and our U.K. natural gas storage assets and our U.K. CRM business in the CRM segment. The third quarter 2004 after-tax loss of $2 million is associated with our U.K. CRM business. The third quarter 2003 after-tax loss of $4 million is
comprised of $3 million in after-tax losses associated with U.K. CRM and the U.K natural gas storage assets and $1 million in after-tax losses from global liquids.



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Nine Months Ended September 30, 2004 and 2003



The following tables provide summary financial data regarding our consolidated and segmented results of operations for the
nine-month periods ended September 30, 2004 and 2003, respectively.



Nine Months Ended September 30, 2004



|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|----------------------------------------------- |  | ------------- | --- | --- | - | --- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ---- | -
|                                                |  | GEN           |     | NGL |   |     | CRM |  |   | Other andEliminations |   |  | Total |     
|                                                |  | (in millions) |    
|Operating income (loss)                         |  | $             | 158 |     | $ | 214 |     |  | $ | 45                    |   |  | $     | (194 | ) |  | $ | 223  |  
|Earnings from unconsolidated investments        |  |               | 110 |     |   | 7   |     |  |   |                      |   |  |       |     |   |  |   | 117  |  
|Other items, net                                |  |               |    |     |   | (15 | )   |  |   | (1                    | ) |  |       | 3    |   |  |   | (13  | )
|Interest expense                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (275 | )
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Income from continuing operations before taxes  |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 52   |  
|Income tax expense                              |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (13  | )
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Income from continuing operations               |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 39   |  
|Loss from discontinued operations, net of taxes |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (9   | )
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Net income                                      |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  | $ | 30   |  
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  



Nine Months Ended
September 30, 2003



|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|------------------------------------------------------------------ |  | ------------- | --- | --- | - | --- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ---- | -
|                                                                   |  | GEN           |     | NGL |   |     | CRM |  |   | Other andEliminations |   |  | Total |     
|                                                                   |  | (in millions) |    
|Operating income (loss)                                            |  | $             | 178 |     | $ | 121 |     |  | $ | (348                  | ) |  | $     | (190 | ) |  | $ | (239 | )
|Earnings from unconsolidated investments                           |  |               | 133 |     |   | 7   |     |  |   |                      |   |  |       |     |   |  |   | 140  |  
|Other items, net                                                   |  |               | 4   |     |   | (12 | )   |  |   | 27                    |   |  |       | (6   | ) |  |   | 13   |  
|Interest expense                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (239 | )
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Loss from continuing operations before taxes                       |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (325 | )
|Income tax benefit                                                 |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 121  |  
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Loss from continuing operations                                    |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (204 | )
|Loss from discontinued operations, net of taxes                    |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (14  | )
|Cumulative effect of change in accounting principles, net of taxes |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 57   |  
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Net loss                                                           |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  | $ | (161 | )
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  



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The following table provides summary segmented operating statistics for the nine months ended September
30, 2004 and 2003, respectively.



|                                                  |  |                                |         |      |   |        
|------------------------------------------------- |  | ------------------------------ | ------- | ---- | - | -------
|                                                  |  | Nine Months EndedSeptember 30,
|                                                  |  | 2004                           |         | 2003
|Power Generation                                  |  |                                |         |      |   |        
|Million megawatt hours generatedgross            |  |                                | 28.9    |      |   | 27.6   
|Million megawatt hours generatednet              |  |                                | 27.5    |      |   | 26.0   
|Average natural gas priceHenry Hub ($/MMbtu) (1) |  | $                              | 5.73    |      | $ | 5.35   
|Average on-peak market power prices ($/MWh):      |  |                                |         |      |   |        
|Cinergy                                           |  | $                              | 43      |      | $ | 41     
|Commonwealth Edison (NI Hub)                      |  | $                              | 42      |      | $ | 40     
|Southern                                          |  | $                              | 49      |      | $ | 44     
|New YorkZone G                                   |  | $                              | 61      |      | $ | 65     
|ERCOT                                             |  | $                              | 47      |      | $ | 47     
|SP-15                                             |  | $                              | 53      |      | $ | 53     
|Natural Gas Liquids                               |  |                                |         |      |   |        
|Gross NGL production (MBbls/d):                   |  |                                |         |      |   |        
|Field plants                                      |  |                                | 57.6    |      |   | 59.2   
|Straddle plants                                   |  |                                | 25.7    |      |   | 25.6   
|                                                  |  |                                |         |      |   |        
|Total gross NGL production                        |  |                                | 83.3    |      |   | 84.8   
|                                                  |  |                                |         |      |   |        
|Natural gas (residue) sales (Bbtu/d)              |  |                                | 185.2   |      |   | 167.3  
|Natural gas inlet volumes (MMCFD):                |  |                                |         |      |   |        
|Field plants                                      |  |                                | 549.4   |      |   | 589.1  
|Straddle plants                                   |  |                                | 968.8   |      |   | 1,153.4
|                                                  |  |                                |         |      |   |        
|Total natural gas inlet volumes                   |  |                                | 1,518.2 |      |   | 1,742.5
|                                                  |  |                                |         |      |   |        
|Fractionation volumes (MBbls/d)                   |  |                                | 218.6   |      |   | 183.5  
|Natural gas liquids sold (MBbls/d)                |  |                                | 281.4   |      |   | 305.0  
|Average commodity prices:                         |  |                                |         |      |   |        
|Crude oilWTI ($/Bbl)                             |  | $                              | 38.51   |      | $ | 31.38  
|Natural gasHenry Hub ($/MMbtu) (2)               |  | $                              | 5.81    |      | $ | 5.65   
|Natural gas liquids ($/Gal)                       |  | $                              | 0.67    |      | $ | 0.54   
|Fractionation spread ($/MMBtu)daily              |  | $                              | 1.84    |      | $ | 0.61   

---

|(1) | Calculated as the average of the daily gas prices for the period.
|--- | -----------------------------------------------------------------

|(2) | Calculated as the average of the first of the month prices for the period.
|--- | --------------------------------------------------------------------------



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The following tables summarize significant items on a pre-tax basis, with the exception of the 2004 tax
item, affecting net income (loss) for the periods presented.



|                                                     |  |                                      |     |   |     |   |    |     |  |   |       |   |  |       |     |   |  |   |      |  
|---------------------------------------------------- |  | ------------------------------------ | --- | - | --- | - | -- | --- |  | - | ----- | - |  | ----- | --- | - |  | - | ---- | -
|                                                     |  | Nine Months Ended September 30, 2004 |    
|                                                     |  | GEN                                  |     |   | NGL |   |    | CRM |  |   | Other |   |  | Total |    
|                                                     |  | (in millions)                        |    
|Discontinued operations                              |  | $                                    |    |   |     | $ | 1  |     |  | $ | 17    |   |  | $     |    |   |  | $ | 18   |  
|Legal and settlement charges                         |  |                                      | 2   |   |     |   | 2  |     |  |   |      |   |  |       | (54 | ) |  |   | (50  | )
|Impairment of West Coast Power                       |  |                                      | (45 | ) |     |   |   |     |  |   |      |   |  |       |    |   |  |   | (45  | )
|Acceleration of financing costs                      |  |                                      |    |   |     |   |   |     |  |   |      |   |  |       | (14 | ) |  |   | (14  | )
|Gas transportation contracts                         |  |                                      |    |   |     |   |   |     |  |   | 88    |   |  |       |    |   |  |   | 88   |  
|Taxes                                                |  |                                      |    |   |     |   |   |     |  |   |      |   |  |       | (15 | ) |  |   | (15  | )
|Gain on sale of Indian Basin                         |  |                                      |    |   |     |   | 36 |     |  |   |      |   |  |       |    |   |  |   | 36   |  
|Gain on sale of Hackberry LNG                        |  |                                      |    |   |     |   | 17 |     |  |   |      |   |  |       |    |   |  |   | 17   |  
|Gain on sale of Oyster Creek                         |  |                                      | 15  |   |     |   |   |     |  |   |      |   |  |       |    |   |  |   | 15   |  
|                                                     |  |                                      |     |   |     |   |    |     |  |   |       |   |  |       |     |   |  |   |      |  
|Total                                                |  | $                                    | (28 | ) |     | $ | 56 |     |  | $ | 105   |   |  | $     | (83 | ) |  | $ | 50   |  
|                                                     |  |                                      |     |   |     |   |    |     |  |   |       |   |  |       |     |   |  |   |      |  
|                                                     | 
|                                                     |  | Nine Months September 30, 2003       |    
|                                                     |  | GEN                                  |     |   | NGL |   |    | CRM |  |   | Other |   |  | Total |    
|                                                     |  | (in millions)                        |    
|Discontinued operations                              |  | $                                    |    |   |     | $ | (3 | )   |  | $ | (17   | ) |  | $     |    |   |  | $ | (20  | )
|Southern Power settlement                            |  |                                      |    |   |     |   |   |     |  |   | (133  | ) |  |       |    |   |  |   | (133 | )
|Sithe power tolling contract                         |  |                                      |    |   |     |   |   |     |  |   | (125  | ) |  |       |    |   |  |   | (125 | )
|Legal charges                                        |  |                                      |    |   |     |   |   |     |  |   |      |   |  |       | (50 | ) |  |   | (50  | )
|Kroger settlement                                    |  |                                      |    |   |     |   |   |     |  |   | (30   | ) |  |       |    |   |  |   | (30  | )
|Acceleration of financing cost                       |  |                                      |    |   |     |   |   |     |  |   |      |   |  |       | (24 | ) |  |   | (24  | )
|Gain on sale of Hackberry LNG                        |  |                                      |    |   |     |   | 10 |     |  |   | 2     |   |  |       |    |   |  |   | 12   |  
|Cumulative effect of change in accounting principles |  |                                      | 47  |   |     |   |   |     |  |   | 43    |   |  |       |    |   |  |   | 90   |  
|                                                     |  |                                      |     |   |     |   |    |     |  |   |       |   |  |       |     |   |  |   |      |  
|Total                                                |  | $                                    | 47  |   |     | $ | 7  |     |  | $ | (260  | ) |  | $     | (74 | ) |  | $ | (280 | )
|                                                     |  |                                      |     |   |     |   |    |     |  |   |       |   |  |       |     |   |  |   |      |  



Operating Income
(Loss)



Operating income was $223 million for the nine
months ended September 30, 2004, compared to a loss of $239 million for the nine months ended September 30, 2003.



GEN.Operating income for the GEN segment was $158 million for the nine months ended September 30, 2004, compared to $178 million for
the nine months ended September 30, 2003.



In the Midwest
region, where we produce approximately 60% of our generated volumes, results increased $21 million period over period. Average on-peak power prices were up 5%, contributing an additional $44 million for the nine months ended September 30, 2004
compared with the same period in 2003. However, improved pricing was partially offset by an increase in operating expenses for the Midwest of approximately $10 million, primarily as a result of the timing of maintenance expenditures. Additionally,
volumes were down slightly, from 15.8 million MWh for the nine months ended September 30, 2003 to 15.6 million MWh for the nine months ended September 30, 2004. This decrease was largely a result of reduced production at our Havana facility, as we
managed fuel inventories in anticipation of our switch to PRB coal, slightly offset by the timing of planned outages. Please read OutlookGEN Outlook for a discussion of the current fuel and transportation environment. For the
nine months ended September 30, 2004, we recorded a $3 million charge to earnings in connection with hedge ineffectiveness.



Improved results in the Midwest were partially offset by the results in the Northeast region, which were down $17 million, from $45 million for the nine
months ended September 30, 2003 to $28 million for the nine



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months ended September 30, 2004. This decrease was driven primarily by a $16 million decrease resulting from lower average prices during the nine months
ended September 30, 2004. Further, revenues for the nine months ended September 30, 2004 under a transitional power purchase agreement were $7 million less than in the same period in 2003. Results were also reduced by a $3 million increase in
operating expenses, primarily resulting from the timing of maintenance expenditures. Additionally, capacity revenues were lower for the nine months ended September 30, 2004, compared with the same period in 2003. However, the effects of pricing and
operating expense were partially offset by the benefit of increased volumes. For the nine months ended September 30, 2004, generated volumes were 5.1 million MWh, up 18% from the same period in 2003, primarily as a result of Rosetons dual fuel
capability and the cost advantage of burning fuel oil rather than natural gas. This increase in volume contributed an additional $13 million.



The decrease in operating income for the nine months ended September 30, 2004 also reflects the loss of approximately $19 million of capacity revenues in
the Southeast region related to a contract that expired at the end of 2003.



Depreciation expense increased $9 million, from $136 million for the nine months ended September 30, 2003 to $145 million for the same period in 2004.



GENs reported operating income for the 2004 and 2003 periods includes approximately $8 million and $4 million,
respectively, of mark-to-market income related to derivative contracts that did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market basis.



In March 2004, we tested our CoGen Lyondell facility for an impairment based
on the identification of a triggering event as defined by SFAS No. 144. After performing the test, we concluded that no impairment was necessary as the estimated undiscounted cash flows exceeded the book value of the facility.



NGL. Operating income for our NGL segment was $214 million for
the nine months ended September 30, 2004, compared to $121 million for the nine months ended September 30, 2003. Operating income for the nine months ended September 30, 2004 included pre-tax gains of $17 million and $36 million, respectively, from
our Hackberry LNG and Indian Basin sales, offset by increased depreciation expense of $6 million due to an adjustment to accumulated depreciation and an asset impairment of $5 million. Operating income for the nine months ended September 30, 2003
included a $10 million gain on sale of our ownership interest in the Hackberry LNG facility and a $3 million gain associated with the expiration of an environmental indemnity obligation. Please read Note 2Acquisitions, Dispositions, Contract
Terminations and Discontinued Operations for further discussion. Also, please read Item 1. BusinessSegment DiscussionNatural Gas Liquids beginning on page 8 of our Form 10-K for a detailed description of the NGL segment, including its
contract portfolio.



Our NGL segments profitability was
higher in all areas as compared to 2003.



Overall, gathering
and processing operating results increased by $24 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003. This was due largely to 3% higher absolute commodity prices for natural gas and 24% higher
absolute commodity prices for natural gas liquids compared to the same period in 2003. Frac spreads increased year over year yet remained lower than required to support liquids extraction under keep whole processing contracts until late July 2004.
At our field plants, results increased $22 million. Our improved contract portfolio period over period reflected our successful 2003 efforts to convert two major keep whole contracts to percentage of proceeds contracts. This contract portfolio of
nearly 98% percentage of proceeds, percentage of liquids and fee-based contracts benefited from higher natural gas liquid prices in the first nine months of 2004. However, gross and net natural gas liquids production declined and natural gas net to
our account decreased as compared to 2003 due to the difference in settlement terms between the two types of contracts and lower natural gas inlet and NGL production volumes resulting from the sale of our interest in Indian Basin in April 2004.
These declines were somewhat offset by higher than planned new natural gas production from higher levels of drilling activity by producers near our facilities. At our straddle plants,



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results increased $3 million. Straddle plant inlet volumes were negatively affected by uncertainty related to pipeline enforcement of dew point quality
specifications in 2004 as compared to 2003 until the third quarter 2004, when inlet volumes increased substantially as frac spreads supported economical extraction of natural gas liquids.



As a result of our percentage of proceeds and percentage of liquids contracts, we take ownership of natural gas and natural
gas liquids as payment for our services. We have established a comprehensive hedging strategy and related control procedures to manage price risk on these equity volumes. We limit the volume considered for hedging and forward selling to Dynegy-owned
volumes received at our field processing facilities that must operate for the gas to meet natural gas pipeline quality specifications. The portion of equity natural gas and natural gas liquids that we hedge is monitored closely against our field
processing plant operations to ensure we hedge no more than the volume we own. We seek to mitigate correlation risk by hedging each natural gas liquid product against our physical production of that product.



Results for our fractionation, storage and terminaling and transportation and
logistics businesses increased $12 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003. Volumes increased at both our Mont Belvieu and Lake Charles fractionators as a result of increased natural
gas liquids extraction at both our and third party gas processing facilities during the third quarter 2004.



Wholesale marketing results increased $1 million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003.



Distribution and marketing services results increased $16
million for the nine months ended September 30, 2004 compared to the nine months ended September 30, 2003. Our results for this business were favorably impacted by volatile and generally rising natural gas liquids prices. Additionally, in the second
quarter 2004, we terminated an inactive natural gas liquids sales contract which allowed us to recognize a $8 million gain on sales of natural gas liquids at current market prices that had previously been held outside our normal inventory at
historic below-current market prices. This increase was partially offset by recognition of well measurement losses in early 2004.



We tested certain of our assets for impairment based on identification of triggering events as defined by SFAS No. 144. After testing, we recorded a
pre-tax impairment in second quarter 2004 of $5 million for our Puckett gas treating plant and gathering system due to rapidly depleting reserves associated with that facility. We concluded that no impairment was necessary for any other facilities
as estimated undiscounted cash flows exceeded facility book values.



CRM. Operating income for our CRM segment was $45 million for the nine months ended September 30, 2004, compared to a loss of $348 million for the nine months ended September 30, 2003. In June 2004, we reached agreements to
exit four natural gas transportation contracts, which we originally entered into to secure firm pipeline capacity in support of our third-party marketing and trading business. In exchange for exiting these obligations, we paid $20 million in June
2004 and will pay $42 million in the first quarter 2005. These payments eliminate approximately $295 million in aggregate fixed capacity payments from April 2005 through 2014. In connection with the exit from these contracts, we reversed an
aggregate liability of $148 million, resulting in a net pre-tax gain of $88 million. This segments results for the first nine months of 2004 also reflect the impact of fixed payments on our remaining power tolling arrangements in excess of
realized margins on power generated and sold and include $10 million in gains associated with the mark-to-market value of certain legacy gas contracts which had previously been accounted for on an accrual basis.



Results for the first nine months of 2003 include a $133 million charge
associated with the settlement of power tolling arrangements with Southern Power, $125 million in mark-to-market losses on contracts associated with our Sithe Independence power tolling arrangement and a $30 million charge associated with the
settlement of power supply agreements with Kroger. Additionally, 2003 results include gains from the sale of natural gas inventories of $61 million, offset by charges associated with the settlement of legacy contracts of $21 million and changes in
the value of our remaining marketing and trading activity.



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Other. Other operating loss was $194 million for the nine months ended September 30, 2004,
compared to $190 million for the nine months ended September 30, 2003. Results for 2004 include approximately $54 million of expenses related to increased legal and settlement charges. Please read Note 3Restructuring Charges for a discussion
of the settlement charges. Operating loss for 2003 includes increased legal charges of $50 million. The increased legal charges in both periods resulted from additional activities during each period that affected managements assessment of the
probable and estimable loss associated with the applicable proceedings.



Earnings from Unconsolidated Investments



Our earnings from unconsolidated investments were approximately $117 million for the nine months ended September 30, 2004, compared to $140 million for the nine months ended September 30, 2003.



GEN. GENs earnings from unconsolidated investments were
approximately $110 million for the nine months ended September 30, 2004, compared to $133 million for the nine months ended September 30, 2003. Earnings for 2004 include a gain of $15 million on the sale of our 50% interest in the Oyster Creek
facility. Also in July 2004, we sold our 50% interest in the 123 MW Michigan Power generating facility for net cash proceeds of approximately $25 million. In the nine months ended September 30, 2004, we recorded impairments of approximately $8
million related to the anticipated sale of Michigan Power which offset our share of Michigan Powers earnings for the nine month period. The net loss related to Michigan Power recorded in the nine months ended September 30, 2004 was $2 million.
Earnings from our West Coast Power investment were $123 million for the nine months ended September 30, 2004, however, these earnings were partly offset by a $45 million impairment charge.



For the nine months ended September 30, 2003, equity earnings were driven
primarily by our investment in West Coast Power, which contributed $102 million. Please read Item 1. BusinessSegment DiscussionPower GenerationWest regionWestern Electricity Coordinating Council (WECC) beginning on page 7 of
our Form 10-K for further discussion of West Coast Powers CDWR contract. Please read Note 8Commitments and ContingenciesFERC and Related Regulatory InvestigationsRequests for Refund for further discussion of the legal
challenges to the CDWR contract.



NGL. NGLs
earnings from unconsolidated investments were approximately $7 million for each of the nine months ended September 30, 2004 and the nine months ended September 30, 2003.



Interest Expense



Interest expense totaled $275 million for the nine months ended September 30, 2004, compared to $239 million for the nine months ended September 30, 2003.
The increase in 2004, as compared to 2003, is primarily attributable to higher average interest rates on debt incurred in connection with our August and October 2003 debt refinancings. This increase is partially offset by reduced amortization of
deferred financing costs.



Other Items, net



Other items, net consists of other income and expense
items, net; minority interest income (expense) and accumulated distributions associated with trust preferred securities. Other items, net totaled an expense of $13 million for the nine months ended September 30, 2004, compared to income of $13
million for the nine months ended September 30, 2003. The decrease in 2004, as compared to 2003, is primarily due to higher minority interest expense.



Income TaxExpense



We reported an income tax expense during the nine months ended September 30,
2004 of $13 million. The 2004 effective tax rate was 25%, compared to 37% in 2003. The 2004 tax benefit includes a $5 million benefit



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primarily related to the conclusion of prior year tax audits. Please read Note 11Income Taxes for further discussion. Excluding these items from the
2004 calculation would result in an effective tax rate of 35%. In general, differences between these effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences
attributable to book-tax basis differences.



Discontinued
Operations



Discontinued operations includes our
global liquids business in the NGL segment and our U.K. natural gas storage assets and our U.K. CRM business in the CRM segment. The largest contributor to the pre-tax gain of $18 million ($9 million after-tax loss) for the nine months ended
September 30, 2004 is the U.K. CRM business, primarily due to $20 million in tax expenses related to the conclusion of prior year tax audits partially offset by translation gains recognized on the repatriation of cash from the U.K. Please read Note
11Income Taxes for further discussion. The loss of $14 million for the nine-month period ended September 30, 2003 is comprised of $12 million in after-tax losses on operations of the U.K. CRM business and $2 million in after-tax losses from
global liquids.



Cumulative Effect of Change in
Accounting Principles



EITF Issue 02-03s
rescission of EITF Issue 98-10 effective January 1, 2003 is reflected as a cumulative effect of a change in accounting principle. The net impact was a pre-tax benefit of $33 million ($21 million after-tax), of which a benefit of $43 million was
recognized in our CRM segment and a charge of $10 million was recognized in our GEN segment. We also adopted SFAS No. 143 effective January 1, 2003 and recognized a pre-tax benefit of $57 million ($36 million after-tax) associated with its
implementation.



Please read Note 1Accounting Policies
for further discussion of our adoption of new accounting policies.



Outlook



The following summarizes our business outlook for our
three reportable segments.



GEN Outlook. This
segments future financial results will continue to reflect a sensitivity to commodity prices and weather conditions. We will continue our efforts to manage price risk through the optimization of fuel procurement and the marketing of power
generated from our assets, including through forward sales and related transactions. Our sensitivity to commodity prices and our ability to manage this sensitivity is subject to a number of factors, including general market liquidity, particularly
in forward years, our ability to provide necessary collateral support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings. Additionally, because we seek to manage price risk through
forward sales and related transactions, at times we may be unable to capture opportunities presented by rising prices.



The operation of our generation facilities is highly dependent on our ability to procure coal as a fuel. Power generators in the Midwest and the Northeast
are experiencing significant pressures on available coal supplies that are either transportation or supply related. Our long-term supply and transportation agreements for our Midwest fleet mitigate these concerns. In the Northeast, we have
accumulated sufficient inventories to allow us to operate our assets.



As discussed in Item 1. BusinessSegment DiscussionPower Generation beginning on page 3 of our Form 10-K, we enter into sales of capacity from our generation assets, which provide a revenue stream independent of energy sales. In
late 2003 and continuing throughout 2004, we have seen increases in the market for capacity-related products from our peaking and intermediate generation facilities.



At the beginning of 2004, a substantial portion of our 2004 operating margin and Earnings from unconsolidated investments
was under contract or hedged. The primary contracts included the CDWR contract



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held by West Coast Power and the Illinois Power power purchase agreement. Our future results of operations will be significantly impacted by these
agreements. West Coast Power, whose equity earnings are primarily derived from the CDWR contract, has been our largest contributor in terms of earnings from unconsolidated investments. If we are unable to enter into a new contract for the operation
of our West Coast Power assets, earnings from the investment will be substantially reduced. Based on our ongoing evaluation of strategic alternatives for our West Coast Power assets, we have determined that it is not economically feasible to
continue to operate our Long Beach generation facility beyond the expiration of the CDWR contract. Therefore, we intend to retire the asset as of December 31, 2004. Additionally, regardless of our ability to extend or enter into a new contract, the
scheduled expiration of the CDWR contract in December 2004 will negatively impact the fair value of our investment in West Coast Power. As the value of the CDWR contract is realized through 2004, the fair value of our investment in West Coast Power
will decline and, accordingly, we anticipate that the remaining value of the investment will be less than its book value. As a result, we recorded an impairment of $45 million in the third quarter 2004. We will continue to evaluate our investment
quarterly and anticipate such reviews will necessitate an additional impairment of our investment of approximately $30 million to $40 million during the remainder of 2004. Please read Note 8Commitments and ContingenciesFERC and Related
Regulatory Investigations Request for Refunds for further discussion of the legal challenges to the CDWR contract. Please also read Liquidity and Capital ResourcesInternal Liquidity SourcesCash Flows from
Operations for a discussion of our efforts to seek a renewal or replacement of the CDWR contract.



The current power purchase agreement between DMG and Illinois Power will terminate on December 31, 2004. In September 2004, in connection with the sale of
Illinois Power to Ameren, DPM entered into a two-year power purchase agreement with Illinois Power with expected volumes comparable to our current agreement. Under the terms of this new agreement, which is effective January 1, 2005, we have agreed
to provide Illinois Power with up to 2,800 MWs of capacity at $48.00 per kW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. Under this arrangement, we will no longer be the provider of last resort for Illinois
Power, which exposed us to volume and price uncertainties under the current contract. However, the structure of the new arrangement differs from the current power purchase agreement with Illinois Power. Under the current agreement, we receive
contract revenues based on a higher fixed capacity payment and lower variable energy payments. Accordingly, GENs operating income under the new agreement will be impacted more significantly by deviations from expected energy purchases by
Illinois Power. We expect that any reduction in operating income under this new agreement will be mitigated by no longer serving as the provider of last resort.



We recently sold our 50% interests in the 424 MW Oyster Creek generating facility, the 123 MW Michigan Power generating facility and the 310 MW
Hartwell generating facility. In addition, we recently executed an agreement to sell our 50% interest in the 310 MW Commonwealth natural gas fired peaking facility. Our investments in these four facilities contributed approximately $24 million in
earnings to our full year 2003 results, exclusive of any impairment charges. Please read Note 5Unconsolidated Investments for further discussion of these investments.



In November 2004, Dynegy entered into an agreement to acquire entities that own the 1,042-megawatt, 7,211-Btu heat rate,
combined-cycle Independence power generation facility, four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. Please read Managements Discussion and Analysis of Financial
Condition and Results of OperationsGeneralSithe Energies for further discussion of this transaction.



NGL Outlook.The outlook for our NGL segment has remained the same throughout 2004. Financial results will continue to reflect a high degree
of sensitivity to natural gas and natural gas liquids prices. We expect the pricing environment for the rest of 2004 will continue to be strong for both commodities. Upstream contract settlements under percentage of proceeds and percentage of
liquids contracts will continue to benefit from these relatively high prices. We saw economic frac spreads in the third quarter, and we expect these frac spreads to stay economical during the first half of the fourth quarter. If frac spreads decline
to uneconomic levels, our hybrid contracts, which are sensitive to frac spread, will generally revert from percentage of liquids settlements



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back to fee settlements. The amount of natural gas liquids volumes produced from both our own and third-party natural gas processing plants will continue to
fluctuate as frac spread economics either support natural gas liquids extraction or do not.



There seems to be a widely held belief that, long term, natural gas prices will remain high enough relative to natural gas liquids prices to depress the frac spread below levels required for liquids extraction,
reducing natural gas liquid volumes requiring fractionation. As a result, there remains aggressive competition between fractionators for available volumes, causing a reduction in fees paid for fractionation services. Effective October 2004, we lost
a substantial fractionation customer at our Mont Belvieu fractionator when the previous contract reached the end of its primary term. The customer committed the volumes to a competitor as part of a larger asset sale. We continue to compete for
replacement volumes in a tight market.



Gulf of Mexico straddle
plant gas processing will continue to be negatively impacted by uncertainty surrounding gas quality specifications for liquefiable hydrocarbons. Over the past several years, extraction economics have been generally poor, causing pipeline companies
to become increasingly concerned about heavy hydrocarbons that have been left in natural gas entering their systems instead of being extracted. These heavy hydrocarbons cause pipeline operational and safety concerns. While industry stakeholders
respond to recent FERC decisions directing pipeline companies to address this issue in their tariff, there is a lack of clarity around when and where processing is required. The result is a patchwork of pipeline policies and practices that leave
producers and processors without clearly defined ground rules, making contracting gas and planning straddle plant operations difficult. Resolution of the issue is currently being pursued through the Natural Gas Council, FERC and other affected
stakeholders.



Drilling rig rates for natural gas throughout
our core processing areas in New Mexico, West Texas, North Texas and offshore Louisiana continue to increase, consistent with natural gas prices that have averaged $5 - $8/MMBtu. Continued exploration and production at these commodity
price levels will benefit our upstream business by providing additional volumes for gathering and processing. If natural gas prices were to decline in the future, resulting in reduced drilling activities, this segments results could be
adversely affected.



While we have not experienced significant
turnover in customer contracts as a result of our non-investment grade credit ratings, we have been required to provide collateral or other adequate assurance of our obligations in connection with many of our commercial relationships. On occasion,
we have been unable to satisfy efficiently a potential new customers concerns about our credit ratings. We expect similar collateral requirements until such time as our credit ratings measurably improve. Our ability to hedge future natural gas
liquids production during 2004 will again be limited by reduced market liquidity and our obligation to post collateral. As commodity prices rise, we are required by counterparties to post additional collateral.



We intend to prudently continue our North Texas gathering system expansion
working collaboratively with our producer customers. Additional compression and plant debottlenecking are expected to add volumes to our expanded Chico gas processing plant. In addition, we continue to review our asset portfolio to maximize return
on investment. In 2004, we identified and sold several assets that were not strategic to our core operations, including our interests in Hackberry LNG and Indian Basin and our Sherman facility. We may pursue sales of other assets if the price is
sufficient to mitigate the anticipated impact on future earnings. Please see Liquidity and Capital ResourcesExternal Liquidity SourcesAsset Sale Proceeds for further discussion.



CRM Outlook.Our CRM business future results of
operations will be significantly impacted by our ability to complete our exit from this business. Although we were successful in reaching agreements to exit four of our natural gas transportation agreements in the second quarter 2004, the CRM
segment remains comprised primarily of four power tolling arrangements, as well as gas transportation agreements and legacy power and gas trading positions. However, in November 2004, Dynegy entered into an agreement to purchase from Exelon
Corporation all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies and Sithe Independence, L.P. Please read Note 2Acquisitions, Dispositions, Contract Terminations and Discontinued



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OperationsAcquisitionsSithe Energies for further discussion. As a result of this agreement, our power tolling arrangement with Sithe will be
transformed into an intercompany agreement, substantially eliminating its future financial impact by retaining the net cash flows within our subsidiaries.



Also in November 2004, DPM entered into a power purchase agreement with Constellation Energy Commodities Group, Inc. under which Constellation will
receive DPMs rights to purchase approximately 570 megawatts of capacity and energy arising under DPMs tolling contract with LSP-Kendall Energy, LLC for a four year term from December 2004 through November 2008. DPM will remain party to
the Kendall tolling contract, but will receive offsetting payments from Constellation during the four year term.



Concurrently with the execution of the power purchase agreement, DPM and Constellation entered into an assignment agreement pursuant to which DPM would
transfer to Constellation all of its rights and obligations under the Kendall tolling contract through November 2008. The assignment will only become effective upon the satisfaction of a number of conditions, including the receipt of
LSP-Kendalls consent, and upon such effectiveness the Constellation power purchase agreement would terminate.



In connection with these transactions, DPM paid to Constellation $117.5 million in cash and effectively eliminated approximately $165 million in our
future fixed payment obligations under the Kendall tolling contract through November 2008.



Although our Gregory tolling arrangement expires by its terms in July 2005, our other two tolling arrangements, excluding Sithe, extend through 2012 to 2017. We are exploring opportunities to assign or renegotiate the
terms of these arrangements, as demonstrated by our power purchase agreement and contingent assignment agreement with Constellation, but we cannot guarantee that we will be successful. If we do not assign, renegotiate or terminate these remaining
arrangements, they will continue to impact negatively our near- and long-term earnings and cash flows based on the current pricing environment. Any assignment, renegotiation or termination of these long-term contracts would likely result in
significant cash payments and a charge to earnings in the applicable period. For a discussion of our annual and long-term obligations under these arrangements, please read Disclosure of Contractual Obligations and Contingent Financial
Commitments and Item 1. BusinessSegment DiscussionCustomer Risk Management beginning on page 15 of our Form 10-K.



Until the closing of Dynegys Sithe Energies acquisition, the earnings of the CRM segment may also be significantly impacted, either positively or
negatively, by mark-to-market changes in the value of a derivative contract associated with the Sithe Independence tolling agreement as power and gas prices change.



As of November 8, 2004, we have posted approximately $117 million of collateral associated with this business. Approximately
$15 million of this balance relates to our tolling arrangements. The remaining $102 million is related to our legacy gas and power trading positions, which collateral will be substantially eliminated by 2007.



Cash Flow Disclosures



The following table presents operating cash flows by reportable segment and includes cash flows from our discontinued
operations, which are disclosed on a net basis in loss from discontinued operations, net of tax, in the condensed consolidated statements of operations:



|                                             |  |               |     |     |   |     |  |   |                     |   |  |              |      |   |  |   |     |  
|-------------------------------------------- |  | ------------- | --- | --- | - | --- |  | - | ------------------- | - |  | ------------ | ---- | - |  | - | --- | -
|                                             |  | GEN           |     | NGL |   | CRM |  |   | Other &Eliminations |   |  | Consolidated |     
|                                             |  | (in millions) |    
|For the nine months ended September 30, 2004 |  | $             | 351 |     | $ | 194 |  | $ | (179                | ) |  | $            | (428 | ) |  | $ | (62 | )
|                                             |  |               |     |     |   |     |  |   |                     |   |  |              |      |   |  |   |     |  
|For the nine months ended September 30, 2003 |  | $             | 309 |     | $ | 156 |  | $ | 600                 |   |  | $            | (263 | ) |  | $ | 802 |  
|                                             |  |               |     |     |   |     |  |   |                     |   |  |              |      |   |  |   |     |  



Operating Cash
Flow. Our net cash used by operating activities totaled $62 million for the nine months ended September 30, 2004. During the period, our GEN and NGL segments provided positive cash flow from



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operations. GEN provided cash flow from operations of $351 million due primarily to positive earnings for the period, partially offset by increased cash
collateral posted in lieu of letters of credit and NGL provided cash flow from operations of $194 million due primarily to positive earnings, partially offset by increased prepayments due to higher sales. Our CRM segment used approximately $179
million in cash due primarily to fixed payments associated with the power tolling arrangements and related gas transportation agreements, increased cash collateral posted in lieu of letters of credit and our exit from four long-term natural gas
transportation contracts. Other & Eliminations includes a use of approximately $428 million in cash due primarily to interest payments to service debt, settlement payments and general and administrative expenses.



Our net cash provided by operating activities totaled $802 million for the
nine months ended September 30, 2003. Cash provided in 2003 primarily relates to collateral returns, settlements of risk management assets and sales of natural gas in storage from our CRM business, a $85 million income tax refund reflected in Other
& Eliminations and the operational performances of our GEN and NGL segments. Our GEN segment provided cash flows of $309 million largely due to strong commodity prices. Similarly, our NGL segment contributed cash flows from operations of $156
million due primarily to increasing commodity prices, which benefited our upstream and marketing businesses, offset by higher prepayments. General and administrative costs and continued extinguishment of liabilities during our exit from our
communications business partially offset these positive operational cash flows during the nine months ended September 30, 2003.



Capital Expenditures and Investing Activities. Net cash used in investing activities during the nine months ended September 30, 2004 totaled
$150 million. Capital spending of $129 million was comprised primarily of $78 million and $41 million in the GEN and NGL segments, respectively. The capital spending for our GEN segment related primarily to maintenance capital projects, as well as
approximately $16 million related to developmental projects. Capital spending in our NGL segment related primarily to maintenance capital projects and wellconnects, as well as approximately $15 million on developmental projects. Proceeds from asset
sales of $197 million consisted primarily of the following items:



| |  | $132 million from the sale of our equity investments in the Oyster Creek, Hartwell and Michigan Power generating facilities;
| | - | ----------------------------------------------------------------------------------------------------------------------------



| |  | $48 million from the sale of Indian Basin; and
| | - | ----------------------------------------------



| |  | $17 million from the sale of our remaining financial interest in the Hackberry LNG project.
| | - | -------------------------------------------------------------------------------------------



Net cash used in investing activities during the nine months ended September 30, 2003 totaled $353 million. Capital spending
of $157 million was comprised principally of $116 million and $36 million in our GEN and NGL segments, respectively, representing primarily improvements to our existing asset base. The capital spending for our GEN segment included approximately $39
million spent on the construction of Rolling Hills, with respect to which commercial operation began in June 2003. Proceeds from asset sales included primarily $20 million from the sale of SouthStar and $20 million from the sale of our ownership
interest in the Hackberry LNG project.



Financing
Activities.Net cash provided by financing activities during the nine months ended September 30, 2004 totaled $300 million. The cash provided was due primarily to proceeds from our $600 million secured term loan, net of issuance costs of $19
million, which was offset by repayments of long-term debt. Repayments of long-term debt totaled $265 million for the nine months ended September 30, 2004 and consisted primarily of the following: (1) payments of $185 million under our ABG Gas Supply
financing; and (2) payments of $78 million on the Tilton capital lease.



Net cash used in financing activities during the nine months ended September 30, 2003 totaled $581 million. During the nine months ended September 30, 2003, we repaid $128 million, net, under our revolving credit facilities. Long-term debt
proceeds, net of issuance costs, for the nine months ended September 30, 2003 consisted of $1,393 million associated with the August 2003 refinancing, and $159 million from the Term A



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Loan drawn in connection with the April 2, 2003 credit facility restructuring. Repayments of long-term debt totaled $1,989 million for the nine months ended
September 30, 2003 and consisted primarily of the following:



| |  | Funding of $200 million payments under the Renaissance and Rolling Hills interim financing;
| | - | -------------------------------------------------------------------------------------------



| |  | Prepaying the $696 million outstanding under the Black Thunder secured financing;
| | - | ---------------------------------------------------------------------------------



| |  | Purchasing approximately $609 million of our previously outstanding 2005/2006 public notes;
| | - | -------------------------------------------------------------------------------------------



| |  | Prepaying in full the $200 million Term A loan outstanding under our restructured credit facility;
| | - | --------------------------------------------------------------------------------------------------



| |  | Prepaying $167 million of the $360 million Term B loan outstanding under our restructured credit facility; and
| | - | --------------------------------------------------------------------------------------------------------------



| |  | Funding of $62 million in the Black Thunder secured financing and $55 million in ABG Gas Supply financing.
| | - | ----------------------------------------------------------------------------------------------------------



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RISK-MANAGEMENT DISCLOSURES



The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance
sheets, statements of operations and statements of cash flows:



|                                                                                      |  |                                                      |      |  
|------------------------------------------------------------------------------------- |  | ---------------------------------------------------- | ---- | -
|                                                                                      |  | As of and for theNine Months EndedSeptember 30, 2004 |     
|                                                                                      |  | (in millions)                                        |     
|Balance Sheet Risk-Management Accounts                                                |  |                                                      |      |  
|Fair value of portfolio at January 1, 2004                                            |  | $                                                    | (137 | )
|Risk-management gains recognized through the income statement in the period, net      |  |                                                      | 8    |  
|Cash paid related to risk-management contracts settled in the period, net             |  |                                                      | 41   |  
|Changes in fair value as a result of a change in valuation technique (1)              |  |                                                      |     |  
|Non-cash adjustments and other (2)                                                    |  |                                                      | (78  | )
|                                                                                      |  |                                                      |      |  
|Fair value of portfolio at September 30, 2004                                         |  | $                                                    | (166 | )
|                                                                                      |  |                                                      |      |  
|Income Statement Reconciliation                                                       |  |                                                      |      |  
|Risk-management gains recognized through the income statement in the period, net      |  | $                                                    | 8    |  
|Physical business recognized through the income statement in the period, net (3)      |  |                                                      | 15   |  
|Non-cash adjustments and other                                                        |  |                                                      | 3    |  
|                                                                                      |  |                                                      |      |  
|Net recognized operating income                                                       |  | $                                                    | 26   |  
|                                                                                      |  |                                                      |      |  
|Cash Flow Statement                                                                   |  |                                                      |      |  
|Cash paid related to risk-management contracts settled in the period, net             |  | $                                                    | (41  | )
|Estimated cash received related to physical business settled in the period, net (3)   |  |                                                      | 15   |  
|Timing and other, net (4)                                                             |  |                                                      | 28   |  
|                                                                                      |  |                                                      |      |  
|Cash received during the period                                                       |  | $                                                    | 2    |  
|                                                                                      |  |                                                      |      |  
|Risk-management cash flow adjustment for the nine months ended September 30, 2004 (5) |  | $                                                    | (24  | )
|                                                                                      |  |                                                      |      |  

---

|(1) | Our modeling methodology has been consistently applied.
|--- | -------------------------------------------------------

|(2) | This amount primarily consists of changes in value associated with cash flow hedges on forward power sales.
|--- | -----------------------------------------------------------------------------------------------------------

|(3) | This amount includes the $88 million gain recognized by our exit from four gas transportation contracts offset by capacity payments on our power tolling arrangements.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | This amount consists primarily of cash received in connection with the settlement of cash flow hedges.
|--- | ------------------------------------------------------------------------------------------------------

|(5) | This amount is calculated as Cash received during the period less Net recognized operating income.
|--- | ------------------------------------------------------------------------------------------------------



The net risk-management liability of $166 million is the aggregate of the
following line items on the condensed consolidated balance sheets: Current AssetsAssets from risk-management activities, Other AssetsAssets from risk-management activities, Current LiabilitiesLiabilities from risk-management
activities and Other LiabilitiesLiabilities from risk-management activities.



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Risk-Management Asset and Liability Disclosures. The following tables depict the
mark-to-market value and cash flow components of our net risk-management assets and liabilities at September 30, 2004 and December 31, 2003:



Mark-to-Market Value of Net Risk-Management Assets (1)



|                    |  |               |      |   |         |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  
|------------------- |  | ------------- | ---- | - | ------- | - | --- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- |  | - | --- | - |  | - | --- | -
|                    |  | Total         |      |   | 2004(2) |   |     | 2005 |  |   | 2006 |   |  | 2007 |     |   | 2008 |   |     | Thereafter | 
|                    |  | (in millions) |     
|September 30, 2004  |  | $             | (121 | ) |         | $ | (11 | )    |  | $ | (22  | ) |  | $    | (12 | ) |      | $ | (46 | )          |  | $ | (17 | ) |  | $ | (13 | )
|December 31, 2003   |  |               | (144 | ) |         |   | (22 | )    |  |   | (17  | ) |  |      | (25 | ) |      |   | (39 | )          |  |   | (12 | ) |  |   | (29 | )
|                    |  |               |      |   |         |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  
|Increase (decrease) |  | $             | 23   |   |         | $ | 11  |      |  | $ | (5   | ) |  | $    | 13  |   |      | $ | (7  | )          |  | $ | (5  | ) |  | $ | 16  |  
|                    |  |               |      |   |         |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  

---

|(1) | The table reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These
amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management liabilities at September 30, 2004 of $166 million on the unaudited condensed consolidated balance sheets include the $121
million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Amounts represent October 1 to December 31, 2004 values in the September 30, 2004 row and January 1 to December 31, 2003 values in the December 31, 2003 row.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------



Cash Flow Components of Net Risk-Management
Assets



|                       |  |                                   |    |   |                                   |   |     |           |  |   |      |   |  |      |     |   |      |   |     |      |  |   |            |   |  |   |     |   |  |   |     |  
|---------------------- |  | --------------------------------- | -- | - | --------------------------------- | - | --- | --------- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---- |  | - | ---------- | - |  | - | --- | - |  | - | --- | -
|                       |  | Nine MonthsEndedSeptember 30,2004 |    |   | Three MonthsEndedDecember 31,2004 |   |     | Total2004 |  |   | 2005 |   |  | 2006 |     |   | 2007 |   |     | 2008 |  |   | Thereafter |  
|                       |  | (in millions)                     |   
|September 30, 2004 (1) |  | $                                 | (3 | ) |                                   | $ | (11 | )         |  | $ | (14  | ) |  | $    | (21 | ) |      | $ | (11 | )    |  | $ | (49        | ) |  | $ | (19 | ) |  | $ | (15 | )
|December 31, 2003      |  |                                   |    |   |                                   |   |     |           |  |   | (17  | ) |  |      | (14 | ) |      |   | (24 | )    |  |   | (43        | ) |  |   | (15 | ) |  |   | (39 | )
|                       |  |                                   |    |   |                                   |   |     |           |  |   |      |   |  |      |     |   |      |   |     |      |  |   |            |   |  |   |     |   |  |   |     |  
|Increase (Decrease)    |  |                                   |    |   |                                   |   |     |           |  | $ | 3    |   |  | $    | (7  | ) |      | $ | 13  |      |  | $ | (6         | ) |  | $ | (4  | ) |  | $ | 24  |  
|                       |  |                                   |    |   |                                   |   |     |           |  |   |      |   |  |      |     |   |      |   |     |      |  |   |            |   |  |   |     |   |  |   |     |  

---

|(1) | The cash flow values for 2004 reflect realized cash flows for the nine months ended September 30, 2004 and anticipated undiscounted cash inflows and outflows by contract based on
the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative
instruments designated as hedges.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The following
table provides an assessment of net contract values by year as of September 30, 2004, based on our valuation methodology:



Net Fair Value of Risk-Management Portfolio



|                       |  |               |      |   |      |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  
|---------------------- |  | ------------- | ---- | - | ---- | - | --- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- |  | - | --- | - |  | - | --- | -
|                       |  | Total         |      |   | 2004 |   |     | 2005 |  |   | 2006 |   |  | 2007 |     |   | 2008 |   |     | Thereafter | 
|                       |  | (in millions) |     
|Market Quotations (1)  |  | $             | (86  | ) |      | $ | (11 | )    |  | $ | (22  | ) |  | $    | (12 | ) |      | $ | (33 | )          |  | $ | (8  | ) |  | $ |    |  
|Prices Based on Models |  |               | (35  | ) |      |   |    |      |  |   |     |   |  |      |    |   |      |   | (13 | )          |  |   | (9  | ) |  |   | (13 | )
|                       |  |               |      |   |      |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  
|Total                  |  | $             | (121 | ) |      | $ | (11 | )    |  | $ | (22  | ) |  | $    | (12 | ) |      | $ | (46 | )          |  | $ | (17 | ) |  | $ | (13 | )
|                       |  |               |      |   |      |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  

---

|(1) | Prices obtained from actively traded, liquid markets for commodities other than natural gas positions. All natural gas positions for all periods are contained in this line based on
available market quotations.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

[LEGAL TO UPDATE]



This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as
forward-looking statements. All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect,
believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown
risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to
historical or current facts. They use words such as anticipate, estimate, project, forecast, plan, may, will, should, expect and other words
of similar meaning. In particular, these include, but are not limited to, statements relating to the following:



| |  | projected operating or financial results, including anticipated cash flows from operations and asset sale proceeds for 2004;
| | - | ----------------------------------------------------------------------------------------------------------------------------



| |  | expectations regarding capital expenditures, interest expense and other payments;
| | - | ---------------------------------------------------------------------------------



| |  | our ability to execute the cost-savings measures we have identified;
| | - | --------------------------------------------------------------------



| |  | our beliefs and assumptions relating to our liquidity position, including our ability to satisfy or refinance our significant debt maturities and other obligations before or as they
come due;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our ability to access the capital markets as and when needed;
| | - | -------------------------------------------------------------



| |  | our ability to address our substantial leverage;
| | - | ------------------------------------------------



| |  | our ability to compete effectively for market share with industry participants;
| | - | -------------------------------------------------------------------------------



| |  | beliefs about the outcome of legal and administrative proceedings, including matters involving the western power and natural gas markets, Dynegys shareholder claims and
environmental and master netting agreement matters, as well as the investigations primarily relating to Project Alpha and our past trading practices;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our and Dynegys ability to consummate the disposition of specified non-strategic assets on the terms and in the timeframes anticipated;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------



| |  | Dynegys ability to consummate the Sithe Energies acquisition and, if consummated, Dynegys ability to integrate the acquired entities and their operations and achieve its
financial and operational goals associated with that acquisition;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our ability to complete our exit from the CRM business, including the ability of the consolidated enterprise to address our Sithe tolling arrangement through consummation of
Dynegys Sithe Energies acquisition, and the costs associated with this exit; and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our ability to consummate the assignment of our rights and obligations under the Kendall tolling contract to Constellation through November 2008.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------



Any or all of our forward-looking statements may turn out to be wrong. They
can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors including, among others:



| |  | the timing and extent of changes in weather and commodity prices, including the relationships between prices for power and natural gas or other power generating fuels, commonly
referred to as the spark spread, and the frac spread;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the effects of competition in our asset-based business lines;
| | - | -------------------------------------------------------------



| |  | the effects of the proposed sales of specified non-strategic assets;
| | - | --------------------------------------------------------------------



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| |  | the effects of Dynegys Sithe Energies acquisition and the consolidation of the related project debt;
| | - | -----------------------------------------------------------------------------------------------------



| |  | our ability to renew or replace West Coast Powers CDWR power purchase agreement;
| | - | ---------------------------------------------------------------------------------



| |  | the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions, and Dynegys ability to
engage in capital-raising transactions;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the financial condition of the consolidated enterprise, including its ability to satisfy its significant debt maturities and debt service obligations;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our ability to realize our significant deferred tax assets, including loss carryforwards;
| | - | -----------------------------------------------------------------------------------------



| |  | the effectiveness of our risk-management policies and procedures and the ability of our counterparties to satisfy their financial commitments;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------



| |  | the liquidity and competitiveness of wholesale trading markets for energy commodities, particularly natural gas, electricity and natural gas liquids;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------



| |  | operational factors affecting the start up or ongoing commercial operations of our power generation, natural gas and natural gas liquids facilities, including catastrophic
weather-related damage, regulatory approvals, permit issues, unscheduled blackouts, outages or repairs, unanticipated changes in fuel costs or availability of fuel emission credits, the unavailability of gas transportation and the unavailability of
electric transmission service or workforce issues;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | increased interest expense and restrictive covenants resulting from our non-investment grade credit rating;
| | - | -----------------------------------------------------------------------------------------------------------



| |  | counterparties collateral demands and other factors affecting our liquidity position and financial condition;
| | - | --------------------------------------------------------------------------------------------------------------



| |  | our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) tightly and generate earnings and cash flow
from our asset-based businesses in relation to our substantial debt and other obligations;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the direct or indirect effects on our business of any further downgrades in our credit ratings (or actions we may take in response to changing credit ratings criteria), including
refusal by counterparties to enter into transactions with us and our inability to obtain credit or capital in amounts or on terms that are considered favorable;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including legal proceedings related to the western power and natural gas
markets, shareholder claims, claims arising out of the CRM business and environmental liabilities that may not be covered by indemnity or insurance, as well as the FERC, U.S. Attorney and other similar investigations primarily surrounding Project
Alpha and our past trading practices;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the effects of Dynegys ongoing efforts to improve our internal control structure of the consolidated entity, particularly with respect to those matters discussed under Item
4Controls and Procedures, and to achieve compliance with Section 404 of Sarbanes-Oxley within the prescribed period;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | other North American regulatory or legislative developments that affect the demand and pricing for energy generally, that increase the environmental compliance cost for our
facilities or that impose liabilities on the owners of such facilities; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | general political conditions and developments in the United States and in foreign countries whose affairs affect our asset-based businesses including any extended period of war or
conflict.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition, there may be other
factors that could cause our actual results to be materially different from the results referenced in the forward-looking statements, some of which are included elsewhere in this Form 10-Q.



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Many of these factors will be important in determining our actual future results. Consequently, no forward-looking statement can be guaranteed. Our actual
future results may vary materially from those expressed or implied in any forward-looking statements.



All forward-looking statements contained in this Form 10-Q are qualified in their entirety by this cautionary statement. Forward-looking statements speak
only as of the date they are made, and we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this Form 10-Q, except as otherwise required by applicable law.



RECENT ACCOUNTING PRONOUNCEMENTS



See Note 1 to the unaudited condensed consolidated financial statements for
a discussion of recently issued accounting pronouncements affecting us. Specifically, we adopted certain provisions of FIN No. 46R on January 1, 2004.



CRITICAL ACCOUNTING POLICIES



Please read Critical Accounting Policies beginning on page 53 of our Form 10-K for a complete description of our critical accounting policies,
with respect to which there have been no material changes since the filing of our Form 10-K.



Item 3Quantitative and Qualitative Disclosures About Market Risk



Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 60 of our Form 10-K for a discussion of our exposure to
commodity price variability and other markets risks, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of September 30, 2004.



Value at Risk (VaR). The following table sets forth
the aggregate daily VaR of the mark-to-market portion of Dynegys risk-management portfolio primarily associated with the GEN and CRM segments:



Daily and Average VaR for Risk-Management Portfolio



|                                                             |  |                   |   |                  |   |  
|------------------------------------------------------------ |  | ----------------- | - | ---------------- | - | -
|                                                             |  | September 30,2004 |   | December 31,2003
|                                                             |  | (in millions)    
|One Day VaR95% Confidence Level                             |  | $                 | 6 |                  | $ | 4
|One Day VaR99% Confidence Level                             |  | $                 | 8 |                  | $ | 6
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $                 | 4 |                  | $ | 6



Credit
Risk. The following table represents our credit exposure at September 30, 2004 associated with the mark-to-market portion of our risk-management portfolio, on a net basis:



Credit Exposure Summary



|                                |  |                         |     |                             |   |       |  |   |    
|------------------------------- |  | ----------------------- | --- | --------------------------- | - | ----- |  | - | ---
|                                |  | Investment GradeQuality |     | Non-InvestmentGrade Quality |   | Total
|                                |  | (in millions)          
|Type of Business:               |  |                         |     |                             |   |       |  |   |    
|Financial Institutions          |  | $                       | 169 |                             | $ |      |  | $ | 169
|Commercial/Industrial/End Users |  |                         | 69  |                             |   | 41    |  |   | 110
|Utility and Power Generators    |  |                         | 22  |                             |   |      |  |   | 22 
|Oil and Gas Producers           |  |                         | 8   |                             |   | 6     |  |   | 14 
|                                |  |                         |     |                             |   |       |  |   |    
|Total                           |  | $                       | 268 |                             | $ | 47    |  | $ | 315
|                                |  |                         |     |                             |   |       |  |   |    



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Of the $47 million in credit exposure to non-investment grade counterparties, approximately 91% ($43
million) is collateralized or subject to other credit exposure protection.



Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of September 30, 2004, our fixed rate debt instruments as a percentage of total debt
instruments was approximately 68%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of September 30, 2004, it is estimated that a one percentage point interest rate movement in the average market
interest rates (either higher or lower) over the 12 months ended September 30, 2005 would either decrease or increase income before taxes by approximately $15 million. Hedging instruments that impact such interest rate exposure are included in the
sensitivity analysis. Over time, we may seek to further reduce the percentage of fixed rate financial obligations in our debt portfolio through the use of additional swaps or other financial instruments.



Derivative Contracts. The absolute notional financial contract
amounts associated with our commodity risk-management and interest rate contracts were as follows at September 30, 2004 and December 31, 2003, respectively:



Absolute Notional Contract Amounts



|                                                                     |  |                   |        |                  |   |      
|-------------------------------------------------------------------- |  | ----------------- | ------ | ---------------- | - | -----
|                                                                     |  | September 30,2004 |        | December 31,2003
|Natural Gas (Trillion Cubic Feet)                                    |  |                   | 1.375  |                  |   | 2.364
|Electricity (Million Megawatt Hours)                                 |  |                   | 12.316 |                  |   | 8.713
|Natural Gas Liquids (Million Barrels)                                |  |                   | 0.030  |                  |   |     
|Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)   |  | $                 | 525    |                  | $ | 25   
|Fixed Interest Rate Received on Swaps (Percent)                      |  |                   | 4.331  |                  |   | 5.706
|Cash Flow Hedge Interest Rate Swaps (In Millions of U.S. Dollars)    |  | $                 |       |                  | $ | 405  
|Fixed Interest Rate Paid on Swaps (Percent)                          |  |                   |       |                  |   | 3.448
|Interest Rate Risk-Management Contract (In Millions of U.S. Dollars) |  | $                 | 25     |                  | $ | 306  
|Fixed Interest Rate Received (Percent)                               |  |                   | 6.00   |                  |   | 5.57 



Item 4Controls and Procedures



Evaluation of Disclosure Controls and Procedures. Effective as of the end of the third quarter 2004, an evaluation was carried out under the supervision and with the participation of our management,
including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation
included consideration of the various processes carried out under the direction of Dynegys disclosure committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported
within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the third quarter 2004 relating to our participation in Dynegys efforts to achieve compliance with Section 404 of the
Sarbanes-Oxley Act of 2002, which is further described below. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective at the reasonable assurance level and designed to ensure that the information
required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be
available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.



Changes in Internal Controls. There were no changes in our internal controls over financial reporting (as defined in Rules 13a-15(f) and
15d-15(f) under the Exchange Act) identified in connection with the evaluation of our internal controls performed during the third quarter 2004, other than those noted below, that have materially affected, or are reasonably likely to materially
affect, our internal controls over financial reporting.



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We are a wholly owned subsidiary of Dynegy and the primary holding company for Dynegys GEN and NGL
businesses. We are not subject to the disclosure requirements promulgated under Section 404 of the Sarbanes-Oxley Act of 2002 until we file our Annual Report on Form 10-K for the year ended December 31, 2005. However, in seeking to achieve
compliance with Section 404 within the prescribed period, Dynegy Inc.s management has formed an internal control steering committee, engaged outside consultants and adopted a detailed project work plan to assess the adequacy of its internal
controls over financial reporting, remediate any control weaknesses that may be identified, validate through testing that controls are functioning as documented and implement a continuous reporting and improvement process for internal controls over
financial reporting. Because we comprise a significant part of Dynegy as a consolidated enterprise, our internal controls over financial reporting are being reviewed in connection with this effort.



In connection with this initiative, which began in 2003, a number of items
have been identified that will likely result in changes to the consolidated enterprises internal controls over financial reporting, including matters relating to system access and system implementation controls, segregation of duties and
documentation of controls and procedures and their effective operation and monitoring.



Weaknesses have also been identified in the consolidated enterprises tax accounting and tax reconciliation controls and processes that make this an area of particular focus. In the third quarter 2004, we
determined that adjustments related to our deferred income tax accounts in periods prior to 2004 were required. We identified this deficiency and promptly brought it to the attention of Dynegys audit and compliance committee and independent
auditors. We believe we have addressed this deficiency, by taking the following steps to improve our internal controls around our tax accounting and tax reconciliation controls and processes:



| |  | Increased the levels of review in the preparation of the quarterly tax provision;
| | - | ---------------------------------------------------------------------------------



| |  | Formalized processes, procedures and documentation standards; and
| | - | -----------------------------------------------------------------



| |  | Restructured the consolidated enterprises Tax Department to ensure appropriate segregation of duties regarding preparation and review of the quarterly tax provision.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



We expect that, in an effort to improve the
consolidated enterprises existing controls and to seek to provide management and the independent auditors the ability to make favorable evaluations and attestations under Section 404 of Sarbanes-Oxley, additional changes will be made in the
consolidated enterprises internal controls over financial reporting with respect to these and potentially other matters that may arise during the period prior to December 31, 2004. These changes may include, due to our involvement in and the
impact of our company on this initiative, changes to our internal controls over financial reporting.



Additionally, the Public Company Accounting Oversight Board recently adopted very stringent standards governing managements required evaluation of
its internal controls over financial reporting and the independent auditors review of those controls and managements evaluation thereof. These standards will likely result in a significant number of companies, which may include us,
identifying significant deficiencies and/or material weaknesses in their internal controls. Indeed, the items referenced in the preceding paragraphs could preclude our independent auditors from delivering an unqualified opinion on internal controls
under Section 404 of Sarbanes-Oxley.



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##### Table of Contents

DYNEGY HOLDINGS INC.



PART II.
OTHER INFORMATION



Item 1Legal Proceedings



See Note 8 to the accompanying unaudited condensed consolidated financial statements for discussion of the material legal proceedings to which we are a party.



Item 6Exhibits



The following documents are included as exhibits to this Form 10-Q:



|     |  |                                                                                                                                                                                                                                                                             
|---- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1 |  | Power Purchase Agreement dated September 30, 2004 between Illinois Power Company and Dynegy Power Marketing, Inc. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form
10-Q for the Quarter Ended September 30, 2004 of Dynegy Inc., File No. 1-15639)

---



Due to our inability to complete our deferred income tax account review, this report is not accompanied by the certifications required by Sections 302 and
906 of the Sarbanes-Oxley Act of 2002 and Rule 13a-14 and 15d-14 of the Securities Exchange Act of 1934, as amended. These certifications will be filed by and/or will accompany an amendment to this report as soon as practicable following the date
hereof. Please read the Explanatory Note following the table of contents for further discussion.



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DYNEGY HOLDINGS INC.



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.



|                         |  |                      |  |                                                                                                                              
|------------------------ |  | -------------------- |  | -----------------------------------------------------------------------------------------------------------------------------
|                         |  | DYNEGY HOLDINGS INC.
|                         |  |                     
|Date:  November 22, 2004 |  | By:                  |  | /s/    NICK J.
CARUSO                                                                                                        
|                         |  |                      |  | Nick J. Caruso Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal
Financial Officer)



77