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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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



For the quarterly period ended September 30, 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: 1-15659



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DYNEGY INC.

(Exact name of registrant as specified in its charter)



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Illinois                                                       |  | 74-2928353                          
|(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  x    No ̈



Number of shares outstanding of each of the issuers classes of common
stock, as of the latest practicable date: Class A common stock, no par value per share, 283,135,636 shares outstanding as of November 8, 2004; Class B common stock, no par value per share, 96,891,014 shares outstanding as of November 8, 2004.



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##### Table of Contents

DYNEGY 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 Income (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 |  | 46  
|                                                                                              | 
|Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                            |  | 78  
|                                                                                              | 
|Item 4. CONTROLS AND PROCEDURES                                                               |  | 79  
|                                                                                              | 
|PART II. OTHER INFORMATION                                                                    |  |     
|                                                                                              | 
|Item 1. LEGAL PROCEEDINGS                                                                     |  | 81  
|                                                                                              | 
|Item 6. EXHIBITS                                                                              |  | 81  



Explanatory Note



On September 22, 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 previously disclosed goodwill impairment charge
associated with the sale of Illinois Power and our deferred income tax accounts. The financial information in this report has been revised to reflect the effects of these items. These items are discussed in more detail in the Introductory Note to
the accompanying unaudited condensed consolidated financial statements.



We expect to file amendments to our 2003 Form 10-K and first and second quarter 2004 Form 10-Qs as soon as practicable after the date of this report.



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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                                                                                                                       
|CUSA      |  | Chevron U.S.A. Inc., a wholly owned subsidiary of ChevronTexaco                                                                                                     
|$/Bbl     |  | Dollars per barrel                                                                                                                                                  
|$/Gal     |  | Dollars per gallon                                                                                                                                                  
|DGC       |  | Dynegy Global Communications                                                                                                                                        
|DHI       |  | Dynegy Holdings Inc., our primary financing subsidiary                                                                                                              
|DMG       |  | Dynegy Midwest Generation, Inc.                                                                                                                                     
|DMS       |  | Dynegy Midstream Services                                                                                                                                           
|DPM       |  | Dynegy Power Marketing Inc.                                                                                                                                         
|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 22, 2004                                                                                                          
|Form 10-K |  | Our Annual Report on Form 10-K for the year ended December 31, 2003, filed on February 27, 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                                                                                                                                        
|KWH       |  | Kilowatt hours                                                                                                                                                      
|kW-yr     |  | Kilowatts per year                                                                                                                                                  
|LIBOR     |  | The London Interbank Offered Rate                                                                                                                                   
|LNG       |  | Liquefied natural gas                                                                                                                                               
|MBbls/d   |  | Thousands of barrels per day                                                                                                                                        
|MISO      |  | Midwest Independent Transmission System Operator, Inc.                                                                                                              
|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                                                                                                                                     
|PGA       |  | Purchase Gas Adjustment                                                                                                                                             
|PPO       |  | Power Purchase Option                                                                                                                                               
|PRB       |  | Powder River Basin                                                                                                                                                  
|PSD       |  | Prevention of Significant Deterioration                                                                                                                             
|REG       |  | Our regulated energy delivery business segment                                                                                                                      
|RTO       |  | Regional Transmission Organization                                                                                                                                  
|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 INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)



|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------- | ------ | - | ---------------- | - | ------ | -
|                                                                                                                                                                                                                                   |  | September 30,2004 |        |   | December 31,2003 |  
|                                                                                                                                                                                                                                   |  |                   |        |   | (Restated)       |  
|ASSETS                                                                                                                                                                                                                             |  |                   |        |   |                  |   |        |  
|Current Assets                                                                                                                                                                                                                     |  |                   |        |   |                  |   |        |  
|Cash and cash equivalents                                                                                                                                                                                                          |  | $                 | 926    |   |                  | $ | 477    |  
|Restricted cash                                                                                                                                                                                                                    |  |                   |       |   |                  |   | 19     |  
|Accounts receivable, net of allowance for doubtful accounts of $161 and $184, respectively                                                                                                                                         |  |                   | 698    |   |                  |   | 1,010  |  
|Accounts receivable, affiliates                                                                                                                                                                                                    |  |                   | 19     |   |                  |   | 25     |  
|Inventory                                                                                                                                                                                                                          |  |                   | 260    |   |                  |   | 279    |  
|Assets from risk-management activities                                                                                                                                                                                             |  |                   | 797    |   |                  |   | 818    |  
|Prepayments and other current assets                                                                                                                                                                                               |  |                   | 463    |   |                  |   | 402    |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Current Assets                                                                                                                                                                                                               |  |                   | 3,163  |   |                  |   | 3,030  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment                                                                                                                                                                                                      |  |                   | 7,774  |   |                  |   | 9,867  |  
|Accumulated depreciation                                                                                                                                                                                                           |  |                   | (1,626 | ) |                  |   | (1,664 | )
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                                                                                                                                                                 |  |                   | 6,148  |   |                  |   | 8,203  |  
|Other Assets                                                                                                                                                                                                                       |  |                   |        |   |                  |   |        |  
|Unconsolidated investments                                                                                                                                                                                                         |  |                   | 459    |   |                  |   | 612    |  
|Assets from risk-management activities                                                                                                                                                                                             |  |                   | 634    |   |                  |   | 629    |  
|Goodwill                                                                                                                                                                                                                           |  |                   | 15     |   |                  |   | 15     |  
|Other long-term assets                                                                                                                                                                                                             |  |                   | 312    |   |                  |   | 472    |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Assets                                                                                                                                                                                                                       |  | $                 | 10,731 |   |                  | $ | 12,961 |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                                                                               |  |                   |        |   |                  |   |        |  
|Current Liabilities                                                                                                                                                                                                                |  |                   |        |   |                  |   |        |  
|Accounts payable                                                                                                                                                                                                                   |  | $                 | 553    |   |                  | $ | 664    |  
|Accounts payable, affiliates                                                                                                                                                                                                       |  |                   | 84     |   |                  |   | 74     |  
|Accrued liabilities and other current liabilities                                                                                                                                                                                  |  |                   | 510    |   |                  |   | 669    |  
|Liabilities from risk-management activities                                                                                                                                                                                        |  |                   | 879    |   |                  |   | 838    |  
|Notes payable and current portion of long-term debt                                                                                                                                                                                |  |                   | 24     |   |                  |   | 245    |  
|Current portion of long-term debt to affiliates                                                                                                                                                                                    |  |                   | 125    |   |                  |   | 86     |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Current Liabilities                                                                                                                                                                                                          |  |                   | 2,175  |   |                  |   | 2,576  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Long-term debt                                                                                                                                                                                                                     |  |                   | 4,151  |   |                  |   | 5,124  |  
|Long-term debt to affiliates                                                                                                                                                                                                       |  |                   | 200    |   |                  |   | 769    |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Long-Term Debt                                                                                                                                                                                                                     |  |                   | 4,351  |   |                  |   | 5,893  |  
|Other Liabilities                                                                                                                                                                                                                  |  |                   |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                                                                                                                                                        |  |                   | 718    |   |                  |   | 746    |  
|Deferred income taxes                                                                                                                                                                                                              |  |                   | 533    |   |                  |   | 524    |  
|Other long-term liabilities                                                                                                                                                                                                        |  |                   | 355    |   |                  |   | 750    |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Liabilities                                                                                                                                                                                                                  |  |                   | 8,132  |   |                  |   | 10,489 |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Minority Interest                                                                                                                                                                                                                  |  |                   | 108    |   |                  |   | 121    |  
|Commitments and Contingencies (Note 9)                                                                                                                                                                                             |  |                   |        |   |                  |   |        |  
|Redeemable Preferred Securities, redemption value of $400 at September 30, 2004 and $411 at December 31, 2003                                                                                                                      |  |                   | 400    |   |                  |   | 411    |  
|Stockholders Equity                                                                                                                                                                                                               |  |                   |        |   |                  |   |        |  
|Class A Common Stock, no par value, 900,000,000 shares authorized at September 30, 2004 and December 31, 2003; 284,699,441 and 280,350,169
shares issued and outstanding at September 30, 2004 and December 31, 2003, respectively |  |                   | 2,858  |   |                  |   | 2,848  |  
|Class B Common Stock, no par value, 360,000,000 shares authorized at September 30, 2004 and December 31, 2003; 96,891,014 shares issued and
outstanding at September 30, 2004 and December 31, 2003                                |  |                   | 1,006  |   |                  |   | 1,006  |  
|Additional paid-in capital                                                                                                                                                                                                         |  |                   | 47     |   |                  |   | 41     |  
|Subscriptions receivable                                                                                                                                                                                                           |  |                   | (8     | ) |                  |   | (8     | )
|Accumulated other comprehensive loss, net of tax                                                                                                                                                                                   |  |                   | (24    | ) |                  |   | (20    | )
|Accumulated deficit                                                                                                                                                                                                                |  |                   | (1,720 | ) |                  |   | (1,859 | )
|Treasury stock, at cost, 1,679,183 shares at September 30, 2004 and December 31, 2003                                                                                                                                              |  |                   | (68    | ) |                  |   | (68    | )
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Stockholders Equity                                                                                                                                                                                                         |  |                   | 2,091  |   |                  |   | 1,940  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                                                                                                                                                         |  | $                 | 10,731 |   |                  | $ | 12,961 |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  



See the notes to
condensed consolidated financial statements.



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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions, except per share data)



|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|--------------------------------------------------------------------------- |  | ------------------------------ | ------ | - | ----------------------------- | - | ------ | ---- |  | - | ------ | - |  | - | ------ | -
|                                                                            |  | Three MonthsEndedSeptember 30, |        |   | Nine MonthsEndedSeptember 30, |  
|                                                                            |  | 2004                           |        |   | 2003                          |   |        | 2004 |  |   | 2003   |  
|Revenues                                                                    |  | $                              | 1,650  |   |                               | $ | 1,385  |      |  | $ | 4,747  |   |  | $ | 4,331  |  
|Cost of sales, exclusive of depreciation shown separately below             |  |                                | (1,327 | ) |                               |   | (1,095 | )    |  |   | (3,803 | ) |  |   | (3,822 | )
|Depreciation and amortization expense                                       |  |                                | (79    | ) |                               |   | (109   | )    |  |   | (249   | ) |  |   | (340   | )
|Impairment and other charges                                                |  |                                | (2     | ) |                               |   | (1     | )    |  |   | (83    | ) |  |   | 6      |  
|Gain (loss) on sale of assets, net                                          |  |                                | (24    | ) |                               |   |       |      |  |   | 14     |   |  |   | 15     |  
|General and administrative expenses                                         |  |                                | (79    | ) |                               |   | (79    | )    |  |   | (247   | ) |  |   | (276   | )
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Operating income (loss)                                                     |  |                                | 139    |   |                               |   | 101    |      |  |   | 379    |   |  |   | (86    | )
|Earnings from unconsolidated investments                                    |  |                                | 102    |   |                               |   | 51     |      |  |   | 194    |   |  |   | 142    |  
|Interest expense                                                            |  |                                | (125   | ) |                               |   | (145   | )    |  |   | (402   | ) |  |   | (364   | )
|Other income and expense, net                                               |  |                                | 3      |   |                               |   | 2      |      |  |   | 10     |   |  |   | 13     |  
|Minority interest income (expense)                                          |  |                                | (9     | ) |                               |   | (2     | )    |  |   | (19    | ) |  |   | 7      |  
|Accumulated distributions associated with trust preferred securities        |  |                                |       |   |                               |   |       |      |  |   |       |   |  |   | (8     | )
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Income (loss) from continuing operations before income taxes                |  |                                | 110    |   |                               |   | 7      |      |  |   | 162    |   |  |   | (296   | )
|Income tax benefit (expense) (Note 12)                                      |  |                                | (30    | ) |                               |   | (3     | )    |  |   | 1      |   |  |   | 109    |  
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Income (loss) from continuing operations                                    |  |                                | 80     |   |                               |   | 4      |      |  |   | 163    |   |  |   | (187   | )
|Income (loss) from discontinued operations, net of taxes (Notes 2 and 12)   |  |                                | (2     | ) |                               |   | 1      |      |  |   | (7     | ) |  |   | (6     | )
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Income (loss) before cumulative effect of change in accounting principles   |  |                                | 78     |   |                               |   | 5      |      |  |   | 156    |   |  |   | (193   | )
|Cumulative effect of change in accounting principles, net of taxes (Note 1) |  |                                |       |   |                               |   |       |      |  |   |       |   |  |   | 55     |  
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Net income (loss)                                                           |  |                                | 78     |   |                               |   | 5      |      |  |   | 156    |   |  |   | (138   | )
|Less: preferred stock dividends (gain)                                      |  |                                | 6      |   |                               |   | (1,183 | )    |  |   | 17     |   |  |   | (1,018 | )
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Net income applicable to common stockholders                                |  | $                              | 72     |   |                               | $ | 1,188  |      |  | $ | 139    |   |  | $ | 880    |  
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Earnings Per Share (Note 8):                                                |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Basic earnings per share:                                                   |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Income from continuing operations                                           |  | $                              | 0.20   |   |                               | $ | 3.17   |      |  | $ | 0.39   |   |  | $ | 2.23   |  
|Income (loss) from discontinued operations                                  |  |                                | (0.01  | ) |                               |   | 0.00   |      |  |   | (0.02  | ) |  |   | (0.02  | )
|Cumulative effect of change in accounting principles                        |  |                                |       |   |                               |   |       |      |  |   |       |   |  |   | 0.15   |  
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Basic earnings per share                                                    |  | $                              | 0.19   |   |                               | $ | 3.17   |      |  | $ | 0.37   |   |  | $ | 2.36   |  
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Diluted earnings per share:                                                 |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Income from continuing operations                                           |  | $                              | 0.16   |   |                               | $ | 2.65   |      |  | $ | 0.33   |   |  | $ | 2.10   |  
|Income (loss) from discontinued operations                                  |  |                                | 0.00   |   |                               |   | 0.00   |      |  |   | (0.01  | ) |  |   | (0.02  | )
|Cumulative effect of change in accounting principles                        |  |                                |       |   |                               |   |       |      |  |   |       |   |  |   | 0.13   |  
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Diluted earnings per share                                                  |  | $                              | 0.16   |   |                               | $ | 2.65   |      |  | $ | 0.32   |   |  | $ | 2.21   |  
|                                                                            |  |                                |        |   |                               |   |        |      |  |   |        |   |  |   |        |  
|Basic shares outstanding                                                    |  |                                | 379    |   |                               |   | 375    |      |  |   | 378    |   |  |   | 373    |  
|Diluted shares outstanding                                                  |  |                                | 504    |   |                               |   | 464    |      |  |   | 503    |   |  |   | 397    |  



See the notes to
condensed consolidated financial statements.



5



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##### Table of Contents

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



|                                                                                        |  |                               |      |   |      |   |        |  
|--------------------------------------------------------------------------------------- |  | ----------------------------- | ---- | - | ---- | - | ------ | -
|                                                                                        |  | Nine MonthsEndedSeptember 30, |     
|                                                                                        |  | 2004                          |      |   | 2003 |  
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                   |  |                               |      |   |      |   |        |  
|Net income (loss)                                                                       |  | $                             | 156  |   |      | $ | (138   | )
|Adjustments to reconcile net income (loss) to net cash flows from operating activities: |  |                               |      |   |      |   |        |  
|Depreciation and amortization                                                           |  |                               | 279  |   |      |   | 399    |  
|Impairment and other charges                                                            |  |                               | 83   |   |      |   |       |  
|Earnings from unconsolidated investments, net of cash distributions                     |  |                               | (82  | ) |      |   | (26    | )
|Risk-management activities                                                              |  |                               | (24  | ) |      |   | 378    |  
|Gain on sale of assets, net                                                             |  |                               | (14  | ) |      |   | (45    | )
|Deferred income taxes                                                                   |  |                               | 27   |   |      |   | (119   | )
|Cumulative effect of change in accounting principles (Note 1)                           |  |                               |     |   |      |   | (55    | )
|Liability associated with gas transportation contracts (Note 2)                         |  |                               | (148 | ) |      |   |       |  
|Other                                                                                   |  |                               | 8    |   |      |   | 33     |  
|Changes in working capital:                                                             |  |                               |      |   |      |   |        |  
|Accounts receivable                                                                     |  |                               | 150  |   |      |   | 1,704  |  
|Inventory                                                                               |  |                               | (70  | ) |      |   | 78     |  
|Prepayments and other assets                                                            |  |                               | (125 | ) |      |   | 817    |  
|Accounts payable and accrued liabilities                                                |  |                               | (123 | ) |      |   | (2,043 | )
|Changes in non-current assets                                                           |  |                               | (17  | ) |      |   | (22    | )
|Changes in non-current liabilities                                                      |  |                               | 20   |   |      |   | (27    | )
|                                                                                        |  |                               |      |   |      |   |        |  
|Net cash provided by operating activities                                               |  |                               | 120  |   |      |   | 934    |  
|                                                                                        |  |                               |      |   |      |   |        |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                   |  |                               |      |   |      |   |        |  
|Capital expenditures                                                                    |  |                               | (221 | ) |      |   | (259   | )
|Proceeds from asset sales, net                                                          |  |                               | 527  |   |      |   | 57     |  
|                                                                                        |  |                               |      |   |      |   |        |  
|Net cash provided by (used in) investing activities                                     |  |                               | 306  |   |      |   | (202   | )
|                                                                                        |  |                               |      |   |      |   |        |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                   |  |                               |      |   |      |   |        |  
|Net proceeds from long-term borrowings                                                  |  |                               | 588  |   |      |   | 1,909  |  
|Repayments of long-term borrowings                                                      |  |                               | (520 | ) |      |   | (2,352 | )
|Net cash flow from commercial paper and revolving lines of credit                       |  |                               |     |   |      |   | (128   | )
|Payment to ChevronTexaco for Series B preferred stock restructuring                     |  |                               |     |   |      |   | (225   | )
|Proceeds from issuance of capital stock                                                 |  |                               | 5    |   |      |   | 6      |  
|Dividends and other distributions, net                                                  |  |                               | (22  | ) |      |   |       |  
|Other financing, net                                                                    |  |                               | (27  | ) |      |   | (18    | )
|                                                                                        |  |                               |      |   |      |   |        |  
|Net cash provided by (used in) financing activities                                     |  |                               | 24   |   |      |   | (808   | )
|                                                                                        |  |                               |      |   |      |   |        |  
|Effect of exchange rate changes on cash                                                 |  |                               | (1   | ) |      |   | 7      |  
|Net increase (decrease) in cash and cash equivalents                                    |  |                               | 449  |   |      |   | (69    | )
|Cash and cash equivalents, beginning of period                                          |  |                               | 477  |   |      |   | 757    |  
|                                                                                        |  |                               |      |   |      |   |        |  
|Cash and cash equivalents, end of period                                                |  | $                             | 926  |   |      | $ | 688    |  
|                                                                                        |  |                               |      |   |      |   |        |  



See the notes to
condensed consolidated financial statements.



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##### Table of Contents

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)



|                                                                                                          |  |                                |     |   |      |   |      |  
|--------------------------------------------------------------------------------------------------------- |  | ------------------------------ | --- | - | ---- | - | ---- | -
|                                                                                                          |  | Three MonthsEndedSeptember 30, |    
|                                                                                                          |  | 2004                           |     |   | 2003 |  
|Net income                                                                                                |  | $                              | 78  |   |      | $ | 5    |  
|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   |   |      |   | (9   | )
|Minimum pension liability (net of tax expense of $23 and zero, respectively)                              |  |                                | 39  |   |      |   |     |  
|                                                                                                          |  |                                |     |   |      |   |      |  
|Other comprehensive income (loss), net of tax                                                             |  |                                | 42  |   |      |   | (10  | )
|                                                                                                          |  |                                |     |   |      |   |      |  
|Comprehensive income (loss)                                                                               |  | $                              | 120 |   |      | $ | (5   | )
|                                                                                                          |  |                                |     |   |      |   |      |  
|                                                                                                          | 
|                                                                                                          |  | Nine MonthsEndedSeptember 30,  |    
|                                                                                                          |  | 2004                           |     |   | 2003 |  
|Net income (loss)                                                                                         |  | $                              | 156 |   |      | $ | (138 | )
|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 | ) |      |   | 12   |  
|Minimum pension liability (net of tax expense of $24 and zero, respectively)                              |  |                                | 41  |   |      |   |     |  
|                                                                                                          |  |                                |     |   |      |   |      |  
|Other comprehensive income (loss), net of tax                                                             |  |                                | (4  | ) |      |   | 35   |  
|                                                                                                          |  |                                |     |   |      |   |      |  
|Comprehensive income (loss)                                                                               |  | $                              | 152 |   |      | $ | (103 | )
|                                                                                                          |  |                                |     |   |      |   |      |  



See the notes to
condensed consolidated financial statements.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods
Ended September 30, 2004 and 2003



Introductory Note



On September 22, 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 previously disclosed goodwill impairment charge associated with the sale of Illinois Power and our
deferred income tax accounts. The financial information in this report has been revised to reflect the effects of these items. We expect to file amendments to our 2003 Form 10-K and first and second quarter 2004 Form 10-Qs as soon as practicable
after the date of this report.



Impairment of Illinois
Power. As more fully discussed in Note 10Goodwill beginning on page F-33 of our Form 10-K, during 2003, the value of goodwill associated with Illinois Power was determined to be impaired, resulting in our recognizing a charge of $242
million. During 2004, while preparing to record the Illinois Power sale, we identified a deferred tax asset that was excluded from our 2003 impairment analysis. Our exclusion of this asset understated the net book value of the assets and, as a
result, understated the impairment that had been recorded in 2003. The impact of the error resulted in an understatement of goodwill impairment of $139 million and an after-tax understatement of asset impairments of $120 million. As such, we were
required to recognize an additional after-tax charge of $259 million ($0.61 per diluted share) in the fourth quarter 2003. In addition, we were required to recognize additional after-tax charges of $4 million ($0.01 per diluted share) and $2 million
($0.00 per diluted share) in the three months ended March 31 and June 30, 2004, respectively, due to changes in the value of the deferred tax asset. This correction had no impact on previously reported cash flows from operating activities, investing
activities or financing activities. The financial information in this report has been revised to reflect the impact of this correction.



The table below summarizes the effects of the correction on our previously reported net income:



|                                                    |  |                    |     |   |                 |   |     |              |  |   |     |  
|--------------------------------------------------- |  | ------------------ | --- | - | --------------- | - | --- | ------------ |  | - | --- | -
|                                                    |  | Three Months Ended |     |   | Six MonthsEnded |  
|                                                    |  | March 31,2004      |     |   | June 30, 2004   |   |     | June 30,2004 | 
|                                                    |  | (in millions)      |    
|Impairment and other charges as previously reported |  | $                  | (10 | ) |                 | $ | (44 | )            |  | $ | (54 | )
|Adjustment                                          |  |                    | (6  | ) |                 |   | (20 | )            |  |   | (26 | )
|                                                    |  |                    |     |   |                 |   |     |              |  |   |     |  
|Impairment and other charges as restated            |  | $                  | (16 | ) |                 | $ | (64 | )            |  | $ | (80 | )
|                                                    |  |                    |     |   |                 |   |     |              |  |   |     |  
|Income tax benefit (expense) as previously reported |  | $                  | 27  |   |                 | $ | (17 | )            |  | $ | 10  |  
|Adjustment                                          |  |                    | 2   |   |                 |   | 18  |              |  |   | 20  |  
|                                                    |  |                    |     |   |                 |   |     |              |  |   |     |  
|Income tax benefit (expense) as restated            |  | $                  | 29  |   |                 | $ | 1   |              |  | $ | 30  |  
|                                                    |  |                    |     |   |                 |   |     |              |  |   |     |  
|Net income as previously reported                   |  | $                  | 74  |   |                 | $ | 10  |              |  | $ | 84  |  
|Adjustment                                          |  |                    | (4  | ) |                 |   | (2  | )            |  |   | (6  | )
|                                                    |  |                    |     |   |                 |   |     |              |  |   |     |  
|Net income as restated                              |  | $                  | 70  |   |                 | $ | 8   |              |  | $ | 78  |  
|                                                    |  |                    |     |   |                 |   |     |              |  |   |     |  



Deferred Income
Tax Accounts. As discussed in the Form 8-K, and as previously disclosed in our second quarter 2004 Form 10-Q, we are currently engaged in an evaluation of our tax accounting and reconciliation controls and processes, including a tax basis
balance sheet review. Through this initiative, we have determined that adjustments related to our deferred income tax accounts in periods prior to 2004 are required. The cumulative impact of these adjustments is a reduction to our deferred tax
liability reflected on our December 31, 2003 balance sheet of $154 million. We have not fully completed the allocation of the matters giving rise to the reduction to the appropriate periods, however, the unaudited condensed consolidated
financial statements



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



contained herein reflect the necessary adjustments to the nine months ended September 30, 2004 and 2003. We are working to complete this allocation as
expeditiously as possible.



Although we have not fully
completed the allocation of the matters, we have determined that one of the adjustments to our deferred income tax accounts arose through the purchase accounting entries recorded at the time of our acquisition of Illinois Power. In order to properly
reflect the impact of the adjustment, our previously disclosed goodwill impairment recorded in the fourth quarter 2003 will be reduced by approximately $70 million. This reduction offsets the $139 million increase discussed in Impairment
of Illinois Power above.



This restatement has no effect
on our previously reported net income for the nine months ended September 30, 2004 or 2003.



Balance Sheet Summary. The table below summarizes the effects of both items discussed above on our December 31, 2003 balance sheet:



|                             |  |                  |        |  
|---------------------------- |  | ---------------- | ------ | -
|                             |  | December 31,2003 |       
|                             |  | (in millions)    |       
|Total Assets                 |  |                  |        |  
|As previously reported       |  | $                | 13,293 |  
|Impairment of Illinois Power |  |                  | (332   | )
|                             |  |                  |        |  
|As restated                  |  | $                | 12,961 |  
|                             |  |                  |        |  
|Total Liabilities            |  |                  |        |  
|As previously reported       |  | $                | 10,716 |  
|Impairment of Illinois Power |  |                  | (73    | )
|Deferred income tax accounts |  |                  | (154   | )
|                             |  |                  |        |  
|As restated                  |  | $                | 10,489 |  
|                             |  |                  |        |  
|Stockholders Equity         |  |                  |        |  
|As previously reported       |  | $                | 2,045  |  
|Impairment of Illinois Power |  |                  | (259   | )
|Deferred income tax accounts |  |                  | 154    |  
|                             |  |                  |        |  
|As restated                  |  | $                | 1,940  |  
|                             |  |                  |        |  



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. 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. 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



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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, (5) determining amounts to accrue for contingencies and (6) estimating various factors
used to value our pension assets. 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.



Restricted Cash.Restricted cash represents cash that is unavailable for general purpose cash needs. Restricted cash at December 31,
2003 reflected amounts reserved for use in retiring Illinois Powers Transitional Funding Trust Notes.



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 income (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 (losses) 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



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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 ofYears
|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      



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.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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, NGL and REG 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. Our transmission, distribution and retail electric and natural gas services revenues are recognized when services are provided to customers. Shipping and handling costs are included in revenue when billed to customers with the
sale of products.



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.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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. We file a consolidated U.S. federal income tax
return and, for financial reporting purposes, account 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.



Earnings Per Share. Basic earnings per share represents the amount of earnings for the period available to each share of common stock
outstanding during the period. Diluted earnings per share represents the amount of earnings for the period available to each share of common stock outstanding during the period plus each share that would have been outstanding assuming the issuance
of common shares for all potentially dilutive common shares outstanding during the period.



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 loss in stockholders 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 $1 million for each of the three months ended September 30, 2004 and 2003, and gains of $2 million and $10 million for the nine months ended
September 30, 2004 and 2003, respectively.



Regulatory
Assets and Liabilities. SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, allows companies whose service obligations and prices are regulated to maintain balance sheet assets representing costs they expect
to recover from customers through inclusion in future rates. Illinois Power, our former wholly owned utility subsidiary, recorded regulatory assets in accordance with SFAS No. 71. Regulatory assets as of December 31, 2003 totaled approximately $207
million and were included in other long-term assets on our unaudited condensed consolidated balance sheet. The investment tax credit related to regulatory assets is amortized over the lives of the respective assets, which gave rise to the investment
tax credit.



Rate-regulated companies subject to SFAS No. 71
are permitted to accrue the estimated cost of removal and salvage associated with certain of their assets through depreciation expense. The amounts accrued in depreciation are not associated with AROs recorded in accordance with SFAS No. 143,
Accounting for Asset Retirement Obligations. At December 31, 2003, approximately $72 million of cost of removal, net of salvage, was included in regulatory liabilities.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------



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.



14



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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, power transmission assets, 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, $10 million for our NGL segment and $1 million for our REG 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 and equipment 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 our REG segment 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 stock-based employee compensation. 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 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 granted in-the-money options
in the past and have recognized compensation expense over the applicable vesting periods. No in-the-money stock options have been granted since 1999.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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) and basic and diluted earnings per share amounts would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2004 and 2003, respectively.



|                                                                                                                                            |  |                                      |      |   |                               |   |      |      |  |   |      |   |  |   |      |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------ | ---- | - | ----------------------------- | - | ---- | ---- |  | - | ---- | - |  | - | ---- | -
|                                                                                                                                            |  | Three MonthsEndedSeptember 30,       |      |   | Nine MonthsEndedSeptember 30, |  
|                                                                                                                                            |  | 2004                                 |      |   | 2003                          |   |      | 2004 |  |   | 2003 |  
|                                                                                                                                            |  | (in millions, except per share data) |     
|Net income (loss) as reported                                                                                                               |  | $                                    | 78   |   |                               | $ | 5    |      |  | $ | 156  |   |  | $ | (138 | )
|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 |  |                                      | (6   | ) |                               |   | (13  | )    |  |   | (22  | ) |  |   | (41  | )
|                                                                                                                                            |  |                                      |      |   |                               |   |      |      |  |   |      |   |  |   |      |  
|Pro forma net income (loss)                                                                                                                 |  | $                                    | 73   |   |                               | $ | (8   | )    |  | $ | 137  |   |  | $ | (178 | )
|                                                                                                                                            |  |                                      |      |   |                               |   |      |      |  |   |      |   |  |   |      |  
|Earnings per share:                                                                                                                         |  |                                      |      |   |                               |   |      |      |  |   |      |   |  |   |      |  
|Basicas reported                                                                                                                           |  | $                                    | 0.19 |   |                               | $ | 3.17 |      |  | $ | 0.37 |   |  | $ | 2.36 |  
|Basicpro forma                                                                                                                             |  | $                                    | 0.18 |   |                               | $ | 3.14 |      |  | $ | 0.32 |   |  | $ | 2.25 |  
|Dilutedas reported                                                                                                                         |  | $                                    | 0.16 |   |                               | $ | 2.65 |      |  | $ | 0.32 |   |  | $ | 2.21 |  
|Dilutedpro forma                                                                                                                           |  | $                                    | 0.15 |   |                               | $ | 2.62 |      |  | $ | 0.28 |   |  | $ | 2.13 |  



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 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 stockholders 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.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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, we 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.



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, we 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, we 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



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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. The acquisition transforms the tolling and swap contracts into intercompany agreements, substantially eliminating their financial impact by retaining the net cash flows within our subsidiaries. Under the terms
of its indebtedness, however, Sithe Independence would have limitations on its ability to distribute cash to us. As a result of the purchase accounting rules under GAAP, which require each contractual arrangement to be adjusted to its fair market
value at closing, we expect to record a charge to earnings upon closing of the transaction.



The financial terms of the agreement include the payment of $135 million in cash and the consolidation of $919 million in face value project debt for which certain of the entities to be acquired are obligated. This
project debt will be recorded at its fair value as of the closing date, which we expect to be substantially less than the face value of $919 million. The principal and interest payments related to the consolidated debt will be substantially funded
through 2014 by the proceeds from the long-term capacity sales contract with Con Edison.



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.On September 30,
2004, we sold all of our outstanding common and preferred shares of Illinois Power Company, which formerly comprised our REG segment, owned by Illinova Corporation, our subsidiary, as well as our 20% interest in the Joppa power generation facility,
to Ameren for $2.3 billion. The $2.3 billion sale price consisted of Amerens assumption of $1.8 billion of Illinois Powers debt and preferred stock obligations, cash proceeds of approximately $375 million and an additional $100 million
of cash placed in escrow. Under the escrow agreement, which we have filed as an exhibit to this Form 10-Q, the $100 million deposited by Ameren will be released to us on the sooner of (i) December 31, 2010, (ii) the date on which DHIs senior
unsecured debt achieves an investment grade rating from Standard & Poors or Moodys Investor Services, Inc. or (iii) the occurrence of specified events relating to contingent environmental liabilities associated with Illinois
Powers former generating facilities. During the time that these funds remain in escrow, we will receive quarterly payments equivalent to the interest income earned on such funds.



Also on September 30, 2004, 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.



In the first quarter 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale in September 2004. SFAS No. 144 requires that long-lived
assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of Illinois Powers property, plant and equipment and regulatory assets, effective February 1, 2004.
Depreciation and amortization expense related to Illinois Power totaled $30 million and $91 million in the three- and nine-month periods ended September 30, 2003, respectively. In addition, SFAS No. 144 requires a loss to be recognized by the amount
Assets held for sale less Liabilities held



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



for sale are in excess of fair value less costs to sell. Accordingly, for the three-month periods ended March 31, 2004 and June 30, 2004, we recorded pre-tax
losses on the sale of $21 million and $48 million, respectively. The first quarter 2004 charge, which was primarily associated with the expected transaction costs, is reflected in Gain (loss) on sale of assets, net and Impairment and other charges
on our unaudited condensed consolidated statements of operations. The second quarter 2004 charge, an impairment of assets, is reflected in Impairment and other charges on the unaudited condensed consolidated statements of operations. Finally, in the
three-month period ended September 30, 2004, we recorded a pre-tax loss on the sale of $24 million. The charge is reflected in Gain (loss) on sale of assets, net on our unaudited condensed consolidated statements of operations.



Further, pursuant to SFAS No. 144, we are not reporting the results of
Illinois Powers operations as a discontinued operation. If we were to account for Illinois Power as a discontinued operation, its results of operations would be condensed into Income (loss) from discontinued operations, net of taxes, on our
unaudited condensed consolidated statements of operations, and prior periods would be required to be restated to conform to this presentation. To qualify for discontinued operations classification, SFAS No. 144 and subsequent interpretations,
specifically EITF Issue 03-13, Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations, require that the
seller have no significant continuing involvement with the business being sold. As noted above, we have contracted to sell capacity and energy to Illinois Power for two years subsequent to the sale. Consequently, because we will have significant
continuing involvement with Illinois Power, we have reported the historical results of Illinois Powers operations in continuing operations. Additionally, earnings from power sales to Illinois Power derived from periods following the sale will
continue to be reported in the GEN segment in continuing operations.



Had the results of Illinois Power been excluded from our comparative results as though the sale had occurred at the beginning of each respective period noted below, our Revenues; Income (loss) before cumulative effect of changes in
accounting principles, net of tax; and Net income applicable to common stockholders and associated basic and diluted earnings per share would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30,
2004 and 2003, respectively.



|                                                                                       |  |                                      |       |      |                               |       |      |  |      |       |  |   |       |  
|-------------------------------------------------------------------------------------- |  | ------------------------------------ | ----- | ---- | ----------------------------- | ----- | ---- |  | ---- | ----- |  | - | ----- | -
|                                                                                       |  | Three MonthsEndedSeptember 30,       |       |      | Nine MonthsEndedSeptember 30, |      
|                                                                                       |  | 2004                                 |       | 2003 |                               |       | 2004 |  | 2003 |      
|                                                                                       |  | (in millions, except per share data) |      
|Revenues:                                                                              |  |                                      |       |      |                               |       |      |  |      |       |  |   |       |  
|As reported                                                                            |  | $                                    | 1,650 |      | $                             | 1,385 |      |  | $    | 4,747 |  | $ | 4,331 |  
|Pro forma                                                                              |  |                                      | 1,387 |      |                               | 1,160 |      |  |      | 3,953 |  |   | 3,562 |  
|                                                                                       |  |                                      |       |     
|Income (loss) before cumulative effect of change in accounting principles, net of tax: |  |                                      |       |      |                               |       |      |  |      |       |  |   |       |  
|As reported                                                                            |  | $                                    | 78    |      | $                             | 5     |      |  | $    | 156   |  | $ | (193  | )
|Pro forma                                                                              |  |                                      | 48    |      |                               | (9    | )    |  |      | 132   |  |   | (214  | )
|                                                                                       |  |                                      |       |     
|Net income applicable to common stockholders:                                          |  |                                      |       |      |                               |       |      |  |      |       |  |   |       |  
|As reported                                                                            |  | $                                    | 72    |      | $                             | 1,188 |      |  | $    | 139   |  | $ | 880   |  
|Pro forma                                                                              |  |                                      | 42    |      |                               | 1,174 |      |  |      | 115   |  |   | 859   |  



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



|                                                                                                   |  |                                      |      |                               |   |      |  |      |      |  |   |     
|-------------------------------------------------------------------------------------------------- |  | ------------------------------------ | ---- | ----------------------------- | - | ---- |  | ---- | ---- |  | - | ----
|                                                                                                   |  | Three MonthsEndedSeptember 30,       |      | Nine MonthsEndedSeptember 30,
|                                                                                                   |  | 2004                                 |      | 2003                          |   | 2004 |  | 2003
|                                                                                                   |  | (in millions, except per share data)
|Earnings per shareIncome before cumulative effect of change in accounting principles, net of tax: |  |                                      |      |                               |   |      |  |      |      |  |   |     
|Basicas reported                                                                                  |  | $                                    | 0.19 |                               | $ | 3.17 |  | $    | 0.37 |  | $ | 2.21
|Basicpro forma                                                                                    |  | $                                    | 0.11 |                               | $ | 3.13 |  | $    | 0.30 |  | $ | 2.16
|Dilutedas reported                                                                                |  | $                                    | 0.16 |                               | $ | 2.65 |  | $    | 0.32 |  | $ | 2.08
|Dilutedpro forma                                                                                  |  | $                                    | 0.10 |                               | $ | 2.62 |  | $    | 0.27 |  | $ | 2.04
|                                                                                                   |  |                                      |      |                              
|Earnings per shareNet income applicable to common stockholders:                                   |  |                                      |      |                               |   |      |  |      |      |  |   |     
|Basicas reported                                                                                  |  | $                                    | 0.19 |                               | $ | 3.17 |  | $    | 0.37 |  | $ | 2.36
|Basicpro forma                                                                                    |  | $                                    | 0.11 |                               | $ | 3.13 |  | $    | 0.30 |  | $ | 2.30
|Dilutedas reported                                                                                |  | $                                    | 0.16 |                               | $ | 2.65 |  | $    | 0.32 |  | $ | 2.21
|Dilutedpro forma                                                                                  |  | $                                    | 0.10 |                               | $ | 2.62 |  | $    | 0.27 |  | $ | 2.17



Joppa.We recorded a pre-tax gain of $75 million upon closing of the sale of our 20% interest in the Joppa power generating facility. This gain is included in Earnings from unconsolidated investments on our unaudited condensed consolidated
statements of operations.



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



PESA. In April 2004, we sold our interest in the Plantas Eolicas, S.A. de R.L. 20 MW wind-powered electric generation facility located in
Costa Rica for approximately $11 million. We recognized a pre-tax loss of approximately $1 million on the sale. This loss 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



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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 substantial portions of our communications business and 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 |   |     | DGC |  |   | 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 |         |   |    |     |  |   | 8             |   |  |       |   |   |  |   | 9   |  
|Gain on sale after taxes                   |  |               | 1 |         |   |    |     |  |   | 5             |   |  |       |   |   |  |   | 6   |  
|                                           |  |               |   |         |  
|                                           |  | U.K.Storage   |   | U.K.CRM |   |     | DGC |  |   | GlobalLiquids |   |  | Total |   
|                                           |  | (in millions) |  
|Nine Months Ended September 30, 2004       |  |               |   |         |   |     |     |  |   |               |   |  |       |    |   |  |   |     |  
|Income from operations before taxes        |  | $             |  |         | $ | 17  |     |  | $ | 3             |   |  | $     | 1  |   |  | $ | 21  |  
|Income (loss) from operations after taxes  |  |               |  |         |   | (9  | )   |  |   | 2             |   |  |       |   |   |  |   | (7  | )
|                                           |  |               |   |         |  
|Nine Months Ended September 30, 2003       |  |               |   |         |   |     |     |  |   |               |   |  |       |    |   |  |   |     |  
|Revenue                                    |  | $             |  |         | $ | 21  |     |  | $ | 5             |   |  | $     |   |   |  | $ | 26  |  
|Loss from operations before taxes          |  |               |  |         |   | (18 | )   |  |   | (29           | ) |  |       | (3 | ) |  |   | (50 | )
|Loss from operations after taxes           |  |               |  |         |   | (13 | )   |  |   | (18           | ) |  |       | (2 | ) |  |   | (33 | )
|Gain on sale before taxes                  |  |               | 1 |         |   |    |     |  |   | 33            |   |  |       |   |   |  |   | 34  |  
|Gain on sale after taxes                   |  |               | 1 |         |   |    |     |  |   | 26            |   |  |       |   |   |  |   | 27  |  



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. Also in the first quarter 2004, we recognized $3 million of pre-tax income associated with DGCs receipt of $3 million from a third party in settlement of a prior contractual claim. 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 12Income Taxes for further discussion.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



Note 3Restructuring Charges



In the nine months ended September 30, 2004, we recorded charges relating to the sale of our interest in Illinois Power
totaling $93 million. For further discussion, please read Note 2Acquisitions, Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSale of Illinois Power. In addition, 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  |  | $             | 23  |   |                                     | $ | 30 |       |  | $ | 53  |  
|2004 adjustments to liability |  |               | 18  |   |                                     |   | 7  |       |  |   | 25  |  
|Cash payments                 |  |               | (36 | ) |                                     |   | (8 | )     |  |   | (44 | )
|                              |  |               |     |   |                                     |   |    |       |  |   |     |  
|Balance at September 30, 2004 |  | $             | 5   |   |                                     | $ | 29 |       |  | $ | 34  |  
|                              |  |               |     |   |                                     |   |    |       |  |   |     |  



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 our former chief executive officer and our former president. Cash
payments during 2004 reflect payments made to our former chief executive officer and our former president. Please see Note 9Commitments and ContingenciesSeverance Arbitrations for further discussion regarding the status of these claims
and settlement payments.



We expect the $29 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-25 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 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.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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 and the European communications 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 stockholders equity were recognized in income, resulting in an after-tax loss of approximately $16 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 stockholders equity.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



Accumulated other comprehensive loss.Accumulated other comprehensive loss, net of tax,
is included in stockholders 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          |  |                   | 15  |   |                  |   | 27  |  
|Minimum pension liability                        |  |                   | (16 | ) |                  |   | (57 | )
|                                                 |  |                   |     |   |                  |   |     |  
|Accumulated other comprehensive loss, net of tax |  | $                 | (24 | ) |                  | $ | (20 | )
|                                                 |  |                   |     |   |                  |   |     |  



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                  |  | $                 | 374 |                  | $ | 518
|NGL investments                  |  |                   | 78  |                  |   | 82 
|                                 |  |                   |     |                  |   |    
|Total equity affiliates          |  |                   | 452 |                  |   | 600
|Other affiliates, at cost        |  |                   | 7   |                  |   | 12 
|                                 |  |                   |     |                  |   |    
|Total unconsolidated investments |  | $                 | 459 |                  | $ | 612
|                                 |  |                   |     |                  |   |    



Summarized aggregate
financial information for unconsolidated equity investments and our equity share thereof was:



|                 |  |                                 |       |             |   |       |  |             |       |  |   |    
|---------------- |  | ------------------------------- | ----- | ----------- | - | ----- |  | ----------- | ----- |  | - | ---
|                 |  | Nine Months Ended September 30,
|                 |  | 2004                            |       | 2003       
|                 |  | Total                           |       | EquityShare |   | Total |  | EquityShare
|                 |  | (in millions)                  
|Revenues         |  | $                               | 1,589 |             | $ | 709   |  | $           | 2,143 |  | $ | 887
|Operating income |  |                                 | 367   |             |   | 173   |  |             | 406   |  |   | 180
|Net income       |  |                                 | 339   |             |   | 162   |  |             | 337   |  |   | 148



Earnings from
unconsolidated investments of $194 million for the nine months ended September 30, 2004 include the $162 million above, gains on the sales of our 20% interest in the Joppa facility, our equity investment in Oyster Creek and our equity investment in
Hartwell of $75 million, $15 million and $2 million, respectively. These gains were partially 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 $7 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 $142 million for the nine
months ended September 30, 2003 consist of the $148 million above, partially offset by $5 million in losses due to impairments of cost investments and a $1 million loss on sale of an investment.



During the first quarter 2004, we sold our interest in our power generating
facility located in Jamaica. Net proceeds associated with the sale were approximately $5.5 million, and we did not recognize a gain or loss on the sale.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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



Notes payable and long-term debt consisted of the following:



|                     |  |                   |       |                  |   |      
|-------------------- |  | ----------------- | ----- | ---------------- | - | -----
|                     |  | September 30,2004 |       | December 31,2003
|                     |  | (in millions)    
|Dynegy Holdings Inc. |  | $                 | 4,150 |                  | $ | 3,744
|Illinova             |  |                   |      |                  |   | 95   
|Illinois Power       |  |                   |      |                  |   | 1,937
|Dynegy Inc.          |  |                   | 350   |                  |   | 448  
|                     |  |                   |       |                  |   |      
|Total                |  | $                 | 4,500 |                  | $ | 6,224
|                     |  |                   |       |                  |   |      



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, DHI 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 DHIs $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 DHIs 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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##### Table of Contents

DYNEGY 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 DHIs 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). DHI 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, including Illinois Power 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 DHI; 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. We and substantially all of our subsidiaries also guarantee this facility.



The credit facility contains affirmative and negative covenants, including
negative covenants relating to the following which restrict DHI and its subsidiaries but do not restrict us: 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.



The credit facility generally prohibits DHI and its subsidiaries, subject to specified exceptions, from incurring additional debt. Notwithstanding this
restriction, DHI may issue, to the extent permitted by the more restrictive covenants with respect to secured debt in the indenture governing the DHI 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.



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



We and our
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



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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.



Repayments. For the nine months ended September 30, 2004, we repaid the $95 million aggregate principal amount of Illinovas 7.125% Senior Notes due 2004. We also made principal repayments of $65
million related to Illinois Powers transitional funding trust notes.



In the nine months ended September 2004, we made $97 million in pre-payments on the ChevronTexaco junior notes. Additionally, in October 2004, we used approximately $125 million of the proceeds from the sale of
Illinois Power to mandatorily redeem all outstanding ChevronTexaco junior notes, as required by the indenture governing these notes.



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, we delivered notice of our intent to exercise our option in order for DMG to purchase the turbines upon
the expiration of the operating lease in September 2004. Based on 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 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 see Note 13Related Party TransactionsTransactions with ChevronTexaco beginning on page F-43
of our Form 10-K for further discussion.



Series C
Convertible Preferred Stock. As discussed in Note 15Redeemable Preferred SecuritiesSeries C Convertible Preferred Stock beginning on page F-48 of our Form 10-K, in August 2003 we issued 8 million shares of our Series C
convertible preferred stock due 2033 to CUSA as a part of a restructuring of our Series B Preferred Stock. The restructuring resulted in a preferred stock dividend gain of $1.2 billion, reflected on the unaudited condensed consolidated statements of
operations for the three and nine months ended September 30, 2003.



We accrue dividends on our Series C convertible preferred stock at a rate of 5.5% per annum. We made the first semi-annual dividend payment of $11 million on February 11, 2004. On August 11, 2004, we made our second semi-annual dividend
payment of $11 million.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



Note 8Earnings Per Share



The reconciliation of basic earnings per share from continuing operations to diluted earnings per share from continuing
operations is shown in the following table:



|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|---------------------------------------------------------------- |  | --------------------------------------- | ---- | ---- | ------------------------------ | ------ | ---- |  | ---- | ---- |  | - | ------ | -
|                                                                 |  | Three Months EndedSeptember 30,         |      |      | Nine Months EndedSeptember 30, |       
|                                                                 |  | 2004                                    |      | 2003 |                                |        | 2004 |  | 2003 |     
|                                                                 |  | (in millions, except per share amounts) |     
|Income (loss) from continuing operations                         |  | $                                       | 80   |      | $                              | 4      |      |  | $    | 163  |  | $ | (187   | )
|Less: convertible preferred stock dividends (gain)               |  |                                         | 6    |      |                                | (1,183 | )    |  |      | 17   |  |   | (1,018 | )
|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Income from continuing operations for basic earnings per share   |  |                                         | 74   |      |                                | 1,187  |      |  |      | 146  |  |   | 831    |  
|Effect of dilutive securities:                                   |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Interest on convertible subordinated debentures                  |  |                                         | 2    |      |                                | 1      |      |  |      | 5    |  |   | 1      |  
|Dividends on Series C convertible preferred stock                |  |                                         | 6    |      |                                | 3      |      |  |      | 17   |  |   | 3      |  
|Dividends on Series B convertible preferred stock (1)            |  |                                         |     |      |                                | 38     |      |  |      |     |  |   |       |  
|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Income from continuing operations for diluted earnings per share |  | $                                       | 82   |      | $                              | 1,229  |      |  | $    | 168  |  | $ | 835    |  
|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Basic weighted-average shares                                    |  |                                         | 379  |      |                                | 375    |      |  |      | 378  |  |   | 373    |  
|Effect of dilutive securities:                                   |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Stock options                                                    |  |                                         | 2    |      |                                | 2      |      |  |      | 2    |  |   | 2      |  
|Convertible subordinated debentures                              |  |                                         | 54   |      |                                | 28     |      |  |      | 54   |  |   | 9      |  
|Series C convertible preferred stock                             |  |                                         | 69   |      |                                | 37     |      |  |      | 69   |  |   | 13     |  
|Series B convertible preferred stock (1)                         |  |                                         |     |      |                                | 22     |      |  |      |     |  |   |       |  
|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Diluted weighted-average shares                                  |  |                                         | 504  |      |                                | 464    |      |  |      | 503  |  |   | 397    |  
|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Earnings per share from continuing operations:                   |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Basic                                                            |  | $                                       | 0.20 |      | $                              | 3.17   |      |  | $    | 0.39 |  | $ | 2.23   |  
|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  
|Diluted                                                          |  | $                                       | 0.16 |      | $                              | 2.65   |      |  | $    | 0.33 |  | $ | 2.10   |  
|                                                                 |  |                                         |      |      |                                |        |      |  |      |      |  |   |        |  

---

|(1) | The diluted shares for the nine months ended September 30, 2003 do not include the effect of the preferential conversion to Class B common stock of the Series B Mandatorily
Convertible Redeemable Preferred Stock previously held by a ChevronTexaco subsidiary, as such inclusion would be anti-dilutive.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Note 9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 $61 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



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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:



| |  | We 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 our 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.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | We 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, we would pay the plaintiff $30.75 million for a full and final release of all claims. We expect 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 are defending a class action lawsuit filed on behalf of purchasers of our publicly
traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit principally asserts that we and 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



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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, we are a nominal defendant in several derivative lawsuits
brought by shareholders on Dynegys behalf against certain of our 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. Our 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. We are 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 our 401(k) Savings Plan, including claims that our Board and certain of our former and current officers, past and present members of our Benefit Plans Committee, former employees who served on a predecessor committee to our 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 stockin particular with respect to our 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, we filed a motion to dismiss this action. The judge entered an order on our motion in March 2004, dismissing several of the plaintiffs claims and all of the defendants except Dynegy
and the members of our 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 our applicable
insurance limits, and we expect 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



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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.



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



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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 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 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.



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. We have removed the action from state court and consolidated it 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



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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.



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



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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 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, 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



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For the Interim Periods Ended September 30, 2004 and 2003



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.



Severance Arbitrations. Our 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, we 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, we 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 we maintain 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 us 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 our
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.



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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 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



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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.



Stumpf Litigation. We and two former subsidiaries are defendants in a lawsuit filed in New York by Stumpf AG and two of its affiliates
stemming from the shutdown of our Vienna telecommunications office in the spring of 2001. The plaintiffs are seeking $29 million in compensatory and unspecified punitive damages, alleging breach of contract, tortious interference and alter ego-based
claims primarily relating to the termination of real property leases to which our former Austrian subsidiary was a party. These claims are based on similar lawsuits filed in Austria against our former Austrian subsidiary, which was sold to a third
party in January 2003. This former subsidiary is in liquidation and, recently, one of its liquidators admitted, for purposes of the liquidation, the plaintiffs claims in the amount of $30 million. Although this lawsuit was initially stayed
pending the Austrian insolvency proceeding, the stay was lifted and we filed our answer in May 2004. The parties are actively engaged in discovery.



We intend to oppose these claims vigorously and believe we have meritorious defenses. Although it is not possible to predict with certainty whether we
will incur any liability in connection with these lawsuits, we do not believe that any liability we might incur as a result of these lawsuits would have a material adverse effect on our financial condition, results of operations or cash flows.
Reserves have been provided in connection with this litigation.



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 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 our 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



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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 we maintain and our ERISA affiliates. We have 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. We have not yet received
the Department of Labors definitive findings resulting from its investigation.



Note 10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



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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 Dynegy 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 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 11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 20Employee Compensation, Savings and Pension Plans beginning on page F-68 of our Form 10-K.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



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    |  | $                                | 6   |   |                | $ | 5   |      |  | $ | 1    |   |  | $ | 1  |  
|Interest cost on projected benefit obligation |  |                                  | 10  |   |                |   | 10  |      |  |   | 3    |   |  |   | 3  |  
|Expected return on plan assets                |  |                                  | (12 | ) |                |   | (13 | )    |  |   | (2   | ) |  |   | (1 | )
|Recognized net actuarial loss                 |  |                                  | 4   |   |                |   | 2   |      |  |   | 2    |   |  |   | 1  |  
|Settlement and curtailment (gain) loss        |  |                                  | 144 |   |                |   |    |      |  |   | (8   | ) |  |   |   |  
|                                              |  |                                  |     |   |                |   |     |      |  |   |      |   |  |   |    |  
|Total net periodic benefit cost (benefit)     |  | $                                | 152 |   |                | $ | 4   |      |  | $ | (4   | ) |  | $ | 4  |  
|                                              |  |                                  |     |   |                |   |     |      |  |   |      |   |  |   |    |  
|                                              |  |                                 
|                                              |  | Pension Benefits                 |     |   | Other Benefits |  
|                                              |  | Nine Months Ended September 30,  |    
|                                              |  | 2004                             |     |   | 2003           |   |     | 2004 |  |   | 2003 |  
|                                              |  | (in millions)                    |    
|Service cost benefits earned during period    |  | $                                | 18  |   |                | $ | 16  |      |  | $ | 4    |   |  | $ | 3  |  
|Interest cost on projected benefit obligation |  |                                  | 31  |   |                |   | 30  |      |  |   | 9    |   |  |   | 8  |  
|Expected return on plan assets                |  |                                  | (37 | ) |                |   | (40 | )    |  |   | (5   | ) |  |   | (4 | )
|Recognized net actuarial loss                 |  |                                  | 12  |   |                |   | 7   |      |  |   | 4    |   |  |   | 4  |  
|Settlement and curtailment (gain) loss        |  |                                  | 144 |   |                |   |    |      |  |   | (8   | ) |  |   |   |  
|                                              |  |                                  |     |   |                |   |     |      |  |   |      |   |  |   |    |  
|Total net periodic benefit cost               |  | $                                | 168 |   |                | $ | 13  |      |  | $ | 4    |   |  | $ | 11 |  
|                                              |  |                                  |     |   |                |   |     |      |  |   |      |   |  |   |    |  



The settlement and
curtailment (gain) loss is a result of the sale of Illinois Power, and resulting reduction in plan participants, and is included in the loss on its sale. For further information see Note 2Acquisitions, Dispositions, Contract Terminations and
Discontinued OperationsDispositions and Contract TerminationsSale of Illinois Power.



Contributions.In Note 20Employee Compensation, Savings and Pension PlansContributions beginning on page F-72 of our Form 10-K,
we reported that we expected to contribute approximately $13 million to our pension and other postretirement benefit plans in 2004. Due to the Pension Funding Equity Act of 2004, we are no longer required to make estimated quarterly contributions in
2004. However, under the terms of our agreement to sell Illinois Power to Ameren, we accelerated approximately $7 million of future cash funding requirements in September 2004.



Note 12Income Taxes



Capital Loss Valuation Allowance.As a result of the asset sales discussed in Note 2Acquisitions, Dispositions, Contract Terminations
and Discontinued Operations, as well as other transactions forecasted to occur during the remainder of 2004, we reduced the valuation allowance related to our significant capital loss carryforward by $11 million and $58 million in the three and nine
months ended September 30, 2004, respectively. This capital loss carryforward primarily related to our third quarter 2002 sale of Northern Natural Gas Company. This benefit is reflected in Income tax benefit (expense) on our unaudited condensed
consolidated statements of operations.



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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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2004 and 2003



Note 13Segment Information



We report our operations in the following segments: GEN, NGL, REG 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 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 |   |       | REG |  |   | CRM |   |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                          |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Domestic                                        |  | $   | 273   |   |     | $ | 920   |     |  | $ | 377 |   |  | $                     | 94    |   |       | $ |     |   |  | $ | 1,664  |  
|Other                                           |  |     |      |   |     |   |      |     |  |   |    |   |  |                       | (14   | ) |       |   |     |   |  |   | (14    | )
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|                                                |  |     | 273   |   |     |   | 920   |     |  |   | 377 |   |  |                       | 80    |   |       |   |     |   |  |   | 1,650  |  
|Intersegment revenues                           |  |     | 156   |   |     |   | 76    |     |  |   | 6   |   |  |                       | (71   | ) |       |   | (167 | ) |  |   |       |  
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Total revenues                                  |  | $   | 429   |   |     | $ | 996   |     |  | $ | 383 |   |  | $                     | 9     |   |       | $ | (167 | ) |  | $ | 1,650  |  
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|                                                |  |     |       |   |     |  
|Depreciation and amortization                   |  | $   | (50   | ) |     | $ | (21   | )   |  | $ |    |   |  | $                     | (1    | ) |       | $ | (7   | ) |  | $ | (79    | )
|Operating income (loss)                         |  | $   | 71    |   |     | $ | 72    |     |  | $ | 83  |   |  | $                     | (32   | ) |       | $ | (55  | ) |  | $ | 139    |  
|Earnings from unconsolidated investments        |  |     | 99    |   |     |   | 3     |     |  |   |    |   |  |                       |      |   |       |   |     |   |  |   | 102    |  
|Other items, net                                |  |     |      |   |     |   | (6    | )   |  |   | 2   |   |  |                       | (3    | ) |       |   | 1    |   |  |   | (6     | )
|Interest expense                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   | (125   | )
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Income from continuing operations before taxes  |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   | 110    |  
|Income tax expense                              |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   | (30    | )
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Income from continuing operations               |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   | 80     |  
|Loss from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   | (2     | )
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Net income                                      |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  | $ | 78     |  
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Identifiable assets:                            |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Domestic                                        |  | $   | 6,449 |   |     | $ | 1,809 |     |  | $ | 18  |   |  | $                     | 1,667 |   |       | $ | 560  |   |  | $ | 10,503 |  
|Other                                           |  |     | 3     |   |     |   | 4     |     |  |   |    |   |  |                       | 192   |   |       |   | 29   |   |  |   | 228    |  
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Total                                           |  | $   | 6,452 |   |     | $ | 1,813 |     |  | $ | 18  |   |  | $                     | 1,859 |   |       | $ | 589  |   |  | $ | 10,731 |  
|                                                |  |     |       |   |     |   |       |     |  |   |     |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Unconsolidated investments                      |  | $   | 381   |   |     | $ | 78    |     |  | $ |    |   |  | $                     |      |   |       | $ |     |   |  | $ | 459    |  
|                                                |  |     |       |   |     |  
|Capital expenditures                            |  | $   | (20   | ) |     | $ | (14   | )   |  | $ | (31 | ) |  | $                     |      |   |       | $ | (5   | ) |  | $ | (70    | )



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DYNEGY 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 |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                            |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                          |  | $   | 65    |   |     | $ | 620   |     |  | $ | 394   |   |  | $                     | 352   |   |       | $ |       |   |  | $ | 1,431  |  
|Other                                             |  |     |      |   |     |   | 3     |     |  |   |      |   |  |                       | (49   | ) |       |   |       |   |  |   | (46    | )
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|                                                  |  |     | 65    |   |     |   | 623   |     |  |   | 394   |   |  |                       | 303   |   |       |   |       |   |  |   | 1,385  |  
|Intersegment revenues                             |  |     | 410   |   |     |   | 58    |     |  |   | 8     |   |  |                       | (301  | ) |       |   | (175   | ) |  |   |       |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total revenues                                    |  | $   | 475   |   |     | $ | 681   |     |  | $ | 402   |   |  | $                     | 2     |   |       | $ | (175   | ) |  | $ | 1,385  |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Depreciation and amortization                     |  | $   | (48   | ) |     | $ | (19   | )   |  | $ | (30   | ) |  | $                     |      |   |       | $ | (12    | ) |  | $ | (109   | )
|                                                  |  |     |       |   |     |  
|Operating income (loss)                           |  | $   | 77    |   |     | $ | 31    |     |  | $ | 64    |   |  | $                     | (26   | ) |       | $ | (45    | ) |  | $ | 101    |  
|Earnings (losses) from unconsolidated investments |  |     | 51    |   |     |   | 2     |     |  |   |      |   |  |                       | (2    | ) |       |   |       |   |  |   | 51     |  
|Other items, net                                  |  |     | 1     |   |     |   | (2    | )   |  |   |      |   |  |                       | 4     |   |       |   | (3     | ) |  |   |       |  
|Interest expense                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (145   | )
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Income from continuing operations before taxes    |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 7      |  
|Income tax expense                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (3     | )
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Income from continuing operations                 |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 4      |  
|Income from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 1      |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Net Income                                        |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  | $ | 5      |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Identifiable assets:                              |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                          |  | $   | 6,380 |   |     | $ | 1,679 |     |  | $ | 5,408 |   |  | $                     | 2,357 |   |       | $ | (2,315 | ) |  | $ | 13,509 |  
|Other                                             |  |     |      |   |     |   |      |     |  |   |      |   |  |                       | 297   |   |       |   | 35     |   |  |   | 332    |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total                                             |  | $   | 6,380 |   |     | $ | 1,679 |     |  | $ | 5,408 |   |  | $                     | 2,654 |   |       | $ | (2,280 | ) |  | $ | 13,841 |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Unconsolidated investments                        |  | $   | 573   |   |     | $ | 95    |     |  | $ |      |   |  | $                     |      |   |       | $ |       |   |  | $ | 668    |  
|                                                  |  |     |       |   |     |  
|Capital expenditures                              |  | $   | (24   | ) |     | $ | (11   | )   |  | $ | (33   | ) |  | $                     |      |   |       | $ | (2     | ) |  | $ | (70    | )



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DYNEGY 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 |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                          |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Domestic                                        |  | $   | 373   |   |     | $ | 2,440 |     |  | $ | 1,146 |   |  | $                     | 868   |   |       | $ |     |   |  | $ | 4,827  |  
|Other                                           |  |     | 2     |   |     |   | 2     |     |  |   |      |   |  |                       | (84   | ) |       |   |     |   |  |   | (80    | )
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|                                                |  |     | 375   |   |     |   | 2,442 |     |  |   | 1,146 |   |  |                       | 784   |   |       |   |     |   |  |   | 4,747  |  
|Intersegment revenues                           |  |     | 910   |   |     |   | 221   |     |  |   | 19    |   |  |                       | (613  | ) |       |   | (537 | ) |  |   |       |  
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Total revenues                                  |  | $   | 1,285 |   |     | $ | 2,663 |     |  | $ | 1,165 |   |  | $                     | 171   |   |       | $ | (537 | ) |  | $ | 4,747  |  
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Depreciation and amortization                   |  | $   | (145  | ) |     | $ | (66   | )   |  | $ | (10   | ) |  | $                     | (1    | ) |       | $ | (27  | ) |  | $ | (249   | )
|Impairment and other charges                    |  |     |      |   |     |   | (5    | )   |  |   | (54   | ) |  |                       |      |   |       |   | (24  | ) |  |   | (83    | )
|                                                |  |     |       |   |     |  
|Operating income (loss)                         |  | $   | 159   |   |     | $ | 214   |     |  | $ | 158   |   |  | $                     | 45    |   |       | $ | (197 | ) |  | $ | 379    |  
|Earnings from unconsolidated investments        |  |     | 187   |   |     |   | 7     |     |  |   |      |   |  |                       |      |   |       |   |     |   |  |   | 194    |  
|Other items, net                                |  |     |      |   |     |   | (15   | )   |  |   | 3     |   |  |                       | (1    | ) |       |   | 4    |   |  |   | (9     | )
|Interest expense                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   | (402   | )
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Income from continuing operations before taxes  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   | 162    |  
|Income tax benefit                              |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   | 1      |  
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Income from continuing operations               |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   | 163    |  
|Loss from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   | (7     | )
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Net income                                      |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  | $ | 156    |  
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Identifiable assets:                            |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Domestic                                        |  | $   | 6,449 |   |     | $ | 1,809 |     |  | $ | 18    |   |  | $                     | 1,667 |   |       | $ | 560  |   |  | $ | 10,503 |  
|Other                                           |  |     | 3     |   |     |   | 4     |     |  |   |      |   |  |                       | 192   |   |       |   | 29   |   |  |   | 228    |  
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Total                                           |  | $   | 6,452 |   |     | $ | 1,813 |     |  | $ | 18    |   |  | $                     | 1,859 |   |       | $ | 589  |   |  | $ | 10,731 |  
|                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |      |   |  |   |        |  
|Unconsolidated investments                      |  | $   | 381   |   |     | $ | 78    |     |  | $ |      |   |  | $                     |      |   |       | $ |     |   |  | $ | 459    |  
|                                                |  |     |       |   |     |  
|Capital expenditures                            |  | $   | (78   | ) |     | $ | (41   | )   |  | $ | (92   | ) |  | $                     |      |   |       | $ | (10  | ) |  | $ | (221   | )



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DYNEGY 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 |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                                             |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                                           |  | $   | 286   |   |     | $ | 2,218 |     |  | $ | 1,170 |   |  | $                     | 698   |   |       | $ |       |   |  | $ | 4,372  |  
|Other                                                              |  |     |      |   |     |   | 3     |     |  |   |      |   |  |                       | (44   | ) |       |   |       |   |  |   | (41    | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|                                                                   |  |     | 286   |   |     |   | 2,221 |     |  |   | 1,170 |   |  |                       | 654   |   |       |   |       |   |  |   | 4,331  |  
|Intersegment revenues                                              |  |     | 940   |   |     |   | 193   |     |  |   | 22    |   |  |                       | (790  | ) |       |   | (365   | ) |  |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total revenues                                                     |  | $   | 1,226 |   |     | $ | 2,414 |     |  | $ | 1,192 |   |  | $                     | (136  | ) |       | $ | (365   | ) |  | $ | 4,331  |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Depreciation and amortization                                      |  | $   | (138  | ) |     | $ | (60   | )   |  | $ | (91   | ) |  | $                     | (1    | ) |       | $ | (50    | ) |  | $ | (340   | )
|Operating income (loss)                                            |  | $   | 176   |   |     | $ | 121   |     |  | $ | 158   |   |  | $                     | (348  | ) |       | $ | (193   | ) |  | $ | (86    | )
|Earnings from unconsolidated investments                           |  |     | 135   |   |     |   | 7     |     |  |   |      |   |  |                       |      |   |       |   |       |   |  |   | 142    |  
|Other items, net                                                   |  |     | 4     |   |     |   | (12   | )   |  |   |      |   |  |                       | 27    |   |       |   | (7     | ) |  |   | 12     |  
|Interest expense                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (364   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Loss from continuing operations before taxes                       |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (296   | )
|Income tax benefit                                                 |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 109    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Loss from continuing operations                                    |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (187   | )
|Loss from discontinued operations, net of taxes                    |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (6     | )
|Cumulative effect of change in accounting principles, net of taxes |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 55     |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Net loss                                                           |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  | $ | (138   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Identifiable assets:                                               |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                                           |  | $   | 6,380 |   |     | $ | 1,679 |     |  | $ | 5,408 |   |  | $                     | 2,357 |   |       | $ | (2,315 | ) |  | $ | 13,509 |  
|Other                                                              |  |     |      |   |     |   |      |     |  |   |      |   |  |                       | 297   |   |       |   | 35     |   |  |   | 332    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total                                                              |  | $   | 6,380 |   |     | $ | 1,679 |     |  | $ | 5,408 |   |  | $                     | 2,654 |   |       | $ | (2,280 | ) |  | $ | 13,841 |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Unconsolidated investments                                         |  | $   | 573   |   |     | $ | 95    |     |  | $ |      |   |  | $                     |      |   |       | $ |       |   |  | $ | 668    |  
|Capital expenditures                                               |  | $   | (117  | ) |     | $ | (36   | )   |  | $ | (101  | ) |  | $                     |      |   |       | $ | (5     | ) |  | $ | (259   | )



Note 14Subsequent Events



In October 2004, we paid approximately $125 million to
mandatorily redeem all outstanding ChevronTexaco junior notes. Please read Note 6Debt for further discussion.



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, we 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 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 been revised
to reflect the effect of the restatements of our previously disclosed goodwill impairment charge associated with the sale of Illinois Power and our deferred income tax accounts. We expect to file amendments to our Form 10-K and first and second
quarter 2004 Form 10-Qs reflecting all such items 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. As described below, our former regulated energy business, which was conducted through Illinois Power
and its subsidiaries, was sold to Ameren Corporation on September 30, 2004. 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 of our unregulated energy businesses 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 made significant 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 Illinois Power Company and our 20% interest in the Joppa power generation facility to Ameren for $2.3 billion. Please read Note
2Acquisitions, Dispositions, Contract Terminations and Discontinued OperationsSale of Illinois Power for further discussion.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | In October 2004, we used approximately $125 million in proceeds from the Illinois Power sale to mandatorily redeem all of the then outstanding ChevronTexaco junior notes.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | In November 2004, we 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. Please read Strategic Growth OpportunitiesSithe Energies for further discussion of this transaction.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Strategic Growth Opportunities



Although some issues remain to be addressed in connection with our
restructuring, we are beginning to shift our focus toward the identification and evaluation of strategic growth opportunities. These opportunities may include strategic acquisitions, such as the 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, we 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, we 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. The acquisition
transforms the tolling and swap contracts into intercompany agreements, substantially eliminating their impact on our consolidated financial results. Under the terms of its indebtedness, however, Sithe Independence would have limitations on its
ability to distribute cash to us. As a result of the purchase accounting rules under GAAP, which require each contractual arrangement to be adjusted to its fair market value at closing, we expect to record a charge to earnings upon closing of the
transaction.



At the closing of this acquisition, we have
agreed to pay Exelon $135 million in cash, subject to adjustment for certain pre-closing matters, and will consolidate approximately $919 million in face value project debt for which certain of the entities to be acquired are obligated. This project
debt will be recorded at its fair value as of the closing date, which we expect to be substantially less than the face value of $919 million. The principal and interest payments under the consolidated debt will be substantially funded through 2014
by the proceeds from the long-term capacity sales contract with Con Edison.



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



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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.



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



Notwithstanding our sale of
Illinois Power to Ameren, in which Ameren assumed $1.8 billion in Illinois Powers debt and preferred stock obligations, we continue to 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, DHI 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 DHIs $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 DHIs 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 the following:



| |  | $81 million in payments on the ChevronTexaco junior notes;
| | - | ----------------------------------------------------------



| |  | $78 million in payments relating to the termination of the Tilton capital lease, which is further described in Note 6DebtTilton Capital Lease; and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------



| |  | $22 million in amortizing payments on Illinois Powers transitional funding trust notes.
| | - | ----------------------------------------------------------------------------------------



Additionally, with the sale of Illinois Power, Ameren assumed approximately $1.8 billion of Illinois Powers
outstanding debt. As a result of this sale and the indenture governing the ChevronTexaco Junior Notes, we paid approximately $125 million in October 2004 to redeem the outstanding balance of these notes.



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As a result of our efforts, our aggregate maturities for long-term debt as of September 30, 2004 were
reduced to $1 million in 2004, $24 million in 2005, $29 million in 2006, $196 million in 2007, $230 million in 2008 and approximately $4 billion thereafter. This $4 billion in aggregate maturities for 2009 and beyond includes $125 million in
maturities relating to the ChevronTexaco junior notes, which were redeemed in full in October 2004 using of a portion of the cash proceeds from the sale of Illinois Power as required by the indenture governing those notes.



Furthermore, upon the closing of the Sithe Energies acquisition, our balance
sheet will reflect the consolidation of the fair value of approximately $919 million in face value project debt for which certain of the entities to be acquired are obligated. Please read GeneralStrategic Growth
OpportunitiesSithe Energies for further discussion of this transaction.



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, but our future financial condition and results of operations could be materially adversely affected by our ability to 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
|REG                    |  |                 | 11  |                   |   | 13               |  |   | 38 
|Other                  |  |                 | 17  |                   |   | 16               |  |   | 8  
|                       |  |                 |     |                   |   |                  |  |   |    
|Total                  |  | $               | 565 |                   | $ | 486              |  | $ | 482
|                       |  |                 |     |                   |   |                  |  |   |    
|By Type:               |  |                 |     |                   |   |                  |  |   |    
|Cash                   |  | $               | 452 |                   | $ | 368              |  | $ | 294
|Letters of Credit      |  |                 | 113 |                   |   | 118              |  |   | 188
|                       |  |                 |     |                   |   |                  |  |   |    
|Total                  |  | $               | 565 |                   | $ | 486              |  | $ | 482
|                       |  |                 |     |                   |   |                  |  |   |    



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. Finally, collateral postings at our REG segment have decreased by $27
million due to the sale of Illinois Power. We expect that the remaining $11 million of collateral will be eliminated by the first quarter 2005.



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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 61% of the aggregate collateral posted (or approximately $294 million) consisted of cash, compared to approximately 76% cash collateral (or
approximately $368 million) as of September 30, 2004 and 80% cash collateral (or approximately $452 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.



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.



Sale of Illinois
Power. In September 2004, we sold all of the outstanding common and preferred shares of Illinois Power Company, which formerly comprised our REG segment, and our 20% interest in the Joppa power generation facility to Ameren for $2.3 billion,
which included Amerens assumption of $1.8 billion of Illinois Powers debt and preferred stock obligations as well as the assumption of other obligations that totaled approximately $500 million at December 31, 2003.



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 $2,852 million as reported on page 42 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 $766 million as reported on page 42 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.



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Sithe Energies. Upon the closing of the Sithe Energies acquisition, our balance sheet will
reflect the consolidation of the fair value of approximately $919 million in face value project debt for which certain of the entities to be acquired are obligated. Please read GeneralStrategic Growth OpportunitiesSithe
Energies for further discussion of this transaction.



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



Dividends on Preferred and Common Stock



Dividend payments on our common stock are at the discretion of our Board of Directors. We did not declare or pay a dividend during the first nine months
of 2004 and do not foresee a declaration of dividends in the near term, particularly given our financial condition and the dividend restrictions contained in our financing agreements. We have, however, continued to make the required dividend
payments on our outstanding trust preferred securities.



We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. These dividends are payable in February and August of each year, but we may defer payments for up to 10 consecutive semi-annual periods. In February and August
2004, we paid our first and second semi-annual dividend payments totaling $22 million.



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 flows of $120 million for the nine months ended September
30, 2004. This consisted of $758 million in operating cash flows from our GEN, NGL and REG 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 partially offset by $638 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 2 of our Form 10-K for a discussion of our views
on supply 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 47 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.



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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 $124 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 the 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 $657 million and $926 million, respectively, as compared to $477 million at the end of 2003.This substantial 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 (i) our $600 million secured term loan and (ii) our sale of Illinois Power.



The decrease in cash between September 30, 2004 and November 8, 2004 primarily reflects the $125 million redemption of the remaining ChevronTexaco junior
notes and 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. We expect to use approximately $135 million to consummate the Sithe Energies acquisition and
additional amounts of this cash on hand for operations and capital expenditures. Please read GeneralStrategic Growth OpportunitiesSithe Energies for further discussion of this transaction. Based on current expectations,
we estimate that we will have approximately $610 million in cash on hand at year end, excluding payment of the $135 million purchase price upon closing of the Sithe Energies acquisition. Unforeseen events, such as legal judgments, regulatory
requirements or matters impacting our operations, could negatively impact our cash position.



Revolver Capacity.In May 2004, DHI 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                                                          |  |                 | 657   | (2) |                   |   | 926   | (2)              |  |   | 477   |  
|                                                              |  |                 |       |     |                   |   |       |                  |  |   |       |  
|Total Available Liquidity                                     |  | $               | 1,244 |     |                   | $ | 1,508 |                  |  | $ | 1,389 |  
|                                                              |  |                 |       |     |                   |   |       |                  |  |   |       |  

---

|(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 the redemption of the remaining ChevronTexaco
junior notes and the 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 $527 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 September 2004, we sold Illinois Power and our 20% interest in the Joppa
power generation facility to Ameren for $2.3 billion. We received approximately $375 million in cash, subject to working capital adjustments, and Ameren deposited $100 million in escrow, subject to full release to us on December 31, 2010 or earlier
upon the occurrence of specified events. Please read Note 2Acquisitions, Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSale of Illinois Power for further discussion of this
transaction.



In an effort to maximize our return on investment
and to further clarify our business strategy, we have been pursuing the sale of other assets that we do not consider core to our operations. These assets primarily include our ownership interests in certain non-strategic domestic and international
power generation facilities, which domestic facilities are detailed in Item 1. BusinessSegment DiscussionPower Generation beginning on page 2 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.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------



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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 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 our ongoing efforts to
develop a capital structure that is more closely aligned with the cash-generating potential of our asset-based businesses, each of which is subject to cyclical changes in commodity prices, we are 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. Our ability to issue public securities is enhanced by our
effective shelf registration statement, under which we have approximately $430 million in remaining availability and which will be available for use after we complete the 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, our non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond our 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 new 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. The sale of Illinois Power provided significant cash proceeds and advanced our business strategy of focusing on our unregulated energy businesses.



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.



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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), 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 the 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 36 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 substantially eliminate the financial impact of the Sithe tolling arrangement through the Sithe
Energies acquisition;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | Our ability to consummate the Sithe Energies acquisition and, if consummated, our ability to integrate the acquired entities and their operations and achieve our financial and
operational goals associated with that acquisition.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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, REG and CRM. Other reported results include corporate overhead
and our discontinued communications business. 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 |   |    | REG |  | CRM |    |  | Other andEliminations |     |   | Total |  
|                                                |  | (in millions) |   
|Operating income (loss)                         |  | $             | 71 |     | $ | 72 |     |  | $   | 83 |  | $                     | (32 | ) |       | $ | (55 | ) |  | $ | 139  |  
|Earnings from unconsolidated investments        |  |               | 99 |     |   | 3  |     |  |     |   |  |                       |    |   |       |   |    |   |  |   | 102  |  
|Other items, net                                |  |               |   |     |   | (6 | )   |  |     | 2  |  |                       | (3  | ) |       |   | 1   |   |  |   | (6   | )
|Interest expense                                |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | (125 | )
|                                                |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  
|Income from continuing operations before taxes  |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | 110  |  
|Income tax expense                              |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | (30  | )
|                                                |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  
|Income from continuing operations               |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | 80   |  
|Loss from discontinued operations, net of taxes |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | (2   | )
|                                                |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  
|Net income                                      |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  | $ | 78   |  
|                                                |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  



Quarter Ended
September 30, 2003



|                                                  |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  
|------------------------------------------------- |  | ------------- | -- | --- | - | -- | --- |  | --- | -- |  | --------------------- | --- | - | ----- | - | --- | - |  | - | ---- | -
|                                                  |  | GEN           |    | NGL |   |    | REG |  | CRM |    |  | Other andEliminations |     |   | Total |  
|                                                  |  | (in millions) |   
|Operating income (loss)                           |  | $             | 77 |     | $ | 31 |     |  | $   | 64 |  | $                     | (26 | ) |       | $ | (45 | ) |  | $ | 101  |  
|Earnings (losses) from unconsolidated investments |  |               | 51 |     |   | 2  |     |  |     |   |  |                       | (2  | ) |       |   |    |   |  |   | 51   |  
|Other items, net                                  |  |               | 1  |     |   | (2 | )   |  |     |   |  |                       | 4   |   |       |   | (3  | ) |  |   |     |  
|Interest expense                                  |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | (145 | )
|                                                  |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  
|Income from continuing operations before taxes    |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | 7    |  
|Income tax expense                                |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | (3   | )
|                                                  |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  
|Income from continuing operations                 |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | 4    |  
|Income from discontinued operations, net of taxes |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | 1    |  
|                                                  |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  
|Net income                                        |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  | $ | 5    |  
|                                                  |  |               |    |     |   |    |     |  |     |    |  |                       |     |   |       |   |     |   |  |   |      |  



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



|                                                  |  |                            |         |      |   |        
|------------------------------------------------- |  | -------------------------- | ------- | ---- | - | -------
|                                                  |  | QuarterEnded September 30,
|                                                  |  | 2004                       |         | 2003
|Power Generation                                  |  |                            |         |      |   |        
|Million megawatt hours generatedgross            |  |                            | 9.6     |      |   | 11.2   
|Million megawatt hours generatednet              |  |                            | 9.1     |      |   | 10.5   
|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   
|Regulated Energy Delivery                         |  |                            |         |      |   |        
|Electric sales in KWH (millions):                 |  |                            |         |      |   |        
|Residential                                       |  |                            | 1,592   |      |   | 1,766  
|Commercial                                        |  |                            | 1,217   |      |   | 1,208  
|Industrial                                        |  |                            | 1,168   |      |   | 1,561  
|Transportation of customer-owned electricity      |  |                            | 975     |      |   | 642    
|Other                                             |  |                            | 99      |      |   | 105    
|                                                  |  |                            |         |      |   |        
|Total electric sales                              |  |                            | 5,051   |      |   | 5,282  
|                                                  |  |                            |         |      |   |        
|Gas sales in Therms (millions):                   |  |                            |         |      |   |        
|Residential                                       |  |                            | 20      |      |   | 18     
|Commercial                                        |  |                            | 11      |      |   | 10     
|Industrial                                        |  |                            | 11      |      |   | 16     
|Transportation of customer-owned gas              |  |                            | 46      |      |   | 48     
|                                                  |  |                            |         |      |   |        
|Total gas delivered                               |  |                            | 88      |      |   | 92     
|                                                  |  |                            |         |      |   |        
|Cooling degree daysactual (3)                    |  |                            | 559     |      |   | 773    
|Cooling degree days10-year rolling average       |  |                            | 862     |      |   | 850    
|Heating degree daysactual (4)                    |  |                            | 49      |      |   | 88     
|Heating degree days10-year rolling average       |  |                            | 59      |      |   |       

---

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



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



|(3) | A Cooling Degree Day (CDD) represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in our service area. The CDDs for a period
of time are computed by adding the CDDs for each day during the period.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(4) | A Heating Degree Day (HDD) represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in our service area. The HDDs for a period
of time are computed by adding the HDDs for each day during the period.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 |   | REG |  |   | CRM |   | Other |   |   | Total |  
|                                |  | (in millions)                    |    
|Impairment of West Coast Power  |  | $                                | (45 | ) |     | $ |    |  | $ |    |   |       | $ |  |       | $ |    |   |  | $ | (45 | )
|Loss on sale of Illinois Power  |  |                                  |    |   |     |   |    |  |   | (24 | ) |       |   |  |       |   |    |   |  |   | (24 | )
|Gain on sale of Joppa           |  |                                  | 75  |   |     |   |    |  |   |    |   |       |   |  |       |   |    |   |  |   | 75  |  
|Gain on sale of Oyster Creek    |  |                                  | 15  |   |     |   |    |  |   |    |   |       |   |  |       |   |    |   |  |   | 15  |  
|Taxes                           |  |                                  |    |   |     |   |    |  |   |    |   |       |   |  |       |   | 13  |   |  |   | 13  |  
|                                |  |                                  |     |   |     |   |     |  |   |     |   |       |   |   |       |   |     |   |  |   |     |  
|Total                           |  | $                                | 45  |   |     | $ |    |  | $ | (24 | ) |       | $ |  |       | $ | 13  |   |  | $ | 34  |  
|                                |  |                                  |     |   |     |   |     |  |   |     |   |       |   |   |       |   |     |   |  |   |     |  
|                                | 
|                                |  | Quarter Ended September 30, 2003 |    
|                                |  | GEN                              |     |   | NGL |   | REG |  |   | CRM |   | Other |   |   | Total |  
|                                |  | (in millions)                    |    
|Acceleration of financing costs |  | $                                |    |   |     | $ |    |  | $ |    |   |       | $ |  |       | $ | (20 | ) |  | $ | (20 | )
|                                |  |                                  |     |   |     |   |     |  |   |     |   |       |   |   |       |   |     |   |  |   |     |  
|Total                           |  | $                                |    |   |     | $ |    |  | $ |    |   |       | $ |  |       | $ | (20 | ) |  | $ | (20 | )
|                                |  |                                  |     |   |     |   |     |  |   |     |   |       |   |   |       |   |     |   |  |   |     |  



Operating Income



Operating income was $139 million for the quarter
ended September 30, 2004, compared to $101 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 $77 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



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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.



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 7 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



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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 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.



REG. Operating income for the REG segment was $83 million for the quarter ended September 30, 2004, compared to $64 million for the
quarter ended September 30, 2003. The third quarter 2004 results include a loss on the sale of Illinois Power totaling approximately $24 million. This loss was more than offset by lower depreciation expense of approximately $31 million due to the
discontinuation of depreciation on our Illinois Power assets on February 1, 2004, as they were classified as held for sale.



Operationally, this segment was impacted by cooler weather in the third quarter 2004 as compared to 2003, which resulted in lower residential electric
sales volumes in 2004. Industrial electric sales were negatively affected by customers choosing alternate energy providers. Such switching is typically based on price. However, these decreases were more than offset by lower overall operating costs,
which were primarily due to the reimbursement of MISO exit fees and RTO development costs totaling approximately $10 million and lower departmental spending, partially offset by higher employee benefit costs. Residential and commercial gas sales
were relatively flat.



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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 $55 million for the quarter ended September 30, 2004, compared to a loss of $45 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 $102 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 $99 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 gains of $75 million and $15 million on the sales of our 20% interest in the Joppa power generation
facility and our 50% interest in the Oyster Creek facility, respectively. 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.



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 6 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 $125 million for the quarter ended September 30, 2004, compared to $145 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 $6 million for the quarter ended September 30, 2004, compared to zero for the quarter ended September 30,
2003. The decrease in 2004, as compared to 2003, is due to increased minority interest expense.



Income Tax Expense



We reported an income tax expense during the quarter ended September 30, 2004 of $30 million. The 2004 effective tax rate was 27%, compared to 43% in
2003. The 2004 tax expense includes a $13 million benefit, primarily related to a reduction in a deferred tax capital losses valuation allowance associated with anticipated gains on asset sales. Excluding this item from the 2004 calculation would
result in an effective tax rate of 39%. 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.



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Discontinued Operations



Discontinued operations includes our global liquids business in the NGL segment, our U.K. natural gas storage assets and our
U.K. CRM business in the CRM segment and our communications business in Other and Eliminations. The third quarter 2004 after-tax loss of $2 million is associated with our U.K. CRM business. The third quarter 2003 after-tax income of $1 million is
comprised of $5 million in an after-tax gain from the sale of the communications business partially offset by $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.



Preferred Stock Dividends (Gain)



The $6 million preferred stock dividend recognized in
the third quarter 2004 is related to our Series C preferred stock, which accumulates dividends at an annual rate of 5.5%. The 2003 gain of $1,183 million related to the restructuring of our Series B preferred stock in August 2003. Please read Note
15Redeemable Preferred Securities beginning on page F-48 of our Form 10-K for a description of the August 2003 exchange of the Series B preferred stock for, among other things, the Series C preferred stock, and the impact on the associated
dividends.



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 |   |     | REG |  | CRM |     |  | Other andEliminations |    |   | Total |  
|                                                |  | (in millions) |    
|Operating income (loss)                         |  | $             | 159 |     | $ | 214 |     |  | $   | 158 |  | $                     | 45 |   |       | $ | (197 | ) |  | $ | 379  |  
|Earnings from unconsolidated investments        |  |               | 187 |     |   | 7   |     |  |     |    |  |                       |   |   |       |   |     |   |  |   | 194  |  
|Other items, net                                |  |               |    |     |   | (15 | )   |  |     | 3   |  |                       | (1 | ) |       |   | 4    |   |  |   | (9   | )
|Interest expense                                |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   | (402 | )
|                                                |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   |      |  
|Income from continuing operations before taxes  |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   | 162  |  
|Income tax benefit                              |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   | 1    |  
|                                                |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   |      |  
|Income from continuing operations               |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   | 163  |  
|Loss from discontinued operations, net of taxes |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   | (7   | )
|                                                |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   |      |  
|Net income                                      |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  | $ | 156  |  
|                                                |  |               |     |     |   |     |     |  |     |     |  |                       |    |   |       |   |      |   |  |   |      |  



Nine Months Ended
September 30, 2003



|                                                                   |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   |      |  
|------------------------------------------------------------------ |  | ------------- | --- | --- | - | --- | --- |  | --- | --- |  | --------------------- | ---- | - | ----- | - | ---- | - |  | - | ---- | -
|                                                                   |  | GEN           |     | NGL |   |     | REG |  | CRM |     |  | Other andEliminations |      |   | Total |  
|                                                                   |  | (in millions) |    
|Operating income (loss)                                            |  | $             | 176 |     | $ | 121 |     |  | $   | 158 |  | $                     | (348 | ) |       | $ | (193 | ) |  | $ | (86  | )
|Earnings from unconsolidated investments                           |  |               | 135 |     |   | 7   |     |  |     |    |  |                       |     |   |       |   |     |   |  |   | 142  |  
|Other items, net                                                   |  |               | 4   |     |   | (12 | )   |  |     |    |  |                       | 27   |   |       |   | (7   | ) |  |   | 12   |  
|Interest expense                                                   |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   | (364 | )
|                                                                   |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   |      |  
|Loss from continuing operations before taxes                       |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   | (296 | )
|Income tax benefit                                                 |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   | 109  |  
|                                                                   |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   |      |  
|Loss from continuing operations                                    |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   | (187 | )
|Loss from discontinued operations, net of taxes                    |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   | (6   | )
|Cumulative effect of change in accounting principles, net of taxes |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   | 55   |  
|                                                                   |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   |      |  
|Net loss                                                           |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  | $ | (138 | )
|                                                                   |  |               |     |     |   |     |     |  |     |     |  |                       |      |   |       |   |      |   |  |   |      |  



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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            |  |                                | 29.3    |      |   | 29.8   
|Million megawatt hours generatednet              |  |                                | 27.8    |      |   | 28.2   
|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   
|Regulated Energy Delivery                         |  |                                |         |      |   |        
|Electric sales in KWH (millions):                 |  |                                |         |      |   |        
|Residential                                       |  |                                | 4,182   |      |   | 4,197  
|Commercial                                        |  |                                | 3,389   |      |   | 3,318  
|Industrial                                        |  |                                | 3,859   |      |   | 4,614  
|Transportation of customer-owned electricity      |  |                                | 2,407   |      |   | 1,792  
|Other                                             |  |                                | 287     |      |   | 292    
|                                                  |  |                                |         |      |   |        
|Total electric sales                              |  |                                | 14,124  |      |   | 14,213 
|                                                  |  |                                |         |      |   |        
|Gas sales in Therms (millions):                   |  |                                |         |      |   |        
|Residential                                       |  |                                | 214     |      |   | 238    
|Commercial                                        |  |                                | 85      |      |   | 98     
|Industrial                                        |  |                                | 40      |      |   | 57     
|Transportation of customer-owned gas              |  |                                | 171     |      |   | 170    
|                                                  |  |                                |         |      |   |        
|Total gas delivered                               |  |                                | 510     |      |   | 563    
|                                                  |  |                                |         |      |   |        
|Cooling degree daysactual (3)                    |  |                                | 932     |      |   | 971    
|Cooling degree days10-year rolling average       |  |                                | 1,236   |      |   | 1,214  
|Heating degree daysactual (4)                    |  |                                | 3,145   |      |   | 3,492  
|Heating degree days10-year rolling average       |  |                                | 3,190   |      |   | 3,018  

---

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



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



|(3) | A Cooling Degree Day (CDD) represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in our service area. The CDDs for a period
of time are computed by adding the CDDs for each day during the period.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(4) | A Heating Degree Day (HDD) represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in our service area. The HDDs for a period
of time are computed by adding the HDDs for each day during the period.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 |   |    | REG |  |   | CRM |   |  | Other |      |   | Total |  
|                                                     |  | (in millions)                        |    
|Discontinued operations                              |  | $                                    |    |   |     | $ | 1  |     |  | $ |    |   |  | $     | 17   |   |       | $ | 3   |   |  | $ | 21   |  
|Legal and settlement charges                         |  |                                      | 2   |   |     |   | 2  |     |  |   | (1  | ) |  |       |     |   |       |   | (57 | ) |  |   | (54  | )
|Impairment of Illinois Power                         |  |                                      |    |   |     |   |   |     |  |   | (54 | ) |  |       |     |   |       |   |    |   |  |   | (54  | )
|Impairment of West Coast Power                       |  |                                      | (45 | ) |     |   |   |     |  |   |    |   |  |       |     |   |       |   |    |   |  |   | (45  | )
|Loss on sale of Illinois Power                       |  |                                      |    |   |     |   |   |     |  |   | (39 | ) |  |       |     |   |       |   |    |   |  |   | (39  | )
|Acceleration of financing costs                      |  |                                      |    |   |     |   |   |     |  |   |    |   |  |       |     |   |       |   | (14 | ) |  |   | (14  | )
|Gas transportation contracts                         |  |                                      |    |   |     |   |   |     |  |   |    |   |  |       | 88   |   |       |   |    |   |  |   | 88   |  
|Gain on sale of Joppa                                |  |                                      | 75  |   |     |   |   |     |  |   |    |   |  |       |     |   |       |   |    |   |  |   | 75   |  
|Taxes                                                |  |                                      |    |   |     |   |   |     |  |   |    |   |  |       |     |   |       |   | 43  |   |  |   | 43   |  
|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                                                |  | $                                    | 47  |   |     | $ | 56 |     |  | $ | (94 | ) |  | $     | 105  |   |       | $ | (25 | ) |  | $ | 89   |  
|                                                     |  |                                      |     |   |     |   |    |     |  |   |     |   |  |       |      |   |       |   |     |   |  |   |      |  
|                                                     | 
|                                                     |  | Nine Months September 30, 2003       |    
|                                                     |  | GEN                                  |     |   | NGL |   |    | REG |  |   | CRM |   |  | Other |      |   | Total |  
|                                                     |  | (in millions)                        |    
|Discontinued operations                              |  | $                                    |    |   |     | $ | (3 | )   |  | $ |    |   |  | $     | (17  | ) |       | $ | 4   |   |  | $ | (16  | )
|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  |   |     |   |   |     |  |   | (3  | ) |  |       | 43   |   |       |   |    |   |  |   | 87   |  
|                                                     |  |                                      |     |   |     |   |    |     |  |   |     |   |  |       |      |   |       |   |     |   |  |   |      |  
|Total                                                |  | $                                    | 47  |   |     | $ | 7  |     |  | $ | (3  | ) |  | $     | (260 | ) |       | $ | (70 | ) |  | $ | (279 | )
|                                                     |  |                                      |     |   |     |   |    |     |  |   |     |   |  |       |      |   |       |   |     |   |  |   |      |  



Operating Income
(Loss)



Operating income was $379 million for the nine
months ended September 30, 2004, compared to a loss of $86 million for the nine months ended September 30, 2003.



GEN.Operating income for the GEN segment was $159 million for the nine months ended September 30, 2004, compared to $176 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,



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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 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 $7 million, from $138 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 7 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



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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, 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.



REG. Operating income for our REG segment was $158 million for the nine month periods ended September 30, 2004 and 2003. The 2004 period includes a $39 million charge related to the loss on the sale of Illinois Power
and a $54 million impairment of Illinois Power. We also stopped depreciating our Illinois Power assets on February 1, 2004, as they were classified as held for sale, which resulted in a benefit to operating income of $81 million compared to the nine
months ended September 30, 2003.



Operationally, residential
and commercial electric sales volumes for the 2004 period were negatively impacted by warmer than average winter weather compared to 2003. Industrial electric sales were negatively affected by customers choosing alternate energy providers. However,
these decreases were more than offset by lower overall operating costs, which were primarily due to the reimbursement of MISO exit fees and RTO



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development costs totaling approximately $10 million and lower departmental spending, partially offset by higher employee benefit costs. Residential and
commercial electric sales volumes were relatively flat in 2004 as compared to 2003 due to cooler summer weather offset by warmer spring weather.



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.



Other.Other operating loss was $197 million for the nine months ended September 30, 2004, compared to $193 million for the nine
months ended September 30, 2003. Results for 2004 include approximately $57 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 $194 million for the nine months ended September 30, 2004, compared to $142 million for the nine months ended September 30, 2003.



GEN. GENs earnings from unconsolidated investments were approximately $187 million for the nine months
ended September 30, 2004, compared to $135 million for the nine months ended September 30, 2003. Earnings for 2004 include gains of $75 million and $15 million on the sales of our 20% interest in the Joppa power generation facility and our 50%
interest in the Oyster Creek facility, respectively. 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 6 of
our Form 10-K for further discussion of West Coast Powers CDWR contract. Please read Note 9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.



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Interest Expense



Interest expense totaled $402 million for the nine months ended September 30, 2004, compared to $364 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 $9 million for the nine months ended September 30,
2004, compared to income of $12 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 Tax Benefit



We reported an income tax benefit during the nine months ended September 30, 2004 of $1 million. The 2004 effective tax rate was (1)%, compared to 37%
in 2003. The 2004 tax benefit includes a $58 million benefit related to a reduction in a deferred tax capital losses valuation allowance associated with anticipated gains on asset sales and a $3 million benefit primarily related to the conclusion of
prior year tax audits. Please read Note 12Income Taxes for further discussion. Excluding these items from the 2004 calculation would result in an effective tax rate of 37%. 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, our U.K. natural gas storage assets and our
U.K. CRM business in the CRM segment and our communications business in Other and Eliminations. The largest contributor to the pre-tax gain of $21 million ($7 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 12Income Taxes for further
discussion. The loss of $6 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, offset by $8 million
in after-tax income associated with the communications business.



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 $54
million ($34 million after-tax) associated with its implementation. The $54 million benefit was split between our GEN ($57 million) and REG ($(3) million) segments.



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



Preferred Stock Dividends (Gain)



The $17 million preferred stock dividend recognized in the first nine months
of 2004 is related to our Series C convertible preferred stock, which accumulates dividends at an annual rate of 5.5%. We pay dividends semi-annually on or before February 11 and August 11 of the respective year. The 2003 preferred stock gain of
$1,018 million related to the restructuring of our Series B preferred stock conducted in August 2003. Please read Note 15Redeemable Preferred Securities beginning on page 48 of our Form 10-K for a description of the August 2003 exchange
of the Series B preferred stock for, among other things, the Series C preferred stock, and the impact on the associated dividends.



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Outlook



The following summarizes our business outlook for our three remaining 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 2 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 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 9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



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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 and our 20% interest in the Joppa 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 five facilities, together with our investment in the Jamaica facility previously sold, 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, we 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  Strategic Growth Opportunities  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 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.



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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, we 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. 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.



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 some of these arrangements, but we cannot guarantee that we will be successful. If we do not
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 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 18 of our Form 10-K.



Until the closing of the 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.



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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 |   | REG |  | CRM |     |  | Other &Eliminations |      |   | Consolidated
|                                             |  | (in millions)
|For the nine months ended September 30, 2004 |  | $             | 351 |     | $ | 194 |  | $   | 213 |  | $                   | (179 | ) |              | $ | (459 | ) |  | $ | 120
|                                             |  |               |     |     |   |     |  |     |     |  |                     |      |   |              |   |      |   |  |   |    
|For the nine months ended September 30, 2003 |  | $             | 315 |     | $ | 156 |  | $   | 85  |  | $                   | 600  |   |              | $ | (222 | ) |  | $ | 934
|                                             |  |               |     |     |   |     |  |     |     |  |                     |      |   |              |   |      |   |  |   |    



Operating Cash
Flow. Our net cash provided by operating activities totaled $120 million for the nine months ended September 30, 2004. During the period, our GEN, NGL and REG segments provided positive cash flow from 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; NGL provided cash flow from operations of $194 million due primarily to positive
earnings, partially offset by increased prepayments due to higher sales; and REG provided cash flow from operations of $213 million due primarily to positive earnings for the period. 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 $459 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 $934 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 $110 million income tax refund reflected in Other
& Eliminations and the operational performances of our GEN, NGL and REG segments. Our GEN segment provided cash flows of $315 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. Our REG segment contributed operating cash flows of $85 million, primarily from normal operating
conditions offset by injections of gas into storage. 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 provided by investing activities during the nine months ended September 30, 2004 totaled $306 million. Capital spending of $221 million was comprised primarily of $78 million, $41 million and $92 million in
the GEN, NGL and REG 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. Capital spending in our REG segment related primarily to projects intended to maintain system reliability and new
business services. Net cash proceeds from asset sales of $527 million consisted primarily of the following items:



| |  | $217 million from the sale of Illinois Power, net of cash retained by Illinois Power of $52 million;
| | - | ----------------------------------------------------------------------------------------------------



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



| |  | $99 million from the sale of Joppa;
| | - | -----------------------------------



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



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



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Net cash used in investing activities during the nine months ended September 30, 2003 totaled $202
million. Capital spending of $259 million was comprised principally of $117 million, $36 million and $101 million in our GEN, NGL and REG 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, offset by $10 million in cash outflows associated with the sale of our European communications business. Finally, proceeds from the sale of unconsolidated investments
totaled approximately $25 million.



Financing Activities.Net cash provided by financing activities during the nine months ended September 30, 2004 totaled $24 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 $520 million for the nine months ended September 30, 2004 and consisted of the following: (1) payments of $95 million on a maturing series of Illinova senior
notes; (2) payments of $65 million on Illinois Powers transitional funding trust notes; (3) payments of $185 million under our ABG Gas Supply financing; (4) payments of $78 million on the Tilton capital lease; and (5) payments of $97 million
on the ChevronTexaco junior notes. Net cash provided by financing activities was also offset by a semi-annual dividend payment of $22 million on our Series C preferred stock.



Net cash used in financing activities during the nine months ended September 30, 2003 totaled $808 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 $1,608 million associated with the August
2003 refinancing, $142 million from the delayed issuance of $150 million in Illinois Power 11.5% Mortgage Bonds due 2010 and $159 million from the Term A Loan drawn in connection with the April 2, 2003 credit facility restructuring. In addition, in
connection with the August 2003 refinancing, we made a $225 million cash payment to ChevronTexaco. Repayments of long-term debt totaled $2,352 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;
| | - | -------------------------------------------------------------------------------------------



| |  | Funding of $190 million in Illinois Power mortgage bond maturities;
| | - | -------------------------------------------------------------------



| |  | Funding of a $100 million payment on Illinois Powers term loan;
| | - | ----------------------------------------------------------------



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



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



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



| |  | Prepaying $167 million of the $360 million Term B loan outstanding under DHIs restructured credit facility;
| | - | ------------------------------------------------------------------------------------------------------------



| |  | Funding of $66 million in amortizing payments on Illinois Powers transitional funding trust notes; $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 |    |   | ThreeMonthsEndedDecember 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



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, 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 ability to consummate the disposition of specified non-strategic assets on the terms and in the timeframes anticipated;
| | - | ---------------------------------------------------------------------------------------------------------------------------



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



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



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;
| | - | --------------------------------------------------------------------



| |  | the effects of the 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 our ability to engage in
capital-raising transactions;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  | our financial condition, including our ability to satisfy our 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 our ongoing efforts to improve our internal control structure, 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. 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.



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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 71 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 80 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



|                                |  |                        |     |                             |   |       |  |   |    
|------------------------------- |  | ---------------------- | --- | --------------------------- | - | ----- |  | - | ---
|                                |  | InvestmentGradeQuality |     | 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
|                                |  |                        |     |                             |   |       |  |   |    



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 73%. 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.



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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 our 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 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.



Beginning with the year ending December 31, 2004, Section 404 of the Sarbanes-Oxley Act of 2002 requires us to provide an annual internal controls report of management. This report must contain (i) a statement of managements
responsibility for establishing and maintaining adequate internal controls over financial reporting for our company, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our
internal controls over financial reporting, (iii) managements assessment of the effectiveness of our internal controls over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not our
internal controls over financial reporting are effective, and (iv) a statement that our independent auditors have issued an attestation report on managements assessment of our internal controls over financial reporting. Additionally, Section
404 requires that our independent auditors must issue an attestation report on managements assessment of our internal controls over financial reporting. In seeking to achieve compliance with Section 404 within the prescribed period, management
formed an internal



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control steering committee, engaged outside consultants and adopted and implemented a detailed project work plan to assess the adequacy of our 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.



As a result of this initiative, which we
began in 2003, we have identified a number of items that will likely result in changes to our 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.



We have also identified weaknesses in our 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 our audit and compliance committee and independent auditors. Accordingly, in this Form 10-Q, we have
revised our unaudited condensed consolidated balance sheet at December 31, 2003 to reflect a reduction to our deferred tax liability of $154 million. 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 our Tax Department to ensure appropriate segregation of duties regarding preparation and review of the quarterly tax provision.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------



In an effort to improve our existing controls and to seek to provide
management and our independent auditors the ability to make favorable evaluations and attestations under Section 404 of Sarbanes-Oxley, we expect to make additional changes in our internal controls over financial reporting with respect to these and
potentially other matters that may arise during the period prior to December 31, 2004.



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 Dynegy, 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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DYNEGY INC.



PART II. OTHER INFORMATION



Item 1LEGAL PROCEEDINGS



See
Note 9 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.                                          
|       | 
|+ 10.2 |  | Escrow Agreement dated as of September 30, 2004 among Illinova Corporation, Ameren Corporation and JPMorgan Chase Bank, as escrow agent.                   
|       | 
|+ 31.1 |  | Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.      
|       | 
|+ 31.2 |  | Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.      
|       | 
|*32.1  |  | Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|       | 
|*32.2  |  | Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

---

|+ | Filed herewith.
|- | ---------------



|* | Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as accompanying this report and not filed as part of
such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by
reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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DYNEGY 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 INC.          
|                        |  |  | 
|Date: November 15, 2004 |  |  |  | By: |  | /s/    NICK J. CARUSO
|                        |  |  |  |     |  |                       |  | Nick J. Caruso                                           
|                        |  |  |  |     |  |                       |  | Executive Vice President and Chief Financial Officer     
|                        |  |  |  |     |  |                       |  | (Duly Authorized Officer and Principal Financial Officer)



82