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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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



For the quarterly period ended June 30, 2005



| ̈ | 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)



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|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|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)



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



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, 285,039,770 shares outstanding as of August 4, 2005; Class B common stock,
no par value per share, 96,891,014 shares outstanding as of August 4, 2005.



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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:June 30, 2005 and December 31, 2004                                                  |  | 5   
|                              |  | Condensed Consolidated Statements of Operations:For the three and six months ended June 30, 2005 and 2004                  |  | 6   
|                              |  | Condensed Consolidated Statements of Cash Flows:For the six months ended June 30, 2005 and 2004                            |  | 7   
|                              |  | Condensed Consolidated Statements of Comprehensive Income (Loss):For the three and six months ended June 30, 2005 and 2004 |  | 8   
|                              |  | Notes to Condensed Consolidated Financial Statements                                                                       |  | 9   
|                              |  |                                                                                                                           
|                              |  | Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS                              |  | 45  
|                              |  | Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                                         |  | 77  
|                              |  | Item 4. CONTROLS AND PROCEDURES                                                                                            |  | 79  
|                              | 
|PART II. OTHER INFORMATION    |  |                                                                                                                           
|                              |  |                                                                                                                           
|                              |  | Item 1. LEGAL PROCEEDINGS                                                                                                  |  | 80  
|                              |  | Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS                                                                |  | 80  
|                              |  | Item 6. EXHIBITS                                                                                                           |  | 82  



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DEFINITIONS



As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below. Additionally, the terms
Dynegy, we, us and our refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.



|        |  |                                                                         
|------- |  | ------------------------------------------------------------------------
|ARB     |  | Accounting Research Bulletin                                            
|ARO     |  | Asset retirement obligation                                             
|Bcf/d   |  | Billion cubic feet 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 Chevron Corporation   
|DGC     |  | Dynegy Global Communications                                            
|DHI     |  | Dynegy Holdings Inc., our primary financing subsidiary                  
|DMG     |  | Dynegy Midwest Generation, Inc.                                         
|DMS     |  | Dynegy Midstream Services                                               
|DMSLP   |  | Dynegy Midstream Services, Limited Partnership                          
|DNE     |  | Dynegy Northeast Generation                                             
|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                                                     
|GAAP    |  | Generally Accepted Accounting Principles of the United States of America
|GCF     |  | Gulf Coast Fractionators                                                
|GEN     |  | Our power generation business segment                                   
|ICC     |  | Illinois Commerce Commission                                            
|ISO     |  | Independent System Operator                                             
|KWyr   |  | Kilowatt year                                                           
|KWh     |  | Kilowatt hour                                                           
|LNG     |  | Liquefied natural gas                                                   
|LPG     |  | Liquefied petroleum gas                                                 
|MBbls/d |  | Thousands of barrels per day                                            
|Mcf     |  | Thousand cubic feet                                                     
|MISO    |  | Midwest Independent Transmission System Operator, Inc.                  
|MMBtu   |  | Millions of British thermal units                                       
|MMCFD   |  | Million cubic feet per day                                              
|MW      |  | Megawatts                                                               
|MWh     |  | Megawatt hour                                                           
|NGL     |  | Our natural gas liquids business segment                                
|NNG     |  | Northern Natural Gas Company                                            
|NOL     |  | Net operating loss                                                      
|NOV     |  | Notice of Violation issued by the EPA                                   
|NYISO   |  | New York Independent System Operator                                    
|NYSDEC  |  | New York State Department of Environmental Conservation                 



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|      |  |                                               
|----- |  | ----------------------------------------------
|POL   |  | Percentage of liquids                         
|POP   |  | Percentage of proceeds                        
|PRB   |  | Powder River Basin coal                       
|REG   |  | Our regulated energy delivery business segment
|RMR   |  | Reliability Must Run                          
|RTO   |  | Regional Transmission Organization            
|SEC   |  | U.S. Securities and Exchange Commission       
|SFAS  |  | Statement of Financial Accounting Standards   
|SPDES |  | State Pollutant Discharge Elimination System  
|SPE   |  | Special Purpose Entity                        
|SPN   |  | Second Priority Notes                         
|VaR   |  | Value at Risk                                 
|VEBA  |  | Voluntary Employees Benefit Association      
|VIE   |  | Variable Interest Entity                      



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DYNEGY INC.



CONDENSED
CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)



|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ------------ | ------ | - | ---------------- | - | ------ | -
|                                                                                                                                                                                                                         |  | June 30,2005 |        |   | December 31,2004 |  
|ASSETS                                                                                                                                                                                                                   |  |              |        |   |                  |   |        |  
|Current Assets                                                                                                                                                                                                           |  |              |        |   |                  |   |        |  
|Cash and cash equivalents                                                                                                                                                                                                |  | $            | 342    |   |                  | $ | 628    |  
|Restricted cash                                                                                                                                                                                                          |  |              | 38     |   |                  |   |       |  
|Accounts receivable, net of allowance for doubtful accounts of $158 and $159, respectively                                                                                                                               |  |              | 595    |   |                  |   | 810    |  
|Accounts receivable, affiliates                                                                                                                                                                                          |  |              | 11     |   |                  |   | 14     |  
|Inventory                                                                                                                                                                                                                |  |              | 197    |   |                  |   | 233    |  
|Assets from risk-management activities                                                                                                                                                                                   |  |              | 640    |   |                  |   | 565    |  
|Deferred income taxes                                                                                                                                                                                                    |  |              | 496    |   |                  |   | 74     |  
|Prepayments and other current assets                                                                                                                                                                                     |  |              | 298    |   |                  |   | 428    |  
|Assets held for sale (Note 3)                                                                                                                                                                                            |  |              | 369    |   |                  |   |       |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Total Current Assets                                                                                                                                                                                                     |  |              | 2,986  |   |                  |   | 2,752  |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Property, Plant and Equipment                                                                                                                                                                                            |  |              | 6,459  |   |                  |   | 7,822  |  
|Accumulated depreciation                                                                                                                                                                                                 |  |              | (1,082 | ) |                  |   | (1,692 | )
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                                                                                                                                                       |  |              | 5,377  |   |                  |   | 6,130  |  
|Other Assets                                                                                                                                                                                                             |  |              |        |   |                  |   |        |  
|Unconsolidated investments                                                                                                                                                                                               |  |              | 290    |   |                  |   | 421    |  
|Restricted investments                                                                                                                                                                                                   |  |              | 84     |   |                  |   |       |  
|Intangible assets                                                                                                                                                                                                        |  |              | 416    |   |                  |   |       |  
|Assets from risk-management activities                                                                                                                                                                                   |  |              | 272    |   |                  |   | 313    |  
|Goodwill                                                                                                                                                                                                                 |  |              |       |   |                  |   | 15     |  
|Deferred income taxes                                                                                                                                                                                                    |  |              | 13     |   |                  |   | 12     |  
|Other long-term assets                                                                                                                                                                                                   |  |              | 172    |   |                  |   | 209    |  
|Assets held for sale (Note 3)                                                                                                                                                                                            |  |              | 1,159  |   |                  |   |       |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Total Assets                                                                                                                                                                                                             |  | $            | 10,769 |   |                  | $ | 9,852  |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                                                                     |  |              |        |   |                  |   |        |  
|Current Liabilities                                                                                                                                                                                                      |  |              |        |   |                  |   |        |  
|Accounts payable                                                                                                                                                                                                         |  | $            | 503    |   |                  | $ | 561    |  
|Accounts payable, affiliates                                                                                                                                                                                             |  |              | 17     |   |                  |   | 23     |  
|Accrued interest                                                                                                                                                                                                         |  |              | 146    |   |                  |   | 118    |  
|Accrued liabilities and other current liabilities                                                                                                                                                                        |  |              | 384    |   |                  |   | 450    |  
|Liabilities from risk-management activities                                                                                                                                                                              |  |              | 684    |   |                  |   | 616    |  
|Notes payable and current portion of long-term debt                                                                                                                                                                      |  |              | 55     |   |                  |   | 34     |  
|Liabilities held for sale (Note 3)                                                                                                                                                                                       |  |              | 139    |   |                  |   |       |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Total Current Liabilities                                                                                                                                                                                                |  |              | 1,928  |   |                  |   | 1,802  |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Long-term debt                                                                                                                                                                                                           |  |              | 4,864  |   |                  |   | 4,132  |  
|Long-term debt to affiliates                                                                                                                                                                                             |  |              | 200    |   |                  |   | 200    |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Long-Term Debt                                                                                                                                                                                                           |  |              | 5,064  |   |                  |   | 4,332  |  
|Other Liabilities                                                                                                                                                                                                        |  |              |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                                                                                                                                              |  |              | 313    |   |                  |   | 395    |  
|Deferred income taxes                                                                                                                                                                                                    |  |              | 885    |   |                  |   | 597    |  
|Other long-term liabilities                                                                                                                                                                                              |  |              | 416    |   |                  |   | 353    |  
|Liabilities held for sale (Note 3)                                                                                                                                                                                       |  |              | 25     |   |                  |   |       |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Total Liabilities                                                                                                                                                                                                        |  |              | 8,631  |   |                  |   | 7,479  |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Minority Interest                                                                                                                                                                                                        |  |              | 107    |   |                  |   | 106    |  
|Commitments and Contingencies (Note 10)                                                                                                                                                                                  |  |              |        |   |                  |   |        |  
|Redeemable Preferred Securities, redemption value of $400 at June 30, 2005 and December 31, 2004, respectively                                                                                                           |  |              | 400    |   |                  |   | 400    |  
|Stockholders Equity                                                                                                                                                                                                     |  |              |        |   |                  |   |        |  
|Class A Common Stock, no par value, 900,000,000 shares authorized at June 30, 2005 and December 31, 2004; 286,670,174 and 285,012,203 shares
issued and outstanding at June 30, 2005 and December 31, 2004, respectively |  |              | 2,864  |   |                  |   | 2,859  |  
|Class B Common Stock, no par value, 360,000,000 shares authorized at June 30, 2005 and December 31, 2004; 96,891,014 shares issued and
outstanding at June 30, 2005 and December 31, 2004                                |  |              | 1,006  |   |                  |   | 1,006  |  
|Additional paid-in capital                                                                                                                                                                                               |  |              | 45     |   |                  |   | 41     |  
|Subscriptions receivable                                                                                                                                                                                                 |  |              | (8     | ) |                  |   | (8     | )
|Accumulated other comprehensive loss, net of tax                                                                                                                                                                         |  |              | (23    | ) |                  |   | (13    | )
|Accumulated deficit                                                                                                                                                                                                      |  |              | (2,185 | ) |                  |   | (1,950 | )
|Treasury stock, at cost, 1,686,715 shares at June 30, 2005 and 1,679,183 shares at December 31, 2004                                                                                                                     |  |              | (68    | ) |                  |   | (68    | )
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Total Stockholders Equity                                                                                                                                                                                               |  |              | 1,631  |   |                  |   | 1,867  |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                                                                                                                                               |  | $            | 10,769 |   |                  | $ | 9,852  |  
|                                                                                                                                                                                                                         |  |              |        |   |                  |   |        |  



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 Months EndedJune 30, |       |   | Six Months EndedJune 30, |  
|                                                                                                                               |  | 2005                       |       |   | 2004                     |   |       | 2005 |  |   | 2004  |  
|Revenues                                                                                                                       |  | $                          | 459   |   |                          | $ | 689   |      |  | $ | 921   |   |  | $ | 1,456 |  
|Cost of sales, exclusive of depreciation shown separately below                                                                |  |                            | (380  | ) |                          |   | (423  | )    |  |   | (910  | ) |  |   | (989  | )
|Depreciation and amortization expense                                                                                          |  |                            | (54   | ) |                          |   | (57   | )    |  |   | (109  | ) |  |   | (125  | )
|Impairment and other charges                                                                                                   |  |                            | (7    | ) |                          |   | (59   | )    |  |   | (6    | ) |  |   | (75   | )
|Loss on sale of assets, net                                                                                                    |  |                            |      |   |                          |   |      |      |  |   |      |   |  |   | (15   | )
|General and administrative expenses                                                                                            |  |                            | (82   | ) |                          |   | (94   | )    |  |   | (345  | ) |  |   | (156  | )
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Operating income (loss)                                                                                                        |  |                            | (64   | ) |                          |   | 56    |      |  |   | (449  | ) |  |   | 96    |  
|Earnings from unconsolidated investments                                                                                       |  |                            | 4     |   |                          |   | 50    |      |  |   | 7     |   |  |   | 88    |  
|Interest expense                                                                                                               |  |                            | (96   | ) |                          |   | (141  | )    |  |   | (185  | ) |  |   | (271  | )
|Other income and expense, net                                                                                                  |  |                            | 6     |   |                          |   | (6    | )    |  |   | 9     |   |  |   | 7     |  
|Minority interest expense                                                                                                      |  |                            |      |   |                          |   | (3    | )    |  |   |      |   |  |   | (1    | )
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Loss from continuing operations before income taxes                                                                            |  |                            | (150  | ) |                          |   | (44   | )    |  |   | (618  | ) |  |   | (81   | )
|Income tax benefit (Note 13)                                                                                                   |  |                            | 41    |   |                          |   | 29    |      |  |   | 215   |   |  |   | 82    |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Income (loss) from continuing operations (Note 9)                                                                              |  |                            | (109  | ) |                          |   | (15   | )    |  |   | (403  | ) |  |   | 1     |  
|Income from discontinued operations, net of tax benefit (expense) of $111, $(48), $93 and $(78), respectively (Notes 3 and 13) |  |                            | 147   |   |                          |   | 23    |      |  |   | 179   |   |  |   | 77    |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Net income (loss)                                                                                                              |  |                            | 38    |   |                          |   | 8     |      |  |   | (224  | ) |  |   | 78    |  
|Less: preferred stock dividends                                                                                                |  |                            | 6     |   |                          |   | 6     |      |  |   | 11    |   |  |   | 11    |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Net income (loss) applicable to common stockholders                                                                            |  | $                          | 32    |   |                          | $ | 2     |      |  | $ | (235  | ) |  | $ | 67    |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Earnings (Loss) Per Share (Note 9):                                                                                            |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Basic earnings (loss) per share:                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Loss from continuing operations                                                                                                |  | $                          | (0.30 | ) |                          | $ | (0.06 | )    |  | $ | (1.09 | ) |  | $ | (0.03 | )
|Income from discontinued operations                                                                                            |  |                            | 0.38  |   |                          |   | 0.07  |      |  |   | 0.47  |   |  |   | 0.20  |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Basic earnings (loss) per share                                                                                                |  | $                          | 0.08  |   |                          | $ | 0.01  |      |  | $ | (0.62 | ) |  | $ | 0.17  |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Diluted earnings (loss) per share:                                                                                             |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Loss from continuing operations                                                                                                |  | $                          | (0.30 | ) |                          | $ | (0.06 | )    |  | $ | (1.09 | ) |  | $ | (0.03 | )
|Income from discontinued operations                                                                                            |  |                            | 0.38  |   |                          |   | 0.07  |      |  |   | 0.47  |   |  |   | 0.20  |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Diluted earnings (loss) per share                                                                                              |  | $                          | 0.08  |   |                          | $ | 0.01  |      |  | $ | (0.62 | ) |  | $ | 0.17  |  
|                                                                                                                               |  |                            |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Basic shares outstanding                                                                                                       |  |                            | 380   |   |                          |   | 378   |      |  |   | 379   |   |  |   | 377   |  
|Diluted shares outstanding                                                                                                     |  |                            | 506   |   |                          |   | 435   |      |  |   | 505   |   |  |   | 503   |  



See the notes to
condensed consolidated financial statements.



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##### Table of Contents

DYNEGY INC.



CONDENSED
CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



|                                                                                        |  |                          |      |   |      |   |      |  
|--------------------------------------------------------------------------------------- |  | ------------------------ | ---- | - | ---- | - | ---- | -
|                                                                                        |  | Six Months EndedJune 30, |     
|                                                                                        |  | 2005                     |      |   | 2004 |  
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                   |  |                          |      |   |      |   |      |  
|Net income (loss)                                                                       |  | $                        | (224 | ) |      | $ | 78   |  
|Adjustments to reconcile net income (loss) to net cash flows from operating activities: |  |                          |      |   |      |   |      |  
|Depreciation and amortization                                                           |  |                          | 151  |   |      |   | 196  |  
|Impairment and other charges                                                            |  |                          | (1   | ) |      |   | 80   |  
|Earnings from unconsolidated investments, net of cash distributions                     |  |                          | 47   |   |      |   | (19  | )
|Risk-management activities                                                              |  |                          | (1   | ) |      |   | (44  | )
|Gain on sale of assets, net                                                             |  |                          |     |   |      |   | (38  | )
|Deferred income taxes                                                                   |  |                          | (306 | ) |      |   | (4   | )
|Liability associated with gas transportation contracts (Note 3)                         |  |                          |     |   |      |   | (148 | )
|Legal and settlement charges                                                            |  |                          | 86   |   |      |   | 39   |  
|Independence toll settlement charge                                                     |  |                          | 170  |   |      |   |     |  
|Other                                                                                   |  |                          | 2    |   |      |   | (34  | )
|Changes in working capital:                                                             |  |                          |      |   |      |   |      |  
|Accounts receivable                                                                     |  |                          | (24  | ) |      |   | 84   |  
|Inventory                                                                               |  |                          | (9   | ) |      |   | 12   |  
|Prepayments and other assets                                                            |  |                          | 180  |   |      |   | (100 | )
|Accounts payable and accrued liabilities                                                |  |                          | (107 | ) |      |   | (49  | )
|Changes in non-current assets                                                           |  |                          | (4   | ) |      |   | (24  | )
|Changes in non-current liabilities                                                      |  |                          | 31   |   |      |   | 32   |  
|                                                                                        |  |                          |      |   |      |   |      |  
|Net cash provided by (used in) operating activities                                     |  |                          | (9   | ) |      |   | 61   |  
|                                                                                        |  |                          |      |   |      |   |      |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                   |  |                          |      |   |      |   |      |  
|Capital expenditures                                                                    |  |                          | (93  | ) |      |   | (151 | )
|Proceeds from asset sales, net                                                          |  |                          | (5   | ) |      |   | 81   |  
|Business acquisitions, net of cash acquired                                             |  |                          | (120 | ) |      |   |     |  
|                                                                                        |  |                          |      |   |      |   |      |  
|Net cash used in investing activities                                                   |  |                          | (218 | ) |      |   | (70  | )
|                                                                                        |  |                          |      |   |      |   |      |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                   |  |                          |      |   |      |   |      |  
|Net proceeds from long-term borrowings                                                  |  |                          |     |   |      |   | 581  |  
|Repayments of long-term borrowings                                                      |  |                          | (38  | ) |      |   | (193 | )
|Proceeds from issuance of capital stock                                                 |  |                          | 2    |   |      |   | 5    |  
|Dividends and other distributions, net                                                  |  |                          | (11  | ) |      |   | (11  | )
|Other financing, net                                                                    |  |                          | 4    |   |      |   | (12  | )
|                                                                                        |  |                          |      |   |      |   |      |  
|Net cash provided by (used in) financing activities                                     |  |                          | (43  | ) |      |   | 370  |  
|                                                                                        |  |                          |      |   |      |   |      |  
|Effect of exchange rate changes on cash                                                 |  |                          |     |   |      |   | (1   | )
|Net increase (decrease) in cash and cash equivalents                                    |  |                          | (270 | ) |      |   | 360  |  
|Cash and cash equivalents, beginning of period                                          |  |                          | 628  |   |      |   | 477  |  
|Less: Cash classified as held for sale at end of period (Note 3)                        |  |                          | (16  | ) |      |   | (42  | )
|                                                                                        |  |                          |      |   |      |   |      |  
|Cash and cash equivalents, end of period                                                |  | $                        | 342  |   |      | $ | 795  |  
|                                                                                        |  |                          |      |   |      |   |      |  



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 Months EndedJune 30, |     
|                                                                                                         |  | 2005                       |      |   | 2004 |  
|Net income                                                                                               |  | $                          | 38   |   |      | $ | 8   |  
|Cash flow hedging activities, net:                                                                       |  |                            |      |   |      |   |     |  
|Unrealized mark-to-market gains arising during period, net                                               |  |                            | (3   | ) |      |   | 5   |  
|Reclassification of mark-to-market losses (gains) to earnings, net                                       |  |                            | (1   | ) |      |   | 9   |  
|                                                                                                         |  |                            |      |   |      |   |     |  
|Changes in cash flow hedging activities, net (net of tax benefit (expense) of $3 and $(8), respectively) |  |                            | (4   | ) |      |   | 14  |  
|Foreign currency translation adjustments                                                                 |  |                            |     |   |      |   |    |  
|                                                                                                         |  |                            |      |   |      |   |     |  
|Other comprehensive income, net of tax                                                                   |  |                            | (4   | ) |      |   | 14  |  
|                                                                                                         |  |                            |      |   |      |   |     |  
|Comprehensive income                                                                                     |  | $                          | 34   |   |      | $ | 22  |  
|                                                                                                         |  |                            |      |   |      |   |     |  
|                                                                                                         | 
|                                                                                                         |  | Six Months EndedJune 30,   |     
|                                                                                                         |  | 2005                       |      |   | 2004 |  
|Net income (loss)                                                                                        |  | $                          | (224 | ) |      | $ | 78  |  
|Cash flow hedging activities, net:                                                                       |  |                            |      |   |      |   |     |  
|Unrealized mark-to-market losses arising during period, net                                              |  |                            | (21  | ) |      |   | (53 | )
|Reclassification of mark-to-market losses to earnings, net                                               |  |                            | 11   |   |      |   | 20  |  
|                                                                                                         |  |                            |      |   |      |   |     |  
|Changes in cash flow hedging activities, net (net of tax benefit of $7 and $20, respectively)            |  |                            | (10  | ) |      |   | (33 | )
|Foreign currency translation adjustments                                                                 |  |                            |     |   |      |   | (15 | )
|Minimum pension liability (net of tax expense of zero and $1, respectively)                              |  |                            |     |   |      |   | 2   |  
|                                                                                                         |  |                            |      |   |      |   |     |  
|Other comprehensive loss, net of tax                                                                     |  |                            | (10  | ) |      |   | (46 | )
|                                                                                                         |  |                            |      |   |      |   |     |  
|Comprehensive income (loss)                                                                              |  | $                          | (234 | ) |      | $ | 32  |  
|                                                                                                         |  |                            |      |   |      |   |     |  



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 June 30, 2005 and 2004



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 for the year ended December 31, 2004, which we refer to as our Form
10-K.



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 statement 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 judgments that affect our reported financial
position and results of operations. These estimates and judgments also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates and judgments affecting our consolidated financial statements
on a recurring basis and record the effect of any necessary adjustments prior to the publication of such financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments
made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and
judgments 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, guarantees and indemnifications and (6) estimating various factors used to value our pension assets and liabilities. Actual
results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.



Asset Retirement Obligations.At December 31, 2004, our ARO liabilities were $35 million for our GEN segment
and $11 million for our NGL segment. These retirement obligations related to activities such as ash pond and landfill capping, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations.
We continue to follow the provisions for disclosure and accounting for these AROs under SFAS No. 143, Asset Retirement Obligations. During the three and six months ended June 30, 2005 and 2004, no material additional AROs were recorded
or settled, and our accretion expenses and revisions to estimated cash flows were not material. At June 30, 2005, our ARO liabilities were $37 million for our GEN segment and $10 million for our NGL segment. The $10 million ARO liabilities
associated with our NGL segment have been reclassified to liabilities held for sale as a result of our anticipated sale of DMSLP. Please see Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued
OperationsNatural Gas Liquids for further discussion.



Employee Stock Options. 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



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



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 January 1, 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. 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.



Had compensation cost for all stock options granted prior to January 1, 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income (loss) and basic and diluted earnings (loss) per share amounts would have
approximated the following pro forma amounts for the three- and six-month periods ended June 30, 2005 and 2004, respectively.



|                                                                                                                                            |  |                                      |      |   |                          |   |       |      |  |   |       |   |  |   |      |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------ | ---- | - | ------------------------ | - | ----- | ---- |  | - | ----- | - |  | - | ---- | -
|                                                                                                                                            |  | Three Months EndedJune 30,           |      |   | Six Months EndedJune 30, |  
|                                                                                                                                            |  | 2005                                 |      |   | 2004                     |   |       | 2005 |  |   | 2004  |  
|                                                                                                                                            |  | (in millions, except per share data) |     
|Net income (loss) as reported                                                                                                               |  | $                                    | 38   |   |                          | $ | 8     |      |  | $ | (224  | ) |  | $ | 78   |  
|Add: Stock-based employee compensation expense included in reported net income (loss), net of related tax effects                           |  |                                      | 1    |   |                          |   | 1     |      |  |   | 2     |   |  |   | 2    |  
|Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax
effects |  |                                      | (1   | ) |                          |   | (7    | )    |  |   | (2    | ) |  |   | (16  | )
|                                                                                                                                            |  |                                      |      |   |                          |   |       |      |  |   |       |   |  |   |      |  
|Pro forma net income (loss)                                                                                                                 |  | $                                    | 38   |   |                          | $ | 2     |      |  | $ | (224  | ) |  | $ | 64   |  
|                                                                                                                                            |  |                                      |      |   |                          |   |       |      |  |   |       |   |  |   |      |  
|Earnings (loss) per share:                                                                                                                  |  |                                      |      |   |                          |   |       |      |  |   |       |   |  |   |      |  
|Basicas reported                                                                                                                           |  | $                                    | 0.08 |   |                          | $ | 0.01  |      |  | $ | (0.62 | ) |  | $ | 0.17 |  
|Basicpro forma                                                                                                                             |  | $                                    | 0.08 |   |                          | $ | (0.01 | )    |  | $ | (0.62 | ) |  | $ | 0.14 |  
|Dilutedas reported                                                                                                                         |  | $                                    | 0.08 |   |                          | $ | 0.01  |      |  | $ | (0.62 | ) |  | $ | 0.17 |  
|Dilutedpro forma                                                                                                                           |  | $                                    | 0.08 |   |                          | $ | (0.01 | )    |  | $ | (0.62 | ) |  | $ | 0.14 |  



Accounting
Principle Adopted



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 that 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



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



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 facilities ranges from 165 MW to 902 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 $273 million at June 30, 2005, and one of our affiliates has a loan outstanding to one of these entities, which totaled $20 million at June 30, 2005.



On January 31, 2005, we completed the acquisition of ExRes SHC, Inc., the
parent company of Sithe Energies, Inc., which we refer to as Sithe Energies, and Sithe/Independence Power Partners, L.P., which we refer to as Independence. ExRes SHC, Inc., which we refer to as ExRes, owns
through its subsidiaries four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. The entities owning these facilities meet the definition of VIEs. In accordance with the purchase
agreement, Exelon Corporation, which we refer to as Exelon, has the sole and exclusive right to direct our efforts to decommission, sell, bankrupt, or otherwise dispose of the hydroelectric facilities owned through the VIE entities.
Exelon is obligated to reimburse ExRes for all costs, liabilities, and obligations of the entities owning these hydroelectric generation facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities.
As a result, we are not the primary beneficiary of the entities, and have not consolidated them in accordance with the provisions of FIN No. 46R.



With regard to the four natural gas-fired merchant facilities located in New York, we had the option to elect to decommission any or all of these
facilities within a 180-day period after the January 31, 2005 closing date. Prior to expiration of the option period which ended on July 30, 2005, we elected to decommission all four of the natural gas-fired merchant facilities owned by ExRes. Under
the terms of the purchase agreement, Exelon will direct the decommissioning, sale, or other disposal of the facilities. Further, Exelon is obligated to indemnify us with respect to all operations prior to February 1, 2005, and subsequent to our
election to decommission or sell the facilities and must provide written consent for any payments or actions outside the ordinary course of operations. On June 8, 2005 and August 4, 2005, we entered into agreements, as directed by Exelon, to sell
our ownership and operating interests in the four natural gas-fired power generation peaking facilities to Alliance Energy Group LLC. The sale, subject to approval by the FERC and review by the New York Public Service Commission, is expected to
close by end of year 2005 and is expected to have no impact on our unaudited condensed consolidated financial statements, as Exelon will receive any proceeds from the sale. As a result of the rights retained by Exelon with respect to these
facilities, we are not the primary beneficiary of these VIEs, and have not consolidated them in accordance with the provisions of FIN No. 46R. Please see Note 2AcquisitionSithe Energies for further discussion regarding this acquisition.



The hydroelectric generation facilities have commitments and
obligations that are off-balance sheet with respect to Dynegy arising under operating leases for equipment and long-term power purchase agreements with local utilities. As of June 30, 2005, the equipment leases have remaining terms from two to
sixteen years and involve a maximum aggregate obligation of $131 million over the terms of the leases. Additionally, each of these facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these
agreements, a project tracking account, which we refer to as the Tracking Account, was established to quantify the difference between (i) the facilitys fixed price revenues under the power purchase agreement and (ii) the respective
utilitys Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance
in the Tracking Account before the end of the facilitys life through decreased



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



pricing under the respective power purchase agreement. Two of the four hydroelectric facilities are currently in the Tracking Account repayment period of the
contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs, exclusive of lease or interest costs. The remaining two facilities
are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of June 30, 2005, was approximately $287 million, and the obligations with respect to each Tracking Account are secured by the assets
of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts may cause the facilities to operate at a net cash deficit. As discussed above, the obligations of the four hydroelectric facilities are non-recourse to us.
Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of these facilities.



Accounting Principles Not Yet Adopted



SFAS No. 123(R). In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which revises SFAS No. 123. SFAS No.
123(R) is effective for January 1, 2006 for all calendar year-end companies. SFAS No. 123(R) requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. We expect to adopt the provisions of
SFAS No. 123(R) on January 1, 2006. SFAS No. 123(R) describes several transition methods, and we expect to apply the modified prospective method of adoption. Under this method, compensation expense will be recognized for the remaining portion of
outstanding, unvested awards at the date of adoption.



As noted
in Employee Stock Options above, we adopted the prospective method for expensing the fair value of stock options and restricted stock awards granted after January 1, 2003, and, as such we do not expect the guidance under SFAS No. 123(R)
to have a material impact on our consolidated statement of operations.



FIN No. 47. In March 2005, the FASB issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, which is an interpretation of SFAS No. 143. FIN No. 47 clarifies the term conditional
asset retirement obligation, which refers to legal obligations for which companies must perform asset retirement activity for which the timing and/or method of settlement are conditional upon future events that may or may not be within the
control of the entity. However, the obligation to perform the asset retirement is unconditional, despite the uncertainty that exists surrounding the timing and method of settlement. Uncertainty about the timing and method of settlement for a
conditional ARO should be considered in estimating the ARO when sufficient information exists. FIN No. 47 clarifies when sufficient information exists to reasonably estimate the fair value of an ARO. FIN No. 47 is effective no later than the end of
the first fiscal year ending after December 15, 2005, and early adoption is encouraged.



As noted in Asset Retirement Obligations above, we currently record AROs for our GEN and NGL segments. These AROs involve significant judgment regarding future cash flows and the ultimate timing of these
cash flows, some of which include the probability of future events occurring such as the timing and method of settlement. As such, we are in the process of evaluating the impact of FIN No. 47 and expect to adopt FIN No. 47 in the first quarter of
2006.



Note 2Acquisition



Sithe Energies. On January 31, 2005, we acquired 100% of the
outstanding common shares of ExRes, the parent company of Sithe Energies and Independence. The results of the operations of ExRes have been included in our consolidated financial statements since that date. Through this acquisition, we acquired the
1,021 MW Independence power generation facility located near Scriba, New York, as well as four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. We have not



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



consolidated the entities that own these four natural gas-fired facilities and four hydroelectric generation facilities, in accordance with the provisions of
FIN No. 46R. See Note 1Accounting PoliciesAccounting Principle AdoptedFIN No. 46R for additional discussion of these facilities. In addition to these power plants, we acquired the 750 MW firm capacity sales agreement between
Independence and Con Edison, a subsidiary of Consolidated Edison, Inc. This agreement, which runs through 2014, will provide us with annual cash receipts of approximately $100 million, subject to the restrictions on distribution under
Independences indebtedness. Independence holds power tolling, financial swap and other contracts with other Dynegy subsidiaries. As a result of the acquisition, these contracts have become intercompany agreements, and their financial statement
impact has been substantially eliminated. This transaction enabled us to address one of our outstanding power tolling arrangements and to expand our generation capacity in a market where we have an existing presence.



The aggregate purchase price was comprised of (i) $135 million cash, which
was reduced by a purchase price adjustment of approximately $2 million; (ii) transaction costs of approximately $16 million, approximately $3 million of which were paid in 2004 and (iii) the assumption of $919 million of face value project debt,
which was recorded at its fair value of $797 million as of January 31, 2005. Please read Note 7DebtIndependence Debt for additional information regarding the debt assumed.



The allocation of purchase price to specific assets and liabilities is based, in part, upon outside appraisals using
customary valuation procedures and techniques. The allocation is substantially complete at this time and we do not anticipate any material changes. We expect to finalize our allocation of the purchase price in 2005, once the final tax basis of the
assets and liabilities acquired has been determined. The acquisition resulted in an excess of the fair value of assets acquired over cost of the acquisition. This excess was then allocated to property plant and equipment and intangible assets
acquired, including intangibles arising from contracts with us, on a pro-rata basis.The following table summarizes the fair values of the assets and liabilities acquired at the date of acquisition, January 31, 2005 (in millions):



|                                       |  |   |        |  
|-------------------------------------- |  | - | ------ | -
|Other current assets                   |  | $ | 87     |  
|Restricted cash and investments        |  |   | 132    |  
|Property, plant and equipment          |  |   | 352    |  
|Assets from risk-management activities |  |   | 62     |  
|Intangible assets                      |  |   | 657    |  
|                                       |  |   |        |  
|Total assets acquired                  |  | $ | 1,290  |  
|                                       |  |   |        |  
|Current liabilities                    |  | $ | (96    | )
|Deferred income taxes                  |  |   | (189   | )
|Other long-term liabilities            |  |   | (59    | )
|Long-term debt                         |  |   | (797   | )
|                                       |  |   |        |  
|Total liabilities assumed              |  | $ | (1,141 | )
|                                       |  |   |        |  
|Net assets acquired                    |  | $ | 149    |  
|                                       |  |   |        |  



Included in the assets
acquired are restricted cash and investments of approximately $132 million. The restricted investments include Federal Home Loan Bank Bonds, U.S. Treasury Bonds, and high-grade short-term commercial paper. The restricted cash and investments are
related to a sinking fund required by Independences debt instruments, including a major overhaul reserve, a debt service reserve, a principal payment reserve, an interest reserve and a project restoration reserve. Restrictions on the cash and
investments are scheduled to be lifted at the end of the project financing term in 2014. For further discussion, please see Note 7DebtIndependence Debt.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Of the $657 million of acquired intangible assets, $487 million was allocated to the firm capacity
sales agreement with Con Edison. This asset will be amortized on a straight-line basis over the ten-year remaining life of the contract as a reduction to revenue in our unaudited condensed consolidated statements of operations, through October 2014.
In addition, Independence holds a power tolling contract, valued at $154 million, and a gas supply agreement, valued at $16 million, with another of our subsidiaries. Upon completion of our purchase of Independence, the power tolling agreement and
the gas supply agreement were effectively settled, which resulted in a 2005 charge equal to their fair values, in accordance with EITF Issue 04-01, Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase
Business Combination. As a result, we recorded a first quarter 2005 pre-tax charge of $183 million, which is included in cost of sales on our unaudited condensed consolidated statements of operations. In the second quarter 2005, we
substantially completed the determination of the tax basis of the assets and liabilities acquired, and revised our purchase price allocation, resulting in additional excess of the fair value of the assets acquired over the cost of the acquisition.
Accordingly, we reversed $13 million of the pre-tax charge recorded in the first quarter, resulting in a net pre-tax charge of $170 million in accordance with EITF Issue 04-01, as well as made additional revisions to our deferred income taxes ($80
million decrease to liability), intangible assets ($52 million decrease to asset), and property, plant and equipment balances ($28 million decrease to asset). Upon settlement of the power tolling and gas supply agreements, the firm capacity sales
agreement with Con Edison is the only remaining intangible asset associated with the acquisition of ExRes, which is included in intangibles and prepaids and other current assets on our unaudited condensed consolidated balance sheets.



We have exercised our right to require Exelon to decommission, sell, or
otherwise dispose of all four natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon will direct the disposition of these facilities, and will indemnify us with respect to all past and present
operations. On June 8, 2005 and August 4, 2005, we entered into agreements, as directed by Exelon, to sell our ownership and operating interests in the four natural gas-fired power generation peaking facilities in upstate New York to Alliance Energy
Group LLC, which includes our 80% interest in an 84 megawatt plant in Massena and our 85% interest in an 83 megawatt plant in Ogdensburg. The sale, subject to approval by the FERC and review by the New York Public Service Commission, is expected to
close by end of year 2005 and is expected to have no impact on our unaudited condensed consolidated financial statements, as Exelon will receive any proceeds from the sale. Further, Exelon is entitled to cause us to decommission, sell, or bankrupt
any or all of the four hydroelectric facilities owned by ExRes, for which we have been indemnified for any losses.



Note 3 Discontinued Operations, Dispositions and Contract Terminations



Discontinued Operations



Natural Gas Liquids. On August 2, 2005, we entered into an agreement to sell our ownership interests in DMSLP,
which comprises substantially all of the operations of our NGL segment, to Targa Resources, Inc. and two of its subsidiaries. We expect to receive $2.475 billion in cash proceeds from the sale, subject to purchase price adjustments, of which $2.35
billion will be paid by Targa at closing, and, based on current expectations, approximately $125 million, representing cash collateral, will be paid by Targa within 60 days of closing. In addition, we expect our responsibility for approximately $75
million in letters of credit to be eliminated at closing. The parties have made customary representations, warranties and covenants in the purchase agreement. The completion of the transaction is conditioned upon the expiration or termination of the
Hart-Scott-Rodino waiting period and the fulfillment of other closing conditions as set forth in the purchase agreement, including the lack of a material adverse effect and other conditions that are customary in transactions of this type. The
purchase agreement also contains customary termination rights, including termination rights by either party in the event the transaction has not been consummated by December 31, 2005. In certain circumstances (including



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



the failure by Targa to close the transaction when all conditions precedent to Targas obligation to close have been satisfied), the purchase agreement
provides for Targa to pay to Dynegy liquidated damages of $65 million upon termination of the purchase agreement. Pending satisfaction of the conditions in the purchase agreement, the sale is expected to close in the fourth quarter 2005. Please see
Note 7DebtNatural Gas Liquids for a discussion of our anticipated use of proceeds.



At June 1, 2005, NGL met the held for sale classification requirements of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, and is classified as such on our unaudited condensed
consolidated balance sheet. The major classes of current and long-term assets and liabilities classified as assets held for sale or liabilities held for sale at June 30, 2005 are as follows (in millions):



|                                                                  |  |   |      
|----------------------------------------------------------------- |  | - | -----
|Current Assets:                                                   |  |   |      
|Cash                                                              |  | $ | 16   
|Accounts receivable, net of allowance for doubtful accounts of $2 |  |   | 266  
|Inventory                                                         |  |   | 67   
|Other                                                             |  |   | 20   
|                                                                  |  |   |      
|Total Current Assets                                              |  | $ | 369  
|                                                                  |  |   |      
|Long-Term Assets:                                                 |  |   |      
|Property, plant and equipment, net                                |  | $ | 1,063
|Unconsolidated investments                                        |  |   | 78   
|Goodwill                                                          |  |   | 15   
|Other                                                             |  |   | 3    
|                                                                  |  |   |      
|Total Long-Term Assets                                            |  | $ | 1,159
|                                                                  |  |   |      
|Current Liabilities:                                              |  |   |      
|Accounts payable                                                  |  | $ | 65   
|Other                                                             |  |   | 74   
|                                                                  |  |   |      
|Total Current Liabilities                                         |  | $ | 139  
|                                                                  |  |   |      
|Long-Term Liabilities:                                            |  |   |      
|Other                                                             |  |   | 25   
|                                                                  |  |   |      
|Total Long-Term Liabilities                                       |  | $ | 25   
|                                                                  |  |   |      



Additionally, the $107
million in minority interest and $1 million of accumulated other comprehensive loss at June 30, 2005 relate to NGL and will not be included in our unaudited condensed consolidated balance sheets subsequent to the sale. As a result of the anticipated
sale of DMSLP, our expected realization of certain deferred tax assets has been accelerated. For further discussion, please read Note 13Income TaxesBalance Sheet Classification.



SFAS No. 144 also 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 NGLs property, plant and equipment, effective June 1, 2005. Depreciation and amortization expense related to NGL totaled $15
million and $35 million in the three- and six-month periods ended June 30, 2005, compared to $25 million and $45 million in the three- and six-month periods ended June 30, 2004.



In addition, SFAS No. 144 requires a loss to be recognized if assets held for sale less liabilities held for sale are in
excess of fair value less costs to sell. Because the fair value less costs to sell is greater than assets held for



15



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



sale less liabilities held for sale, we did not recognize a loss in the second quarter 2005. However, as a result of the anticipated sale of DMSLP, we
reduced our deferred tax valuation allowance. For further discussion, please read Note 13Income TaxesCapital Loss Valuation Allowance. We expect to record a pre-tax gain of approximately $1.1 billion ($700 million after-tax) upon closing
of the transaction.



Pursuant to SFAS No. 144, we are reporting
the results of NGLs operations as a discontinued operation. Accordingly, the results of operations of our NGL segment have been included in discontinued operations for all periods presented. EITF Issue 87-24, Allocation of Interest to
Discontinued Operations, requires that interest expense on debt that is required to be repaid upon the sale of DMSLP should be reclassified to discontinued operations. Therefore, interest expense on our $594 million term loan scheduled to
mature in 2010 and our $189 million generation facility debt scheduled to mature in 2007 has been allocated to discontinued operations, as the respective debt instruments are required to be paid upon the sale of DMSLP. Such interest expense totaled
$14 million and $4 million for the three months ended June 30, 2005 and 2004, respectively, and $25 million and $6 million for the six months ended June 30, 2005 and 2004, respectively. For further information, please see Note
7DebtNatural Gas Liquids.



Additionally, results
from NGLs operations include revenues and cost of sales arising from intersegment transactions, which will cease after the sale of DMSLP. NGL processes natural gas and sells this natural gas to CRM for resale to third parties. NGL also
purchases natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGLs results were reclassified to discontinued operations, the effects of these intersegment transactions eliminated in
consolidation, including the ultimate third party settlement, previously recorded in other segments, have also been reclassified to discontinued operations.



Other. We sold or liquidated some of our operations during 2003, including 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 all of our discontinued operations, including the NGL operations discussed above:



|                                          |  |               |     |   |     |   |     |  |       |       |  |   |      
|----------------------------------------- |  | ------------- | --- | - | --- | - | --- |  | ----- | ----- |  | - | -----
|                                          |  | U.K.CRM       |     |   | DGC |   | NGL |  | Total
|                                          |  | (in millions)
|Three Months Ended June 30, 2005          |  |               |     |   |     |   |     |  |       |       |  |   |      
|Revenue                                   |  | $             |    |   |     | $ |    |  | $     | 933   |  | $ | 933  
|Income from operations before taxes       |  |               | 1   |   |     |   |    |  |       | 35    |  |   | 36   
|Income from operations after taxes        |  |               |    |   |     |   | 2   |  |       | 145   |  |   | 147  
|                                          |  |               |     |  
|Three Months Ended June 30, 2004          |  |               |     |   |     |   |     |  |       |       |  |   |      
|Revenue                                   |  | $             |    |   |     | $ |    |  | $     | 766   |  | $ | 766  
|Income from operations before taxes       |  |               | 1   |   |     |   |    |  |       | 70    |  |   | 71   
|Income (loss) from operations after taxes |  |               | (19 | ) |     |   |    |  |       | 42    |  |   | 23   
|                                          |  |               |     |  
|Six Months Ended June 30, 2005            |  |               |     |   |     |   |     |  |       |       |  |   |      
|Revenue                                   |  | $             |    |   |     | $ |    |  | $     | 1,979 |  | $ | 1,979
|Income from operations before taxes       |  |               | 5   |   |     |   |    |  |       | 81    |  |   | 86   
|Income from operations after taxes        |  |               | 5   |   |     |   |    |  |       | 174   |  |   | 179  
|                                          |  |               |     |  
|Six Months Ended June 30, 2004            |  |               |     |   |     |   |     |  |       |       |  |   |      
|Revenue                                   |  | $             |    |   |     | $ |    |  | $     | 1,667 |  | $ | 1,667
|Income from operations before taxes       |  |               | 18  |   |     |   | 3   |  |       | 134   |  |   | 155  
|Income (loss) from operations after taxes |  |               | (7  | ) |     |   | 2   |  |       | 82    |  |   | 77   



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



In the six months ending June 30, 2005, we recognized $5 million of pre-tax income primarily
associated with U.K. CRMs receipt from a third party bankruptcy settlement.



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 5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 in U.K. CRM related to charges resulting from the conclusion of prior year tax audits. Please see Note 13Income TaxesPrior Year Tax Audits for
further discussion.



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, as well as our 20% interest in the Joppa power generation facility, to Ameren Corporation 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. At June 30, 2005 and December 31, 2004, we reflected the balance held in escrow in prepayments and other current assets on our unaudited condensed consolidated balance sheets. Under the escrow agreement, which we filed as an exhibit to our
third quarter 2004 Form 10-Q, the $100 million deposited by Ameren was to be released to us upon the occurrence of specified events relating to contingent environmental liabilities associated with Illinois Powers former generating facilities
(currently owned by DMG). The Baldwin consent decree, which was approved and entered by the Illinois federal district court on May 27, 2005, satisfied the condition for the release of the $100 million in escrowed funds. We received the funds on July
27, 2005. Please read Note 10Commitments and ContingenciesBaldwin Station Litigation for further discussion of this consent decree. During the time that these funds remained in escrow, the escrow fund earned interest on a quarterly
basis.



During the first quarter 2005, we paid approximately $5
million to Ameren for a final working capital purchase price adjustment. As a result of an adjustment to the contingent liabilities identified as part of the Illinois Power sale, we recorded a $12 million charge in the second quarter of 2005. On
July 27, 2005, we paid $8 million in partial satisfaction of such contingent liabilities. For further discussion, please see Note 10Commitments and ContingenciesGuarantees and Indemnification. The adjustment to the contingent liabilities
resulted in an increase to our capital loss carryforward, and a corresponding increase to the deferred tax valuation allowance of $4 million.



Further, on September 30, 2004, we entered into a two-year power purchase agreement with Illinois Power, now known as AmerenIP. Under the terms of this
agreement, which became effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48 per KW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. We also agreed to sell 300
MW of capacity in 2005 and 150 MW of capacity in 2006 to Illinois Power at a fixed price of $16 per KW-yr with an option to purchase energy at market-based prices.



During 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 on September 30, 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 $10 million in the six-month period ended June 30,
2004. In addition, SFAS No. 144 requires a loss to be recognized in the amount by which assets held for sale less liabilities held for sale are in excess of fair value less



17



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



costs to sell. Accordingly, for the three- and six-month periods ended June 30, 2004, we recorded pre-tax losses on the sale of $48 million and $69 million,
respectively. The first quarter charge, which was primarily associated with the expected transaction costs and an impairment of assets, is reflected in loss on sale of assets, net, and impairment and other charges on the unaudited condensed
consolidated statements of operations. The second quarter charge, an impairment of assets, is reflected in impairments and other charges 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 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 beginning in January 2005. Consequently, because we still have significant continuing
involvement with Illinois Power, we will continue to include the historical results of Illinois Powers operations as part of our continuing operations. Additionally, power sales to Illinois Power occurring subsequent to the disposition will be
reported in our consolidated statements of operations as third party sales. Approximately $108 million and $183 million of revenues, derived from power sales to Illinois Power occurring subsequent to the disposition, are reflected in our continuing
operations for the three- and six-month periods ending June 30, 2005.



Had the results of Illinois Power been excluded from our comparative results as though the sale had occurred on January 1, 2004, our revenues, 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 six-month periods ended June 30, 2004:



|                                                                 |  |                                      |      |                 |   |      
|---------------------------------------------------------------- |  | ------------------------------------ | ---- | --------------- | - | -----
|                                                                 |  | Three MonthsEnded                    |      | Six MonthsEnded
|                                                                 |  | June 30, 2004                       
|                                                                 |  | (in millions, except per share data)
|Revenues:                                                        |  |                                      |      |                 |   |      
|As reported                                                      |  | $                                    | 689  |                 | $ | 1,456
|Pro forma                                                        |  |                                      | 480  |                 |   | 925  
|                                                                 |  |                                     
|Net income applicable to common stockholders:                    |  |                                      |      |                 |   |      
|As reported                                                      |  |                                      | 2    |                 |   | 67   
|Pro forma                                                        |  |                                      | 15   |                 |   | 72   
|                                                                 |  |                                     
|Earnings per shareNet income applicable to common stockholders: |  |                                      |      |                 |   |      
|Basicas reported                                                |  | $                                    | 0.01 |                 | $ | 0.17 
|Basicpro forma                                                  |  | $                                    | 0.04 |                 | $ | 0.19 
|Dilutedas reported                                              |  | $                                    | 0.01 |                 | $ | 0.17 
|Dilutedpro forma                                                |  | $                                    | 0.04 |                 | $ | 0.19 



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



18



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



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 included rights to 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 income from
discontinued operations 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 income from discontinued operations 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 loss on sale of assets, net, on our unaudited condensed consolidated statements of operations.



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, $16 million in December 2004 and $26 million in March 2005. This payment obligation was recorded at its fair value of $40 million and was accreted to $42 million over the period July 1, 2004 through March 31, 2005. Additionally, we
reversed an aggregate liability of $148 million associated with the transportation contracts that was originally established in 2001 and recognized a pre-tax gain of $88 million related to these transactions. This gain is included in revenues on our
unaudited condensed consolidated statements of operations and is included in the results of our CRM segment. This agreement eliminated our obligation to make approximately $295 million in aggregate fixed capacity payments from April 2005 through
2014.



Note 4Restructuring Charges



In the three and six months ended June 30, 2004, we recorded pre-tax charges
relating to our interest in Illinois Power totaling $48 million and $69 million, respectively. For further discussion, please read Note 3Discontinued Operations, Dispositions and Contract TerminationsDispositions and Contract
TerminationsSale of Illinois Power. In addition, in the three months ended June 30, 2004, we recorded a $5 million pre-tax charge related to the impairment 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 2005 activity for the liabilities recorded in connection with this restructuring:



|                              |  |               |   |                                     |   |    |       |  |   |    |  
|----------------------------- |  | ------------- | - | ----------------------------------- | - | -- | ----- |  | - | -- | -
|                              |  | Severance     |   | CancellationFees andOperatingLeases |   |    | Total | 
|                              |  | (in millions) |  
|Balance at December 31, 2004  |  | $             | 3 |                                     | $ | 25 |       |  | $ | 28 |  
|2005 adjustments to liability |  |               |  |                                     |   | (1 | )     |  |   | (1 | )
|Cash payments                 |  |               |  |                                     |   | (5 | )     |  |   | (5 | )
|                              |  |               |   |                                     |   |    |       |  |   |    |  
|Balance at June 30, 2005      |  | $             | 3 |                                     | $ | 19 |       |  | $ | 22 |  
|                              |  |               |   |                                     |   |    |       |  |   |    |  



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



We expect the $19 million accrual as of June 30, 2005 associated with cancellation fees and operating
leases to be paid by the end of 2007 when the leases expire.



Note
5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-33 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 and NGL
businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin.



During the three and six months ended June 30, 2005, we recorded a $2 million and $6 million charge, respectively, 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 six months ended June 30, 2004, there was no material ineffectiveness from
changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three and six months ended June 30, 2005 and 2004, no amounts were reclassified to
earnings in connection with forecasted transactions that were no longer considered probable of occurring.



The balance in cash flow hedging activities, net at June 30, 2005 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 $22 million are currently estimated to be reclassified into earnings over
the 12-month period ending June 30, 2006. 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 floating-rate debt. During the three and six months ended June 30, 2005 and 2004, 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 six months ended June 30, 2005 and 2004, no amounts were recognized in relation to firm commitments that
no longer qualified as fair value hedges.



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 June 30, 2005, we had no net investment hedges in place.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Accumulated Other Comprehensive Loss.Accumulated other comprehensive loss, net of tax,
is included in stockholders equity on our unaudited condensed consolidated balance sheets as follows:



|                                                 |  |               |     |   |                  |   |     |  
|------------------------------------------------ |  | ------------- | --- | - | ---------------- | - | --- | -
|                                                 |  | June 30,2005  |     |   | December 31,2004 |  
|                                                 |  | (in millions) |    
|Cash flow hedging activities, net                |  | $             | (26 | ) |                  | $ | (16 | )
|Foreign currency translation adjustment          |  |               | 16  |   |                  |   | 16  |  
|Minimum pension liability                        |  |               | (13 | ) |                  |   | (13 | )
|                                                 |  |               |     |   |                  |   |     |  
|Accumulated other comprehensive loss, net of tax |  | $             | (23 | ) |                  | $ | (13 | )
|                                                 |  |               |     |   |                  |   |     |  



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 had accumulated in
stockholders equity.



Note 6Unconsolidated Investments



A summary of our unconsolidated investments is as
follows:



|                                                                |  |               |     |   |                  |   |    
|--------------------------------------------------------------- |  | ------------- | --- | - | ---------------- | - | ---
|                                                                |  | June 30,2005  |     |   | December 31,2004
|                                                                |  | (in millions)
|Equity affiliates:                                              |  |               |     |   |                  |   |    
|GEN investments                                                 |  | $             | 290 |   |                  | $ | 337
|NGL investments                                                 |  |               | 78  |   |                  |   | 78 
|                                                                |  |               |     |   |                  |   |    
|Total equity affiliates                                         |  |               | 368 |   |                  |   | 415
|Other affiliates, at cost                                       |  |               |    |   |                  |   | 6  
|                                                                |  |               |     |   |                  |   |    
|                                                                |  |               | 368 |   |                  |   | 421
|Less: Unconsolidated investments held for sale at end of period |  |               | (78 | ) |                  |   |   
|                                                                |  |               |     |   |                  |   |    
|Total unconsolidated investments                                |  | $             | 290 |   |                  | $ | 421
|                                                                |  |               |     |   |                  |   |    



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



|                 |  |                           |     |              |   |       |  |              |     |  |   |    
|---------------- |  | ------------------------- | --- | ------------ | - | ----- |  | ------------ | --- |  | - | ---
|                 |  | Six Months Ended June 30,
|                 |  | 2005                      |     | 2004        
|                 |  | Total                     |     | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)            
|Revenues         |  | $                         | 158 |              | $ | 79    |  | $            | 352 |  | $ | 176
|Operating income |  |                           | 1   |              |   | 1     |  |              | 163 |  |   | 82 
|Net income       |  |                           | 4   |              |   | 2     |  |              | 164 |  |   | 82 



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



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



|                 |  |                           |     |              |   |       |  |              |     |  |   |    
|---------------- |  | ------------------------- | --- | ------------ | - | ----- |  | ------------ | --- |  | - | ---
|                 |  | Six Months Ended June 30,
|                 |  | 2005                      |     | 2004        
|                 |  | Total                     |     | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)            
|Revenues         |  | $                         | 190 |              | $ | 63    |  | $            | 428 |  | $ | 161
|Operating income |  |                           | 27  |              |   | 10    |  |              | 72  |  |   | 30 
|Net income       |  |                           | 25  |              |   | 9     |  |              | 50  |  |   | 22 



Earnings from
unconsolidated investments of $7 million for the six months ended June 30, 2005, include the $9 million above and $2 million from West Coast Power offset by $4 million of earnings from NGL investments which are included in income from discontinued
operations. Earnings from unconsolidated investments of $88 million for the six months ended June 30, 2004, include the $22 million above and $82 million from West Coast Power, offset by $4 million of earnings from NGL investments which are included
in income from discontinued operations, an $8 million impairment of our Michigan Power equity investment discussed below and $4 million of amortization of the difference between the cost of our unconsolidated investments and our underlying equity in
their net assets.



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. In the three- and six-month periods ended June 30, 2004, we
recorded impairments on our investment in Michigan Power totaling $1 million and $8 million, respectively, to adjust our book value to the selling price.



Note 7Debt



Revolving Credit Facility. During the three- and six-month periods ended June 30, 2005, we increased letters of credit under our $700
million revolving credit facility by $190 million and $199 million, respectively, in the aggregate, resulting in a total of $293 million outstanding at June 30, 2005. As of June 30, 2005, there were no borrowings outstanding under this facility.
During the period from June 30, 2005 through August 4, 2005, we increased our outstanding letters of credit under this facility by $29 million.



Natural Gas Liquids. As further discussed in Note 3Discontinued Operations, Dispositions and Contract
TerminationsDiscontinued OperationsNatural Gas Liquids, we have entered into an agreement to sell DMSLP. The terms of our credit facility and the SPN indenture and security agreements govern how we may use the proceeds from this sale.
The credit facility requires repayment and termination upon the sale of DMSLP. We anticipate either (i) amending the current facility or (ii) replacing the current facility with a new cash collateralized credit facility concurrently with the closing
of the sale.



Upon repayment of the credit facility ($594
million scheduled to mature in 2010), we must also repay the generation facility ($189 million scheduled to mature in 2007). We can elect to use the balance of the proceeds to (i) repay parity lien debt, provided that any offer to repay parity lien
debt holders is made on a pro rata basis or (ii) make a capital expenditure or invest in various type of assets defined as Replacement Assets in the agreements.



22



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Any net proceeds from a sale of DMSLP that are not applied or invested in the manner described above
will constitute Excess Proceeds. If the Excess Proceeds exceed $50 million, we must make an Asset Sale Offer to holders of our SPNs within 365 days from closing of the sale. The offer price in the Asset Sale Offer shall be equal to 100% of the
principal amount plus accrued and unpaid interest. If the SPN holders decline pro rata repayment at par, then the balance of the proceeds can be used for any other purposes not otherwise restricted by the SPN indenture.



Repayments. In the first half of 2005, we paid the outstanding
$18 million balance on our 8.125% senior notes, which matured in March 2005. We also made payments of $17 million related to the Independence Senior Notes due 2007 and $3 million related to the DHI May 2004 term loan.



Independence Debt. On January 31, 2005, we completed the
acquisition of ExRes, the parent company of Sithe Energies and Independence. Upon the closing, we consolidated $919 million in face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005, for which certain of
the entities acquired are obligated. Please see Note 2AcquisitionSithe Energies for further discussion of this transaction.



Long-term debt consolidated upon completion of the Sithe Energies acquisition consisted of the following as of January 31, 2005:



|                                 |  |               |     |                     |   |      |           |  |   |    
|-------------------------------- |  | ------------- | --- | ------------------- | - | ---- | --------- |  | - | ---
|                                 |  | FaceValue     |     | Premium /(Discount) |   |      | FairValue
|                                 |  | (in millions)
|Subordinated Debt, 7.0% due 2034 |  | $             | 419 |                     | $ | (167 | )         |  | $ | 252
|Senior Notes, 8.5% due 2007      |  |               | 91  |                     |   | 3    |           |  |   | 94 
|Senior Notes, 9.0% due 2013      |  |               | 409 |                     |   | 42   |           |  |   | 451
|                                 |  |               |     |                     |   |      |           |  |   |    
|Total Independence Debt          |  | $             | 919 |                     | $ | (122 | )         |  | $ | 797
|                                 |  |               |     |                     |   |      |           |  |   |    



Principal payments on
the Independence senior notes, which we refer to as the senior debt, are due semiannually through 2013 and principal payments on the subordinated debt begin in 2015. Annual maturities of the Independence debt are as follows: 2005 - $17
million; 2006 - $37 million; 2007 - $40 million; 2008 - $44 million; 2009 - $57 million; and thereafter - $707 million. The senior debt and subordinated debt are secured by substantially all of the assets of Independence, but are not guaranteed by
us or DHI.



The terms of the indenture governing the senior
debt, among other things, prohibit cash distributions by Independence to its affiliates, including Dynegy, unless certain project reserve accounts are funded to specified levels and the required debt service coverage ratio is met. The indenture also
includes other covenants and restrictions, relating to, among other things, prohibitions on asset dispositions and fundamental changes, reporting requirements and maintenance of insurance. As of June 30, 2005, Independence had current restricted
cash of $38 million as reflected on our unaudited condensed consolidated balance sheets. As of June 30, 2005, Independence had short-term and long-term restricted investment balances of $2 million and $84 million, respectively. The restricted
investment balances are included in prepayments and other current assets and restricted investments, respectively, on our unaudited condensed consolidated balance sheets.



Note 8Related Party Transactions



We engage in transactions with Chevron Corporation, which we refer to as Chevron, and its affiliates, including purchases and sales of natural
gas and natural gas liquids, which we believe are executed on terms that



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



are fair and reasonable. Please see Note 12Related Party TransactionsTransactions with ChevronTexaco beginning on page F-47 of our Form 10-K for
further discussion.



Series C Convertible Preferred
Stock. As discussed in Note 14Redeemable Preferred StockSeries C Convertible Preferred Stock beginning on page F-54 of our Form 10-K, in August 2003, we issued to CUSA 8 million shares of our Series C convertible preferred stock
due 2033, which we refer to as our Series C preferred stock. We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. We made a semi-annual dividend payment of $11 million in February 2005. In July 2005, we
declared a dividend of $11 million to be paid on or before August 11, 2005.



Note 9Earnings (Loss) Per Share



Basic
earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) 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 dilutive potential common shares outstanding during the period.



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



|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|------------------------------------------------------------------- |  | --------------------------------------- | ----- | - | ------------------------ | - | ----- | ---- |  | - | ----- | - |  | - | ----- | -
|                                                                    |  | Three Months EndedJune 30,              |       |   | Six Months EndedJune 30, |  
|                                                                    |  | 2005                                    |       |   | 2004                     |   |       | 2005 |  |   | 2004  |  
|                                                                    |  | (in millions, except per share amounts) |      
|Income (loss) from continuing operations                            |  | $                                       | (109  | ) |                          | $ | (15   | )    |  | $ | (403  | ) |  | $ | 1     |  
|Preferred stock dividends                                           |  |                                         | (6    | ) |                          |   | (6    | )    |  |   | (11   | ) |  |   | (11   | )
|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Loss from continuing operations for basic loss per share            |  |                                         | (115  | ) |                          |   | (21   | )    |  |   | (414  | ) |  |   | (10   | )
|Effect of dilutive securities:                                      |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Interest on convertible subordinated debentures                     |  |                                         | 2     |   |                          |   | 2     |      |  |   | 3     |   |  |   | 3     |  
|Dividends on Series C preferred stock (2)                           |  |                                         | 6     |   |                          |   |      |      |  |   | 11    |   |  |   | 11    |  
|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Income (loss) from continuing operations for diluted loss per share |  | $                                       | (107  | ) |                          | $ | (19   | )    |  | $ | (400  | ) |  | $ | 4     |  
|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Basic weighted-average shares                                       |  |                                         | 380   |   |                          |   | 378   |      |  |   | 379   |   |  |   | 377   |  
|Effect of dilutive securities:                                      |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Stock options                                                       |  |                                         | 2     |   |                          |   | 2     |      |  |   | 2     |   |  |   | 2     |  
|Convertible subordinated debentures                                 |  |                                         | 55    |   |                          |   | 55    |      |  |   | 55    |   |  |   | 55    |  
|Series C preferred stock (2)                                        |  |                                         | 69    |   |                          |   |      |      |  |   | 69    |   |  |   | 69    |  
|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Diluted weighted-average shares                                     |  |                                         | 506   |   |                          |   | 435   |      |  |   | 505   |   |  |   | 503   |  
|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Loss per share from continuing operations:                          |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Basic                                                               |  | $                                       | (0.30 | ) |                          | $ | (0.06 | )    |  | $ | (1.09 | ) |  | $ | (0.03 | )
|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  
|Diluted (1)                                                         |  | $                                       | (0.30 | ) |                          | $ | (0.06 | )    |  | $ | (1.09 | ) |  | $ | (0.03 | )
|                                                                    |  |                                         |       |   |                          |   |       |      |  |   |       |   |  |   |       |  

---

|(1) | When an entity has a net loss from continuing operations, SFAS No. 128, Earnings per Share, prohibits the inclusion of potential common shares in the
computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding and the loss from continuing operations for basic loss per share
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



| | amount to calculate both basic and diluted loss per share for the three and six months ended June 30, 2005 and 2004.
| | --------------------------------------------------------------------------------------------------------------------

|(2) | The diluted shares for the three months ended June 30, 2004 do not include the effect of the preferential conversion to Class B common stock of the Series C convertible preferred
stock held by a Chevron subsidiary, as such inclusion would have been anti-dilutive when the calculation was performed in 2004.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Note 10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, Accounting for Contingencies. For environmental matters, we record liabilities when remedial efforts are probable and the
costs can be reasonably estimated. Please see Note 2Accounting PoliciesContingencies, Commitments, Guarantees and Indemnifications beginning on page F-16 of our Form 10-K for further discussion of our reserve policies. Environmental
reserves do not reflect managements assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the amount of any
reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.



With respect to some of the items listed below, management has determined
that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. In some cases, management is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding
these facts, management has assessed these matters based on current information and made a judgment concerning their potential outcome, giving due consideration to 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 Form 10-K:



| |  |  | On May 27, 2005, the U.S. district court entered and approved the consent decree associated with our Baldwin Station litigation. The requisite appeal period expired on July 26,
2005, with no appeals being filed. The decree settles all claims in the litigation, as well as similar claims that might have been brought related to maintenance, repair and replacement activities at other DMG plants including Vermilion, Wood River,
Hennepin and Havana.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In July 2005, the U.S. district court approved the comprehensive settlement agreement of the parties in our shareholder class action litigation. As part of the settlement, we agreed
to make an aggregate settlement payment of $468 million (consisting of $150 million funded by insurance proceeds, two cash payments by DHI totaling $250 million, and the issuance of 17,578,781 shares of Class A common stock) and cause the
resignation and replacement of two members of the Dynegy board of directors who are defendants in the litigation with two new directors from a list of candidates proposed by the lead plaintiff.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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DYNEGY INC.

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(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



| |  |  | Also in July 2005, the state district court approved our settlement of the shareholder derivative litigation. Under this settlement, we agreed to pay approximately $5 million in
attorneys fees and expenses and to effect certain corporate governance changes, many of which were previously implemented since the initiation of the litigation.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The above summary of recent developments is qualified in its entirety by, and
should be read in conjunction with, the more detailed summary of our significant legal proceedings set forth below.



Shareholder Litigation. In April 2005, we settled 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 as filed principally alleged 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 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 were lead plaintiff and Lerach Coughlin Stoia
& Robbins, LLP was class counsel. Reserves were provided in connection with this litigation.



In October 2004, in response to our June 2004 motions to dismiss, the judge entered an order dismissing all of plaintiffs claims under (i) the
Securities Act of 1933, except those relating to Dynegys March 2001 note offering and December 2001 common stock offering, and (ii) the Securities Exchange Act of 1934, except those dealing with Project Alpha and two alleged round-trip trades.
Further, the judge scheduled the trial to commence in May 2005. Also in October 2004, the plaintiff voluntarily dismissed its claim under the Securities Act relating to our March 2001 note offering. The parties filed motions on the class
certification issue in the fourth quarter 2004. In December 2004, the court issued an order identifying the class period for the Exchange Act claims as June 21, 2001 through July 22, 2002, and the class for the Securities Act claims includes persons
who purchased our stock, provided that the purchase is traceable to the December 20, 2001 offering of Class A common stock.



In July 2005, the court approved the comprehensive settlement agreement reached by the parties to the class action litigation in April 2005, which
provided for the following:



| |  |  | An aggregate settlement payment by Dynegy of $468 million, comprised of a $150 million cash payment funded by insurance proceeds, a $250 million cash payment by DHI, and the
issuance to the plaintiffs of $68 million in Dynegys Class A common stock, consisting of 17,578,781 shares based on a calculation using a volume weighted average stock price for the 20 trading days ending April 15, 2005. We were required to
make two payments totaling $250 million during 2005, consisting of an initial payment of $175 million, which we paid in May 2005, followed by a second payment of $75 million plus interest upon court approval, which we paid in July 2005. As required
by the settlement, we intend to issue the shares of Class A common stock promptly following expiration of the appeal period which occurred on August 8, 2005.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | The resignation of two members of the Dynegy board of directors who are defendants in the litigation, with the vacancies resulting from such resignations to be filled by two new
directors from a list of at least five qualified candidates submitted by the lead plaintiff. We will also nominate such directors for election at our next meeting of shareholders at which directors are elected.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition, we were named as 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



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



similar to those described above. These lawsuits were consolidated into two groupsone pending in federal court and the other pending in Texas state
court. In February 2005, the plaintiffs voluntarily dismissed the federal derivative matter. In April 2005, the parties to the shareholder derivative litigation pending in Texas state court reached a settlement,and the court approved the
settlement agreement in July 2005. Under this settlement agreement, Dynegy agreed to effect certain corporate governance changes, many of which were implemented since the claim was originally filed, and to pay related attorney fees and expenses
incurred by the plaintiffs in the aggregate amount of approximately $5 million. The ongoing corporate changes relate to director qualifications, the involvement of a lead independent director, the structure and function of certain Board committees
and other governance enhancements.



Dynegy and the other
defendants did not admit any liability in connection with either of the settlements described above, and there were no findings of any violations of the federal securities laws. We recorded pre-tax charges of $18 million ($12 million after-tax) and
$240 million ($168 million after-tax) in the three and six months ended June 30, 2005 and $31 million ($20 million after-tax) in the three and six months ended June 30, 2004, related to these settlements and associated legal expenses. The pre-tax
charges are reflected in general and administrative expenses on our unaudited condensed consolidated statements of operations. The charge recorded in the three months ended June 30, 2005 is primarily a result of appreciation in our stock price from
the date of the settlement through June 30, 2005. We expect to record another adjustment to income in the third quarter 2005, to the extent the closing stock price on the date of issuance differs from $4.86, the closing stock price on June 30, 2005.



ERISA/Illinois Power 401(k) Litigation. In
January 2005, three DMG employees who are participants in the DMG 401(k) Savings Plan for employees covered under a collective Bargaining Agreement (formerly known as the Illinois Power Company Incentive Savings Plan For Employees Covered Under a
Collective Bargaining Agreement), which we refer to as the DMG 401(k) Plan, purporting to represent all DMG and Illinois Power employees who held Dynegy common stock through the DMG 401(k) Plan during the period from February 2000
through the present, filed a lawsuit in federal court in the Southern District of Illinois against us, Illinois Power Company, DMG and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG 401(k) Plan
that are similar to the claims made in the ERISA litigation settled in December 2004, including claims that certain of our former and current officers (who are past and present members of our Benefit Plans Committee) 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. We have filed motions to transfer this litigation to the Southern District of Texas and a ruling on these motions is expected in the third
quarter. It is not possible to predict with certainty whether we will incur any liability or to estimate the range of possible loss, if any, that we might incur in connection with these lawsuits. However, we do not believe that any liability which
might be incurred by Dynegy as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Enron/NNG VEBA Litigation. Prior to our acquisition of NNG from Enron, NNG employees were participants in a post-retirement medical plan
maintained by Enron. The plans assets were maintained in a VEBA trust, along with the assets of other Enron companies whose plans were included in the same VEBA trust (the Enron VEBA). Enron filed bankruptcy in December 2001. When
we acquired NNG in January 2002, the assets of the Enron VEBA had not been distributed to its participant companies, though we and NNG made the appropriate requests for such a distribution. In July 2002, we estimated that approximately $25.4 million
of the assets of the Enron VEBA were attributable to the NNG employees who participated in the post-retirement medical plan. On July 1, 2002, as part of our sale of NNG to Mid American Energy Holdings Company, NNG



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



established a separate VEBA trust solely for its plan participants (the NNG VEBA). As a condition of the sale agreement, we placed $25.4 million
into escrow under terms providing that if Enron did not release NNGs share of the VEBA assets by August 2004, NNG was entitled to the escrowed money to fund the NNG VEBA.



As Enron did not release the funds from the Enron VEBA as of August 2004, NNG placed our escrowed funds into the NNG VEBA.
Pursuant to the escrow agreement, once the Enron VEBA releases NNGs funds to the NNG VEBA, we will be entitled to be reimbursed an equivalent amount, up to $25.4 million.



In June 2005, in accordance with the terms of the escrow agreement, NNG, the NNG VEBA trustee, and the NNG VEBA participants
as a class, filed a class action lawsuit in Nebraska federal court against various Enron related parties, including the individual members of the Enron Benefit Plan Committee, alleging a breach of fiduciary duty under ERISA and seeking immediate
disbursement of the Enron VEBA assets. As we have a receivable recorded to reflect our rights to this distribution, an adverse outcome in this matter would impact us, even though we are not a party. We do not believe that an adverse result in this
litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Baldwin Station Litigation. Since November 1999, DMG has been the subject of an NOV from the EPA and a complaint filed by the EPA and the
DOJ in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations related to certain maintenance, repair and replacement activities at our Baldwin generating station. We reached agreement with the
EPA, the DOJ, the State of Illinois and the environmental group intervenors on terms to settle the litigation. A consent decree was signed by all parties and lodged with the U.S. District Court for the Southern District of Illinois on March 7, 2005.
Following a public comment period and hearing, the Court entered and approved the consent decree on May 27, 2005. No appeals were filed prior to the expiration of the appeal period on July 26, 2005. The consent decree provides for our payment of a
civil penalty of $9 million and for our funding of several environmental projects in the additional aggregate amount of $15 million. It also requires us to install additional emission controls at our Baldwin, Vermilion and Havana plants. Based upon
preliminary engineering estimates, the installation of these emission controls, including the previously planned conversion of our Vermilion facility to low-sulfur PRB coal, is expected to cost approximately $320 million through 2010, with an
additional investment of approximately $225 million in the 2011-2012 timeframe. These estimates represent managements reasonable judgment with respect to 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 the actual costs incurred with regard to these emission controls to differ materially from such estimates. The decree settles all claims in the litigation, as well as similar
claims that might have been brought related to maintenance, repair and replacement activities at other DMG plants including Vermilion, Wood River, Hennepin and Havana.



The $9 million civil penalty pursuant to the consent decree was paid on June 17, 2005. Reserves have been provided in an
amount adequate to cover environmental projects provided for under the consent decree.



The EPA previously requested information, which we provided, concerning maintenance, repair and replacement activities at our Danskammer and Roseton plants. The consent decree does not cover any activities at the
Danskammer and Roseton plants; however, the EPA could eventually commence enforcement actions based on activities at these plants. At this time, we are unable to assess the likelihood of any such additional EPA enforcement actions.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



California Market Litigation.We and various other power generators and marketers are
defendants in numerous lawsuits alleging rate and market manipulation in Californias wholesale electricity market during the California energy crisis and seeking unspecified treble damages. The cases included: Pamela R. Gordon v. Reliant
Energy Inc., et al.; Ruth Hendricks v. Dynegy Power Marketing, et al.; The People of the State of California v. Dynegy Power Marketing, et al.; Sweetwater Authority v. Dynegy Inc., et al.; People of the State of California ex rel. Bill Lockyer,
Attorney General v. Dynegy Inc., et al.; Public Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, et al.; and Bustamante [I] v. Dynegy Inc., et al.These cases were coordinated before a single federal judge, who dismissed two
of them, Lockyer and Snohomish County, in the first quarter of 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. In Lockyer, plaintiffs Petition for Writ of Certiorari to the U.S. Supreme Court was denied in April 2005. Plaintiffs in Snohomish County filed a Petition for Writ of Certiorari to the U.S. Supreme Court in November
2004 that was denied in June 2005. The remaining coordinated cases were remanded to a California state court, where we filed a motion to dismiss in July 2005.



Between April and October 2002, the following nine additional 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: Pier 23 Restaurant v. PG&E Energy Trading, et al.; Bronco Don Holdings v. Duke Energy Trading and Marketing, LLC,
et al.; T&E Pastorino Nursery v. Duke Energy Trading and Marketing LLC, et al.; Century Theaters, Inc. v. Allegheny Energy Supply Company, et al.; J&M Karsant Family Ltd. Partnership v. Duke Energy Trading and Marketing, LLC, et al.;
Leos Day & Night Pharmacy v. Duke Energy Trading and Marketing, LLC, et al.; El Super Burrito v. Allegheny Energy Supply Company, LLC, et al.; RDJ Farms, Inc. v. Allegheny Energy Supply Company, et al.; and Millar v. Allegheny Energy
Supply Company, LLC, et al.The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek injunctive relief, restitution and unspecified damages. Although some of the
allegations in these lawsuits are similar to those in the seven cases referenced above, these lawsuits include additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR.
Following removal of these cases, the federal court dismissed eight of the nine actions and plaintiffs appealed. In February 2005, the Ninth Circuit affirmed the dismissals. The remaining case, Millar, was remanded to state court, and in May
2005, defendants filed a motion to dismiss. Plaintiffs filed their response in June 2005, and shortly thereafter, the defendants replied. The Court has not yet issued its ruling.



In December 2002, two additional actions were filed on behalf of consumers and businesses in Oregon, Washington, Utah,
Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleging violations of the Cartwright Act and unfair business practices. These cases were subsequently dismissed and refiled in California Superior
Court as one class action complaint styled JerryEgger v. Dynegy Inc., et al. We removed the action from state court and consolidated it with existing actions pending before the U.S. District Court for the Northern District of
California. Plaintiffs challenged the removal and thus, the federal court stayed its ruling pending a decision by the Ninth Circuit on the five coordinated cases referenced above. Although the Ninth Circuit issued a decision remanding those cases,
no ruling has been made with respect to Egger.



In May
and June 2004, two additional lawsuits,Wah Chang v. Avista Corporation, et al.and City of Tacoma v. American Electric Power Service Corporation, et al., were filed in Oregon and Washington federal courts against several energy
companies, including DPM, seeking more than $30 million in compensatory damages resulting from alleged manipulation of the California wholesale power markets. In February 2005, the respective federal courts granted our motions to dismiss. Shortly
thereafter, plaintiffs in both cases filed notices of appeal to the Ninth Circuit. We intend to file a motion for summary disposition to dismiss the appeal upon the filing of plaintiffs brief in August 2005.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



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 removed the action to federal court in June 2005.



We believe that we have meritorious defenses to these claims and intend to defend against such claims. We cannot predict with certainty whether we will
incur any liability 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 provided for the settlement of FERC claims relating to western energy market transactions that
occurred from January 2000 through June 2001. Market participants (other than the parties to the settlement) were permitted to opt into this settlement and share in the distribution of the settlement proceeds, and most of these other market
participants have done so. The Cal ISO will determine the entitlement to refund and/or the liability of each non-settling market participant. Under the terms of the settlement, we will have no further liability to these non-settling parties. The
settlement further provides that we are entitled to pursue claims for reimbursement of fuel costs against various non-settling market participants. We are currently pursuing these claims but are unable to predict the amounts that may be recovered
from such parties.



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.



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. Assuming the
master netting agreement is enforceable, we have 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 were owed by Enron to approximately $57 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 had been fully reserved in the fourth quarter 2001. In the event that Enron prevails in its position that the master netting agreement is unenforceable, our
exposure to Enron would be approximately $216 million, with as much as $220 million in unsecured Dynegy claims remaining to enforce against the bankruptcy estate. As required by the master netting agreement, we have pursued resolution of this
dispute through arbitration; however, we were unsuccessful in our efforts to arbitrate



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because the Bankruptcy Court did not grant our motion, which was opposed by Enron, to permit arbitration with a non-bankrupt Enron entity. We then filed a
motion with the Bankruptcy Court to allow us to proceed to discovery and trial in order to determine the enforceability of the master netting agreement under the U.S. Bankruptcy Code. The Bankruptcy Court denied our motion and ordered us to mediate
the dispute with Enron. The parties participated in mediation in November 2004, and have had further discussions since that time, but no settlement has been reached.



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 claims.
Reserves have been provided in an aggregate amount we consider reasonable with respect to Enrons claims. 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 addition, each claimed additional amounts related to long-term incentive payments. In May 2004, pursuant to the decision of the arbitration
panel, we paid Mr. Bergstrom $10.4 million plus attorneys fees, costs and interest. Shortly after the panels decisions in the Bergstrom matter, we elected to enter into mediation with Mr. Watson. Through mediation, we agreed to pay 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 4Restructuring and
Impairment ChargesSeverance and Other Restructuring Costs beginning on page F-31 of our Form 10-K for further discussion regarding the accrual relating to these former executive officers.



The arbitration with respect to Mr. Doty is currently scheduled to commence
in September 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 that we consider reasonable relating to this proceeding.



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 because 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
notice of appeal with the court in October 2004 and its appellate brief in December 2004. The parties attended mediation in February 2005, but did not reach a settlement. Settlement discussions continue outside of mediation. Barring settlement, we
expect to file our response to the plaintiffs appellate briefs in the third quarter 2005. 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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Gas Index Pricing Litigation. We are defending the following suits that claim damages
resulting from the alleged manipulation of gas index publications and prices by us and others: ABAG v. Sempra Energy et al. (filed in state court in November 2004); AblemanArt Glass v. Encana Corporation et al.(class action
filed in federal court in December 2004); Benschiedt(class action filed in state court in February 2004); Bustamante v. The McGraw Hill Companies et al. (class action filed in state court in November 2002); City and County of San
Franciscov. Dynegy Inc. et al.(filed in state court in July 2004); County of San Diego v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state court in July 2004); County of San Mateov.
Sempra Energy et al.(filed in state court in December 2004); County of Santa Clarav. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state court in July 2004); FairhavenPower Company v.
Encana Corp. et al. (class action filed in federal court in September 2004); In re Natural Gas Commodity Litigation (class action filed in federal court in January 2004); Leggett v. Duke Energy et al. (class action filed in state
court in January 2005); Multiut v. Dynegy Inc.(filed in federal court in December 2004); Nelson Brothers LLC v. Cherokee Nitrogen v. Dynegy Marketing and Trade and Dynegy Inc.(filed in state court in April 2003); Nurserymens
Exchange v. Sempra Energy et al. (filed in state court in October 2004); Older v. Dynegy Inc. et al.(filed in federal court in September 2004); Owens-Brockway v. Sempra Energy at al.(filed in state court in January 2005);
People of the State of Montana et al. v. Williams Energy Marketing et al.(filed in federal court in July 2003); Sacramento Municipal Utility District (SMUD) v. Reliant Energy Services, et al.(filed in state court in November
2004);School Project for Utility Rate Reduction v. Sempra Energy et al.(filed in state court in November 2004);Sierra Pacific Resources and Nevada Power Company v. El Paso Corp. et al. (filed in federal court in April 2003);
Tamco v. Dynegy Inc. et al.(filed in state court in December 2004);Texas-Ohio Energy, Inc. v. CenterPoint Energy Inc., et al.(class action filed in federal court in November 2003); and Utility Savings& Refund v. Reliant
Energy Services, et al.(class action filed in federal court in November 2004). 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 reports 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. We have not been served in the Montana case.



Pursuant to various motions filed by the parties to the litigation described above, the gas index pricing lawsuits pending
in state court (except for Nelson Brothers) have been consolidated before a single judge in state court in San Diego. These cases are now entitled the Judicial Counsel Coordinated Proceeding (JCCP) 4221, 4224, 4226, and 4228, the
Natural Gas Anti-Trust Cases, I, II, III, & IV, which we refer to as the Coordinated Gas Index Cases. In April 2005, defendants moved to dismiss the Coordinated Gas Index Cases on preemption and filed rate grounds. The Court
denied defendants motion in June 2005. The parties are presently engaged in discovery. The Nelson Brothers lawsuit involves an alleged breach of a gas purchase contract and is pending in Alabama state court. In March 2005, we moved to
compel the matter to arbitration. The trial court denied the motion, and in April 2005 we appealed the decision to the Alabama Supreme Court.



As to the gas index pricing lawsuits filed in federal court, the Sierra Pacific case was dismissed in December 2004 on defendants motion. In
Texas-Ohio, the defendants filed a motion to dismiss in May 2004, which the court granted in April 2005. In the In re Natural Gas Commodity Litigation matter, pending in New York federal court, the parties are actively engaged in
discovery following denial of the appeal of the previous denial of defendants motion to dismiss. In April 2005, defendants filed a joint opposition to the motion for class certification filed by the plaintiffs earlier in the year. The
Multiut case involves a counterclaim of alleged index manipulation filed by the defendant, Multiut, against whom we have a pending breach of gas purchase contract claim. Multiut,along with the remaining federal court cases
(Abelman, Fairhaven Power, Utility Savings and



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Leggett) are pending transfer, or have already been transferred, to the federal judge in Nevada who presided over the Texas-Ohio matter.



We are analyzing all of these claims and intend to defend
vigorously against them. We cannot 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 this litigation would have a material adverse effect
on our financial condition, results of operations or cash flows.



Stand Energy Litigation (formerly 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 July 2004, prior to the Courts ruling on defendants
motions to dismiss, the plaintiff voluntarily dismissed the Maryland federal court action against all defendants. Shortly thereafter, plaintiff filed a class action lawsuit in 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. In January 2005, the newly added defendants filed motions to dismiss on
various grounds. Oral argument on some of the pending motions occurred in April 2005. In June 2005, the Court denied defendants motions to dismiss on the following grounds: filed rate doctrine, field preemption, certain antitrust claims and
unjust enrichment. However, the Court granted defendants motion to dismiss under antitrust law to the extent Plaintiffs claims are based on price fixing. In August 2005, the Court granted certain defendants (including Dynegy Inc.)
motion to dismiss all antitrust claims on statute of limitations grounds. Our motion to dismiss for lack of personal jurisdiction remains pending before the Court. We are analyzing these claims and intend to defend against them vigorously. We cannot
predict with certainty whether we will incur any liability in connection with this lawsuit, however, we believe that any liability incurred as a result of this litigation would not 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. All of the lawsuits pending in Austria have been stayed. This former subsidiary is in liquidation and 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. In December 2004, the plaintiffs filed a motion for partial summary judgment on issues of liability. Oral argument on plaintiffs motion was held in June 2005. An order is
expected in September 2005.



We continue to oppose these claims
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.



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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  Texas (formerly U.S. Attorney Investigations). We are continuing to cooperate fully with the U.S. Attorneys office in Houston in its ongoing investigation of the
industrys gas trade reporting practices. We do not believe these investigations will have a material adverse effect on our financial condition, results of operations or cash flows.



In January 2003, one of our former natural gas traders was indicted on three counts of knowingly causing the transmission of
false trade reports used to calculate the index price of natural gas and four counts of wire fraud. In December 2004, a second indictment was filed against this same individual and other individuals, not related to Dynegy, alleging conspiracy to
falsely report gas prices to various index publications. A superceding indictment was returned in July 2005 recharging the original violations and adding additional charges. There is no trial date set for this indictment.



U.S. Attorney Investigations  California (formerly U.S. Attorney
Investigations).The U.S. Attorneys office in the Northern District of California issued a Grand Jury subpoena requesting information related to our activities in the California energy markets in November 2002. We continue to cooperate
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 cooperated with the Department of
Labor throughout this investigation, which focused on a review of plan documentation, plan reporting and disclosure, plan record keeping, plan investments and investment options, plan fiduciaries and third-party service providers, plan contributions
and other operational aspects of the plans. In February 2005, we received a letter from the Department of Labor indicating that, as a result of our recent settlement in the ERISA litigation, it intended to take no further action with respect to its
investigation of the Dynegy Inc. 401(k) Plan. However, its investigation is ongoing as it relates to the Illinois Power 401(k) Plans, and the recent litigation relating to those plans described above.



Guarantees and Indemnifications. We routinely enter into
contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical
service agreements,



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and procurement and construction contracts. Some agreements contain indemnities that cover the other partys negligence or limit the other partys
liability with respect to third-party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by
the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss
could be significant, in most cases management considers the probability of loss to be extremely remote.



During 2003, as part of our sale of Northern Natural, the Rough and Hornsea gas storage facilities and certain natural gas liquids assets, we provided
indemnities to third parties regarding environmental, tax, employee and other representations. Maximum recourse under these indemnities is limited to $209, $857 and $28 for the Northern Natural, Rough and Hornsea gas storage facilities and natural
gas liquids assets, respectively. We also entered into similar indemnifications regarding environmental, tax, employee and other representations when completing other asset sales such as, but not limited to, Hackberry LNG Project, SouthStar Energy
Services and various Canadian assets. We carry reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.



As a condition of our 2004 sale of Illinois Power and our interest in Joppa, we provided indemnifications to third parties
regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, we have indemnified third parties against losses resulting from possible adverse regulatory
actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased gas and investments in specified items. Although there is no limitation on our liability under this indemnity, our indemnity is
limited to 50% of any such losses. Illinois Power had not sustained any material losses in recent years and, at the time of the sale of Illinois Power to Ameren, our management considered the probability of any material loss under this indemnity
remote. Consequently, the value of the indemnification was initially deemed to be insignificant. In the second quarter of 2005, however, the ICC rejected an Administrative Law Judges proposed order and entered an order in one of the
proceedings covered by the scope of this indemnification that disallowed items relating to one of Illinois Powers gas storage fields, resulting in a negative revenue requirement impact to Ameren. On July 27, 2005, we made a payment of $8
million to Ameren in settlement of Amerens indemnification claims with respect to this ICC order. Although the ICC has not issued an order in any other cases, there are other cases in which it is now probable, based on this recent action by
the ICC that some loss may occur and a liability can be reasonably estimated. As a result, in the second quarter 2005, we recognized a pre-tax charge of $12 million, which is included in general and administrative expense on our unaudited condensed
consolidated statements of operations. Further disallowances and other events, which fall within the scope of the indemnity, may still occur; however, we are not required to accrue a liability in connection with these indemnifications, as management
cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. We intend to contest any proposed disallowances.



We have also entered into various indemnifications regarding environmental,
tax, employee and other representations when completing other asset sales such as, but not limited to Michigan Power, Oyster Creek, Hartwell, Commonwealth, Sherman, Indian Basin and PESA. We carry reserves for existing environmental, tax and
employee liabilities and have incurred no other expense relating to these indemnities.



During 2004, as part of entering into a back-to-back power purchase agreement with Constellation, under which Constellation effectively received our rights to purchase approximately 570 MW of capacity and
energy arising under our Kendall tolling contract, we guaranteed Constellation an aggregate $3.5 million in reactive power revenues over the four year term of the power purchase agreement. We established a liability of $0.3 million reflecting the
fair value of this guarantee, but have made no payments or incurred any other expense relating to this guarantee.



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Note 11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 U.S. Congress, as well
as various state legislative bodies, are considering a number of bills that could impact current 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.



Roseton State Pollutant Discharge Elimination System Permit. Rosetons SPDES Permit was issued for a five-year term in 1987. Prior to expiration of the permit, Central Hudson Gas & Electric (former owner) filed a
timely and sufficient application to renew the SPDES Permit. Under New York State law, when a timely and sufficient application for renewal is filed before a SPDES Permit expires, the permit is extended by operation of law until final action is
taken on the renewal application. In April 2005, the NYSDEC issued to DNE a draft SPDES Permit for the Roseton plant. The draft SPDES Permit contains provisions governing, among other things, the cooling water intake and the discharge of heated
effluent water. These provisions require the facility to actively manage its water intake to reduce impingement mortality of fish by 85% and to reduce entrainment mortality of aquatic organisms including juvenile fish, larvae and fish eggs by 70%
during the first two years of the renewal term, and by 80% thereafter.



On July 18, 2005, a public hearing was held to receive public comments on the draft SPDES Permit. On July 19 and 20, 2005, the Administrative Law Judge held an issues conference to consider party status and to determine what issues should
be subject to adjudication at the adjudicatory hearing. Three organizations filed petitions for party status and appeared through counsel at the issues conference. The petitioners, Riverkeeper, Inc., Natural Resource Defense Council, Inc. and Scenic
Hudson, Inc. seek to impose a permit requirement that the Roseton plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing entrainment and impingement. The petitioners claim
that only a closed cycle cooling system meets the Clean Water Acts requirement that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental
impacts from the facilitys cooling water intake structures. The current draft SPDES Permit does not require installation of a closed cycle cooling system; however, it does require entrainment and impingement mortality reductions that exceed
the best technology available requirements of the USEPA regulations applicable to existing facilities. We expect that the adjudicatory hearing on the Roseton draft SPDES Permit will be held in the spring or summer of 2006. We believe that the
Petitioners claims are without merit and we plan to vigorously oppose those claims. Given the cost of installing a closed cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial
condition, results of operations and cash flows.



Danskammer Water Permit. Our wastewater discharges are permitted under the Clean Water Act and analogous state laws. These permits are subject to review every five years. The state-issued water discharge permits associated
with the DNE facilities expired in 1992. However, under New York State law, the authorization arising under these permits 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



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and discharge permit expired because of alleged deficiencies in the renewal application process. In September 2004, the Court ruled that the water intake and
discharge permit for our Danskammer facility is void, but stayed the enforcement of the decision pending further review by the Court or by the Appellate Division.



In October 2004, we filed our appeal of the Courts decision with the Appellate Division and are currently challenging
the Courts ruling voiding our permit. We are also continuing to seek renewal of the water intake and discharge permit in proceedings before the NYSDEC. If our appeal is ultimately unsuccessful, we may be required to suspend 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
suspend 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. The FERCs market-based rate authority allows the sale of power at
negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic re-review. 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 it upheld in July 2004, (i) addressing the implementation
process for pending and new market-based rate applications and (ii) establishing a timeline for entities with FERC market-based rate authority to provide the FERC with their market power assessment. These orders required entities that were
previously granted market-based rate authority by the FERC, including entities with pending applications for re-review, to resubmit their applications in accordance with the new directive. Consequently, our entities with applications pending since
February 2002, as well as the entities we acquired in January 2005 in connection with the Sithe Energies acquisition, timely resubmitted their applications to the FERC. On June 16, 2005, the FERC issued an order accepting the updated market power
analyses submitted by Sithe Energies and Dynegy. Our next (triennial) market power analysis is due June 16, 2008.



Note 12Employee Compensation, Savings and Pension Plans



We have various defined benefit pension plans and post-retirement benefit plans, which are more fully described in Note 19Employee Compensation,
Savings and Pension Plans beginning on page F-73 of our Form 10-K.



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



|                                              |  |                             |    |   |                |   |     |      |  |      |   |  |   |    |  
|--------------------------------------------- |  | --------------------------- | -- | - | -------------- | - | --- | ---- |  | ---- | - |  | - | -- | -
|                                              |  | Pension Benefits            |    |   | Other Benefits |  
|                                              |  | Three Months Ended June 30, |   
|                                              |  | 2005                        |    |   | 2004           |   |     | 2005 |  | 2004 |  
|                                              |  | (in millions)               |   
|Service cost benefits earned during period    |  | $                           | 3  |   |                | $ | 6   |      |  | $    |  |  | $ | 1  |  
|Interest cost on projected benefit obligation |  |                             | 2  |   |                |   | 10  |      |  |      | 1 |  |   | 3  |  
|Expected return on plan assets                |  |                             | (2 | ) |                |   | (12 | )    |  |      |  |  |   | (1 | )
|Recognized net actuarial loss                 |  |                             | 1  |   |                |   | 4   |      |  |      |  |  |   | 1  |  
|                                              |  |                             |    |   |                |   |     |      |  |      |   |  |   |    |  
|Total net periodic benefit cost               |  | $                           | 4  |   |                | $ | 8   |      |  | $    | 1 |  | $ | 4  |  
|                                              |  |                             |    |   |                |   |     |      |  |      |   |  |   |    |  



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|                                              |  |                           |    |   |                |   |     |      |  |      |   |  |   |    |  
|--------------------------------------------- |  | ------------------------- | -- | - | -------------- | - | --- | ---- |  | ---- | - |  | - | -- | -
|                                              |  | Pension Benefits          |    |   | Other Benefits |  
|                                              |  | Six Months Ended June 30, |   
|                                              |  | 2005                      |    |   | 2004           |   |     | 2005 |  | 2004 |  
|                                              |  | (in millions)             |   
|Service cost benefits earned during period    |  | $                         | 6  |   |                | $ | 12  |      |  | $    | 1 |  | $ | 2  |  
|Interest cost on projected benefit obligation |  |                           | 4  |   |                |   | 20  |      |  |      | 2 |  |   | 6  |  
|Expected return on plan assets                |  |                           | (4 | ) |                |   | (24 | )    |  |      |  |  |   | (3 | )
|Recognized net actuarial loss                 |  |                           | 2  |   |                |   | 8   |      |  |      |  |  |   | 3  |  
|                                              |  |                           |    |   |                |   |     |      |  |      |   |  |   |    |  
|Total net periodic benefit cost               |  | $                         | 8  |   |                | $ | 16  |      |  | $    | 3 |  | $ | 8  |  
|                                              |  |                           |    |   |                |   |     |      |  |      |   |  |   |    |  



Contributions. During 2005, we expect to contribute approximately $31 million to our pension plans, the final $21 million of which we expect to pay in September 2005, and $0.3 million to our other post-retirement benefit plans
in 2005. During the first half of 2005, we made $7 million in contributions, and we made an additional $3 million contribution in July.



Sale of Illinois Power.As a result of the sale of Illinois Power to Ameren, the number of participants in our various defined benefit
pension plans and post-retirement benefit plans was reduced substantially. Consequently, our 2005 net periodic benefit cost is substantially lower than the cost for 2004. In addition, in connection with the sale, we agreed to transfer a portion of
the assets in certain of our defined benefit plans to other plans maintained by Ameren. An initial asset transfer of $411 million was made in November 2004, and an additional transfer of approximately $67 million was made in the first quarter 2005.



Medicare Prescription Drug, Improvement and
Modernization Act of 2003.As discussed in Note 19Employee Compensation, Savings and Pension PlansMedicare Prescription Drug, Improvement and Modernization Act of 2003, beginning on page F-78 of our Form 10-K, we anticipate that
the amount of benefits we will pay after 2005 will be lower as a result of the new Medicare provisions described under this Act.



Note 13Income Taxes



Effective Tax Rate. The income tax benefits included in our loss from continuing operations were as follows:

|                   |  |                             |    |   |                           |   |    |      |  |   |      |   |  |   |     |  
|------------------ |  | --------------------------- | -- | - | ------------------------- | - | -- | ---- |  | - | ---- | - |  | - | --- | -
|                   |  | Three Months Ended June 30, |    |   | Six Months Ended June 30, |  
|                   |  | 2005                        |    |   | 2004                      |   |    | 2005 |  |   | 2004 |  
|                   |  | (in millions, except rates) |   
|Income tax benefit |  | $                           | 41 |   |                           | $ | 29 |      |  | $ | 215  |   |  | $ | 82  |  
|Effective tax rate |  |                             | 27 | % |                           |   | 66 | %    |  |   | 35   | % |  |   | 101 | %



We compute our
quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions. Income taxes for significant unusual or
extraordinary transactions are computed and recorded in the period that the specific transaction occurs. During 2005, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to the
nondeductible portion of the shareholder litigation settlement, offset by the changes in the valuation allowance, as further discussed below, and adjustments to the effective state tax rate. During 2004, our overall effective tax rate on continuing
operations was different than the statutory rate of 35% due primarily to changes in the valuation allowance and adjustments related to the conclusion of prior year tax audits, as further discussed below.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Capital Loss Valuation Allowance.As a result of the anticipated sale of DMSLP,
as further discussed in Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids, we reduced the valuation allowance related to our capital loss carryforward by $125 million in
both the three and six months ended June 30, 2005. This benefit is reflected in income from discontinued operations on our unaudited condensed consolidated statements of operations.



The changes in the valuation allowance by attribute since December 31, 2004 were as follows:



|                                         |  |                           |      |   |                    |   |     |                        |  |   |       |   |  |   |      |  
|---------------------------------------- |  | ------------------------- | ---- | - | ------------------ | - | --- | ---------------------- |  | - | ----- | - |  | - | ---- | -
|                                         |  | Capital LossCarryforwards |      |   | Foreign TaxCredits |   |     | State NOLCarryforwards |  |   | Total |  
|                                         |  | (in millions)             |     
|Balance as of December 31, 2004          |  | $                         | (125 | ) |                    | $ | (38 | )                      |  | $ | (1    | ) |  | $ | (164 | )
|Acquisition of Sithe Energies            |  |                           | (17  | ) |                    |   |    |                        |  |   | (20   | ) |  |   | (37  | )
|Tax benefit from discontinued operations |  |                           | 125  |   |                    |   |    |                        |  |   |      |   |  |   | 125  |  
|                                         |  |                           |      |   |                    |   |     |                        |  |   |       |   |  |   |      |  
|Balance as of June 30, 2005              |  | $                         | (17  | ) |                    | $ | (38 | )                      |  | $ | (21   | ) |  | $ | (76  | )
|                                         |  |                           |      |   |                    |   |     |                        |  |   |       |   |  |   |      |  



Previously, as a
result of the asset sales discussed in Note 3Discontinued Operations, Dispositions and Contract Terminations, as well as other transactions occurring in 2004, we reduced the valuation allowance related to our capital loss carryforward by $8
million and $47 million in the three and six months ended June 30, 2004, respectively. 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 income from discontinued operations on our unaudited condensed
consolidated statements of operations. An offsetting benefit of $3 million is reflected in income tax benefit (expense) on our unaudited condensed consolidated statements of operations.



Balance Sheet Classification. The balance sheet classification of deferred tax liabilities and assets is as
follows:



|                           |  |               |      |   |                  |   |      |  
|-------------------------- |  | ------------- | ---- | - | ---------------- | - | ---- | -
|                           |  | June 30,2005  |      |   | December 31,2004 |  
|                           |  | (in millions) |     
|Deferred tax assets:       |  |               |      |   |                  |   |      |  
|Current                    |  | $             | 496  |   |                  | $ | 74   |  
|Non-current                |  |               | 13   |   |                  |   | 12   |  
|Deferred tax liabilities:  |  |               |      |   |                  |   |      |  
|Non-current                |  |               | (885 | ) |                  |   | (597 | )
|                           |  |               |      |   |                  |   |      |  
|Net deferred tax liability |  | $             | (376 | ) |                  | $ | (511 | )
|                           |  |               |      |   |                  |   |      |  



The balance sheet
classification of our deferred tax liabilities and assets has changed significantly since December 31, 2004. As a result of our projected gain on the sale of DMSLP, coupled with current year operations, we expect to utilize approximately $860
million of our net operating loss carryforwards and approximately $350 million of our capital loss carryforwards within the next 12 months. Accordingly, we have reclassified the deferred tax assets associated with these attributes from non-current
to current as of June 30, 2005.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Note 14Segment Information



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



Pursuant to 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, all gains and losses on third-party energy-trading contracts in the CRM segment, whether realized or unrealized, are
presented net in our 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.



In accordance with SFAS No. 144, results associated with our NGL segment,
primarily consisting of DMSLP, have been reclassified to discontinued operations for all periods presented. These results include revenues and cost of sales arising from intersegment transactions, which will cease after the sale of DMSLP. NGL
processes natural gas and sells this natural gas to CRM for resale to third parties. NGL also purchases natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGLs results were reclassified to
discontinued operation, the effects of these intersegment transactions, eliminated in consolidation, including the ultimate third party settlement, previously recorded in other segments, have also been reclassified to discontinued operations.
Revenues from continuing operations represents third party sales not originating from NGL.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Reportable segment information for the three- and six-month periods ended June 30, 2005 and 2004 is
presented below.



Dynegys Segment Data for the Quarter
Ended June 30, 2005

(in millions)



|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | --- | -- |  | --------------------- | ----- | - | ----- | - | --- | - |  | - | ------ | -
|                                                  |  | GEN |       |   | NGL |   |       | REG |  | CRM |    |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                            |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Domestic                                          |  | $   | 428   |   |     | $ |      |     |  | $   |   |  | $                     | (3    | ) |       | $ |    |   |  | $ | 425    |  
|Other                                             |  |     | 30    |   |     |   |      |     |  |     |   |  |                       | 4     |   |       |   |    |   |  |   | 34     |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|                                                  |  |     | 458   |   |     |   |      |     |  |     |   |  |                       | 1     |   |       |   |    |   |  |   | 459    |  
|Intersegment revenues                             |  |     | (17   | ) |     |   |      |     |  |     |   |  |                       | 17    |   |       |   |    |   |  |   |       |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Total revenues                                    |  | $   | 441   |   |     | $ |      |     |  | $   |   |  | $                     | 18    |   |       | $ |    |   |  | $ | 459    |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Depreciation and amortization                     |  | $   | (50   | ) |     | $ |      |     |  | $   |   |  | $                     |      |   |       | $ | (4  | ) |  | $ | (54    | )
|Operating income (loss)                           |  | $   | 19    |   |     | $ |      |     |  | $   |   |  | $                     | (15   | ) |       | $ | (68 | ) |  | $ | (64    | )
|Earnings from unconsolidated investments          |  |     | 4     |   |     |   |      |     |  |     |   |  |                       |      |   |       |   |    |   |  |   | 4      |  
|Other items, net                                  |  |     | 2     |   |     |   |      |     |  |     |   |  |                       | (1    | ) |       |   | 5   |   |  |   | 6      |  
|Interest expense                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   | (96    | )
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Loss from continuing operations before taxes      |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   | (150   | )
|Income tax benefit                                |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   | 41     |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Loss from continuing operations                   |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   | (109   | )
|Income from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   | 147    |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Net income                                        |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  | $ | 38     |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Identifiable assets:                              |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Domestic                                          |  | $   | 7,580 |   |     | $ | 1,542 |     |  | $   | 16 |  | $                     | 927   |   |       | $ | 563 |   |  | $ | 10,628 |  
|Other                                             |  |     | 5     |   |     |   | 2     |     |  |     |   |  |                       | 134   |   |       |   |    |   |  |   | 141    |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Total                                             |  | $   | 7,585 |   |     | $ | 1,544 |     |  | $   | 16 |  | $                     | 1,061 |   |       | $ | 563 |   |  | $ | 10,769 |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |     |   |  |   |        |  
|Unconsolidated investments                        |  | $   | 290   |   |     | $ | 78    |     |  | $   |   |  | $                     |      |   |       | $ |    |   |  | $ | 368    |  
|                                                  |  |     |       |   |     |  
|Capital expenditures                              |  | $   | (25   | ) |     | $ | (13   | )   |  | $   |   |  | $                     |      |   |       | $ | (1  | ) |  | $ | (39    | )



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



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

(in millions)



|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | ----- | - |  | --------------------- | ----- | - | ----- | - | ------ | - |  | - | ------ | -
|                                                  |  | GEN |       |   | NGL |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                            |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                          |  | $   | 54    |   |     | $ |      |     |  | $ | 317   |   |  | $                     | 343   |   |       | $ |       |   |  | $ | 714    |  
|Other                                             |  |     |      |   |     |   |      |     |  |   |      |   |  |                       | (25   | ) |       |   |       |   |  |   | (25    | )
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|                                                  |  |     | 54    |   |     |   |      |     |  |   | 317   |   |  |                       | 318   |   |       |   |       |   |  |   | 689    |  
|Intersegment revenues                             |  |     | 359   |   |     |   |      |     |  |   | 7     |   |  |                       | (185  | ) |       |   | (181   | ) |  |   |       |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total revenues                                    |  | $   | 413   |   |     | $ |      |     |  | $ | 324   |   |  | $                     | 133   |   |       | $ | (181   | ) |  | $ | 689    |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Depreciation and amortization                     |  | $   | (47   | ) |     | $ |      |     |  | $ |      |   |  | $                     |      |   |       | $ | (10    | ) |  | $ | (57    | )
|Operating income (loss)                           |  | $   | 35    |   |     | $ |      |     |  | $ | 22    |   |  | $                     | 90    |   |       | $ | (91    | ) |  | $ | 56     |  
|Earnings from unconsolidated investments          |  |     | 50    |   |     |   |      |     |  |   |      |   |  |                       |      |   |       |   |       |   |  |   | 50     |  
|Other items, net                                  |  |     |      |   |     |   |      |     |  |   |      |   |  |                       | (1    | ) |       |   | (8     | ) |  |   | (9     | )
|Interest expense                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (141   | )
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Loss from continuing operations before taxes      |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (44    | )
|Income tax benefit                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 29     |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Loss from continuing operations                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (15    | )
|Income from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 23     |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Net income                                        |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  | $ | 8      |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Identifiable assets:                              |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                          |  | $   | 6,362 |   |     | $ | 1,670 |     |  | $ | 4,867 |   |  | $                     | 2,353 |   |       | $ | (2,199 | ) |  | $ | 13,053 |  
|Other                                             |  |     | 35    |   |     |   | 4     |     |  |   |      |   |  |                       | 209   |   |       |   | 30     |   |  |   | 278    |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total                                             |  | $   | 6,397 |   |     | $ | 1,674 |     |  | $ | 4,867 |   |  | $                     | 2,562 |   |       | $ | (2,169 | ) |  | $ | 13,331 |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Unconsolidated investments                        |  | $   | 546   |   |     | $ | 80    |     |  | $ |      |   |  | $                     |      |   |       | $ |       |   |  | $ | 626    |  
|                                                  |  |     |       |   |     |  
|Capital expenditures                              |  | $   | (44   | ) |     | $ | (18   | )   |  | $ | (33   | ) |  | $                     |      |   |       | $ | (3     | ) |  | $ | (98    | )



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Dynegys Segment Data for the Six Months Ended June 30, 2005

(in millions)



|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | --- | -- |  | --------------------- | ----- | - | ----- | - | ---- | - |  | - | ------ | -
|                                                  |  | GEN |       |   | NGL |   |       | REG |  | CRM |    |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                            |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Domestic                                          |  | $   | 873   |   |     | $ |      |     |  | $   |   |  | $                     | 60    |   |       | $ |     |   |  | $ | 933    |  
|Other                                             |  |     | 30    |   |     |   |      |     |  |     |   |  |                       | (42   | ) |       |   |     |   |  |   | (12    | )
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|                                                  |  |     | 903   |   |     |   |      |     |  |     |   |  |                       | 18    |   |       |   |     |   |  |   | 921    |  
|Intersegment revenues                             |  |     | (26   | ) |     |   |      |     |  |     |   |  |                       | 26    |   |       |   |     |   |  |   |       |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Total revenues                                    |  | $   | 877   |   |     | $ |      |     |  | $   |   |  | $                     | 44    |   |       | $ |     |   |  | $ | 921    |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Depreciation and amortization                     |  | $   | (97   | ) |     | $ |      |     |  | $   |   |  | $                     | (1    | ) |       | $ | (11  | ) |  | $ | (109   | )
|Operating income (loss)                           |  | $   | 79    |   |     | $ |      |     |  | $   |   |  | $                     | (207  | ) |       | $ | (321 | ) |  | $ | (449   | )
|Earnings from unconsolidated investments          |  |     | 7     |   |     |   |      |     |  |     |   |  |                       |      |   |       |   |     |   |  |   | 7      |  
|Other items, net                                  |  |     | 2     |   |     |   |      |     |  |     |   |  |                       |      |   |       |   | 7    |   |  |   | 9      |  
|Interest expense                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   | (185   | )
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Loss from continuing operations before taxes      |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   | (618   | )
|Income tax benefit                                |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   | 215    |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Loss from continuing operations                   |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   | (403   | )
|Income from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   | 179    |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Net loss                                          |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  | $ | (224   | )
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Identifiable assets:                              |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Domestic                                          |  | $   | 7,580 |   |     | $ | 1,542 |     |  | $   | 16 |  | $                     | 927   |   |       | $ | 563  |   |  | $ | 10,628 |  
|Other                                             |  |     | 5     |   |     |   | 2     |     |  |     |   |  |                       | 134   |   |       |   |     |   |  |   | 141    |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Total                                             |  | $   | 7,585 |   |     | $ | 1,544 |     |  | $   | 16 |  | $                     | 1,061 |   |       | $ | 563  |   |  | $ | 10,769 |  
|                                                  |  |     |       |   |     |   |       |     |  |     |    |  |                       |       |   |       |   |      |   |  |   |        |  
|Unconsolidated investments                        |  | $   | 290   |   |     | $ | 78    |     |  | $   |   |  | $                     |      |   |       | $ |     |   |  | $ | 368    |  
|                                                  |  |     |       |   |     |  
|Capital expenditures                              |  | $   | (65   | ) |     | $ | (23   | )   |  | $   |   |  | $                     |      |   |       | $ | (5   | ) |  | $ | (93    | )



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004



Dynegys Segment Data for the Six Months Ended June 30, 2004

(in millions)



|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | ----- | - |  | --------------------- | ----- | - | ----- | - | ------ | - |  | - | ------ | -
|                                                  |  | GEN |       |   | NGL |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|Unaffiliated revenues:                            |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                          |  | $   | 100   |   |     | $ |      |     |  | $ | 769   |   |  | $                     | 654   |   |       | $ |       |   |  | $ | 1,523  |  
|Other                                             |  |     | 2     |   |     |   |      |     |  |   |      |   |  |                       | (69   | ) |       |   |       |   |  |   | (67    | )
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|                                                  |  |     | 102   |   |     |   |      |     |  |   | 769   |   |  |                       | 585   |   |       |   |       |   |  |   | 1,456  |  
|Intersegment revenues                             |  |     | 750   |   |     |   |      |     |  |   | 12    |   |  |                       | (423  | ) |       |   | (339   | ) |  |   |       |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total revenues                                    |  | $   | 852   |   |     | $ |      |     |  | $ | 781   |   |  | $                     | 162   |   |       | $ | (339   | ) |  | $ | 1,456  |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Depreciation and amortization                     |  | $   | (95   | ) |     | $ |      |     |  | $ | (10   | ) |  | $                     |      |   |       | $ | (20    | ) |  | $ | (125   | )
|Operating income (loss)                           |  | $   | 88    |   |     | $ |      |     |  | $ | 76    |   |  | $                     | 77    |   |       | $ | (145   | ) |  | $ | 96     |  
|Earnings from unconsolidated investments          |  |     | 88    |   |     |   |      |     |  |   |      |   |  |                       |      |   |       |   |       |   |  |   | 88     |  
|Other items, net                                  |  |     |      |   |     |   |      |     |  |   | 1     |   |  |                       | 2     |   |       |   | 3      |   |  |   | 6      |  
|Interest expense                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (271   | )
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Loss from continuing operations before taxes      |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | (81    | )
|Income tax benefit                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 82     |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Income from continuing operations                 |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 1      |  
|Income from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   | 77     |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Net income                                        |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  | $ | 78     |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Identifiable assets:                              |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Domestic                                          |  | $   | 6,362 |   |     | $ | 1,670 |     |  | $ | 4,867 |   |  | $                     | 2,353 |   |       | $ | (2,199 | ) |  | $ | 13,053 |  
|Other                                             |  |     | 35    |   |     |   | 4     |     |  |   |      |   |  |                       | 209   |   |       |   | 30     |   |  |   | 278    |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Total                                             |  | $   | 6,397 |   |     | $ | 1,674 |     |  | $ | 4,867 |   |  | $                     | 2,562 |   |       | $ | (2,169 | ) |  | $ | 13,331 |  
|                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |   |        |   |  |   |        |  
|Unconsolidated investments                        |  | $   | 546   |   |     | $ | 80    |     |  | $ |      |   |  | $                     |      |   |       | $ |       |   |  | $ | 626    |  
|                                                  |  |     |       |   |     |  
|Capital expenditures                              |  | $   | (58   | ) |     | $ | (27   | )   |  | $ | (61   | ) |  | $                     |      |   |       | $ | (5     | ) |  | $ | (151   | )



Note 15Subsequent Events



On July 27, 2005, we received $100 million of funds held
in escrow pursuant to the Baldwin consent decree. Please see Note 3Discontinued Operations, Dispositions and Contract TerminationsDispositions and Contract TerminationsSale of Illinois Power.



In July 2005, we made a $75 million payment in connection with the settlement
of the shareholder class action litigation and a $5 million payment in connection with the derivative litigation. Please see Note 10Commitments and ContingenciesShareholder Litigation for further discussion.



On August 2, 2005, we entered into an agreement to sell DMSLP, which
comprises substantially all of the operations of our NGL segment. Please see Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids for further discussion.



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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, 2005 and 2004



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.



GENERAL



We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily in two areas of the energy industry: power generation
and natural gas liquids. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. We also separately report the results of our CRM business,
which primarily consists of our two remaining power tolling arrangements (excluding the Independence toll, which is now part of our GEN segment) as well as our gas transportation contracts and 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.



Operational Highlights. We are a commodity-cyclical business and, as such, our core business results are affected by swings in commodity
prices. The four most important regions that impact our power generation business are PJM, MISO, New York Zone G and New York Zone A. We believe prices in these regions will be our most indicative earnings drivers for the remainder of 2005. Pricing
in each of these regions for the first six months of the year were higher than the same period last year, and although our volumes continue to be strong, they were slightly less than last year.



For our natural gas liquids business, the price of natural gas has the most
impact on our earnings due to our upstream contract structure which is primarily POP and POL. Crude oil pricing is also an important indicator of earnings as natural gas liquids prices have historically moved directionally with crude prices.
However, the current price relationship between crude oil and natural gas liquids has been less correlated, and natural gas liquids prices have not risen at the same rate as crude oil prices. Both natural gas and natural gas liquids prices remain
strong year to date in 2005. Processing volumes are higher, fractionation volumes are lower and marketing volumes are lower than the same period last year.



Please read Results of Operations for further discussion of the comparative results of our reportable business segments.



Restructuring Activities. We embarked on our self-restructuring
strategy in late 2002. Since then, we have been engaged in a comprehensive self-restructuring process through which our top priorities were to refocus, repair and rebuild the company. We refocused around our two core business lines, power generation
and natural gas liquids. We have worked to restore credibility and trust, and we restructured and eliminated many liabilities and risks facing the company.



During the first half of 2005, we achieved three critical accomplishments. Our acquisition of Sithe Energies in January 2005 achieved both sector growth
and restructuring of a significant toll obligation by making it an intercompany agreement. Through this transaction, we acquired more than 1,000 MW of low heat rate efficient generation facilities. In addition to the power plants, we acquired a 750
MW firm capacity sales agreement with



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Con Edison which runs through 2014. Over its term, this contract essentially offsets the principal and interest payments associated with the debt we assumed
in this acquisition.



Second, we entered into a comprehensive
settlement resolving the environmental litigation related to our Baldwin Energy Complex in Illinois. Under the terms of this settlement, we will undertake several emission control projects in the upcoming years, estimated to require an investment of
approximately $320 million between now and 2010, and an additional investment of approximately $225 million in the 2011-2012 timeframe. When completed, these power plant modifications are expected to meet or exceed anticipated federal environmental
requirements under the Clean Air Interstate Rules, as well as proposed legislation currently before Congress. The settlement also satisfied one of the conditions for the release of our remaining $100 million in sales proceeds held in escrow in
connection with our sale of Illinois Power to Ameren, and we received such funds on July 27, 2005.



Finally, in April 2005, we reached a comprehensive settlement of the shareholder class action litigation. Under the terms of the settlement, which
received final court approval in July 2005, we agreed to a total settlement consisting of (i) a $150 million payment to be covered by our directors and officers insurance policy, (ii) two cash payments totaling $250 million, which were made in May
and July of 2005, and (iii) the delivery of 17,578,781 shares of our Class A common stock promptly following expiration of the appeal period, which occurred on August 8, 2005.



With these three accomplishments, our self-restructuring phase essentially came to a close, and we move into our strategic
era.



Strategic Outlook. During our
self-restructuring phase, our main focus was on eliminating liabilities, mitigating risks and preserving collateral, while rebuilding the company around two core businesses  power generation and natural gas liquids. Our new strategic era is
one where the company is positioned for growth and focused on strategic alternatives for natural gas liquids and, in turn, power generation.



While the natural gas liquids business has played an integral role in our companys financial recovery, after careful consideration, we have
concluded that significant opportunities exist to realize even greater value through a sale. On August 2, 2005, we entered into an agreement to sell DMSLP, which comprises substantially all of the operations of our NGL segment. Please see Note
3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids for further discussion. We expect to net 95% of the cash proceeds from the sale of DMSLP, as the anticipated taxable gain
will be largely offset by net operating losses and capital loss carry-forwards. This will provide us with opportunities to further de-lever our capital structure, which we believe will position us favorably in a potential power generation strategic
combination or industry consolidation scenario.



While we
believe that our power generation business is commercially sound, operationally focused, reliably run and very well managed, future growth is tied to greater scale and scope and a responsive pricing environment. Accordingly, we believe that growth
through (i) independent organic transactions, (ii) opportunistic expansion or (iii) consolidation or strategic combination enabled by a more favorable net debt-to-capital ratio are the best ways to strengthen our business and deliver greater value
to investors.



In the case of organic growth, we could continue
to develop and expand our existing facilities. We have done this previously through the conversion of our Havana power generating facility to lower-cost and lower-emission PRB coal.



In the case of opportunistic expansion, we could explore opportunistic controlled expansion of our power generation business
through calculated acquisitions designed to increase our market share, similar to our acquisition of Sithe Energies and its Northeast power generation assets earlier this year. We believe there are significant opportunities to profitably expand in
our existing markets.



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In the case of consolidation or strategic combination, we could seek to achieve greater scale and scope
by engaging in strategic transactions with industry participants. We anticipate there will be an initial period of one-time transaction costs associated with combinations in the power sector. These integration costs will include, among other things,
costs to exit existing business contracts, including building leases, service arrangements or customer obligations. However, we believe the synergies to be realized by participating in the consolidation of the power sector will exceed the initial
integration costs. Combined organizations should benefit from economies of scale, which include cost efficiencies through combinations of back offices, as well as greater market share with geographic and fuel diversity.



Our ability to consummate the sale of DMSLP and utilize our tax loss
carryforwards should position our power generation business for growth and attractively align it for anticipated consolidation of the power sector. However, our desire or ability to pursue any such opportunities is subject to a number of factors
beyond our control. Accordingly, we cannot guarantee that any such opportunities will be available to us, nor can we predict with any degree of certainty the impact of any such opportunities on our financial condition or results of operations.



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 prepayments or cash collateral associated with purchases of commodities, particularly natural gas, coal and natural gas liquids,
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 to the extent we engage in these activities.



Debt Obligations



During the second quarter 2005, we used cash on hand to reduce our outstanding debt as follows:



| |  |  | $17 million payment related to our Independence Senior Notes due 2007; and
| | - |  | --------------------------------------------------------------------------



| |  |  | $2 million payment for our May 2004 term loan.
| | - |  | ----------------------------------------------



Our aggregate maturities for long-term debt, including the current portion and excluding our Central Hudson leveraged lease and our Series C preferred
stock, as of June 30, 2005, were approximately $5.1 billion. This includes the approximately $797 million of debt acquired with our 2005 acquisition of the Independence facility, which had a face value of $919 million at acquisition. Please see Note
2AcquisitionSithe Energies and Note 7DebtIndependence Debt for further discussion of this transaction.



Under the terms of our credit facilities, in connection with the sale of DMSLP, we are required to use a portion of the proceeds of such sale to repay any
borrowings under our revolving credit facility, a $594 million term loan and the $189 million generation facility debt. Following such repayments, our debt maturity profile will include $62 million in 2006, $40 million in 2007, $269 million in 2008,
$57 million in 2009, $688 million in 2010 and $3,208 million thereafter.



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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 financial 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 segment at August 4, 2005, June 30, 2005 and December 31, 2004:



|                  |  |               |     |              |   |                  |  |   |    
|----------------- |  | ------------- | --- | ------------ | - | ---------------- |  | - | ---
|                  |  | August 4,2005 |     | June 30,2005 |   | December 31,2004
|                  |  | (in millions)
|By Segment:       |  |               |     |              |   |                  |  |   |    
|GEN               |  | $             | 235 |              | $ | 203              |  | $ | 192
|CRM               |  |               | 68  |              |   | 68               |  |   | 94 
|NGL               |  |               | 220 |              |   | 230              |  |   | 167
|REG               |  |               |    |              |   |                 |  |   | 10 
|Other             |  |               | 8   |              |   | 8                |  |   | 7  
|                  |  |               |     |              |   |                  |  |   |    
|Total             |  | $             | 531 |              | $ | 509              |  | $ | 470
|                  |  |               |     |              |   |                  |  |   |    
|By Type:          |  |               |     |              |   |                  |  |   |    
|Cash              |  | $             | 209 |              | $ | 216              |  | $ | 376
|Letters of Credit |  |               | 322 |              |   | 293              |  |   | 94 
|                  |  |               |     |              |   |                  |  |   |    
|Total             |  | $             | 531 |              | $ | 509              |  | $ | 470
|                  |  |               |     |              |   |                  |  |   |    



The increase in
collateral postings since December 31, 2004 is primarily a result of a $53 million increase in postings for NGL. This increase is related to increases in commodity prices, as well as our transition from providing cash as collateral to providing
letters of credit as collateral. At June 30, 2005, we had both cash and letters of credit outstanding for the same exposure, resulting in an over-collateralized balance of $33 million which will no longer be advanced by the end of August. In
addition, the $43 million increase in GEN is primarily the result of increases in commodity prices and the volume of fuel purchased, as well as the reclassification of the Independence tolling arrangement and related collateral obligations from CRM
to GEN. These items were offset by a $26 million decrease in collateral posted in support of CRM, resulting primarily from the reclassification of the Independence tolling arrangement and related collateral obligations from CRM to GEN and the
rolloff of NYMEX positions. Finally, the remaining $10 million in collateral postings at our REG segment has been eliminated since December 31, 2004.



We have transitioned counterparty collateral demands from cash postings to letters of credit in order to replenish our cash balances after taking into
account (i) the closing of the Sithe Energies acquisition in January 2005, for which we paid $120 million, net of transaction costs and cash acquired, and (ii) our payment of $175 million in May 2005 and $80 million in July 2005 in connection with
the settlement of the shareholder class action and derivative litigation. As of December 31, 2004, approximately 80% of the aggregate collateral posted (or approximately $376 million) consisted of cash, compared to approximately 42% cash collateral
(or approximately $216 million) as of June 30, 2005 and 39% cash collateral (or approximately $209 million) as of August 4, 2005.



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, our anticipated
sale of DMSLP prior to the end of 2005 and forward hedging transactions, we believe that collateral requirements will be approximately $275 million at year-end 2005. We believe that we have sufficient capital resources to satisfy
counterparties collateral demands,



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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.



Contractual Obligations and Contingent Financial Commitments



We have incurred various contractual obligations and 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, 2004, with respect to which information is included in
our Form 10-K. As a result of the Sithe Energies acquisition, we have effectively eliminated the financial statement impact of commitments associated with the power tolling agreement and derivative contract held by Independence, which totaled $747
million as of December 31, 2004. Subsequent to the acquisition, these contracts have become intercompany agreements.



However, we have assumed additional contractual obligations as a result of the Sithe Energies acquisition, including (i) two additional gas supply
agreements under which we are obligated for $191 million through 2015, (ii) $919 million of face value project debt, which was recorded at its fair value of $797 million and (iii) an operating lease related to the Sithe Energies New York City office
space, which extends through 2011. We expect our future payments of $37 million under this lease to be partially offset by $19 million in future sublease rentals. Please see Note 2AcquisitionSithe Energies and Note
7DebtIndependence Debt for further discussion.



Additionally, as a result of the acquisition, we acquired four hydroelectric generation facilities in Pennsylvania. These facilities are subject to certain off-balance sheet commitments arising under operating leases for equipment and
project tracking accounts related to the sale of power.



As of
June 30, 2005, the equipment leases have remaining terms from two to sixteen years and involve a maximum aggregate obligation of $131 million over the terms of the leases. Each of the hydroelectric generation facilities is party to a long-term power
purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account, which we refer to as a Tracking Account, was established to quantify the difference between (i) the facilitys fixed
price revenues under the power purchase agreement and (ii) the respective utilitys Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement
calls for the facility to return to the utility the balance in the Tracking Account before the end of the facilitys life through decreased pricing under the respective power purchase agreement. Two of the four facilities are currently in the
Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs, exclusive of lease or
interest costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of June 30, 2005 was approximately $287 million, and the obligations with respect to each
Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts may cause the facilities to operate at a net cash deficit.



The obligations of the four facilities described in the preceding paragraph
are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of the facilities. The facilities are not consolidated by Dynegy for GAAP financial reporting
purposes under the provisions of FIN No. 46R.



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There were no other material changes to our contractual obligations and contingent financial commitments
since December 31, 2004.



As further discussed in Note
7DebtNatural Gas Liquids, upon the sale of DMSLP, we are required to repay the priority lien debt comprised of the $594 million term loan scheduled to mature in 2010 and the $189 million generation facility debt scheduled to mature in
2007.



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 on common stock for the first half of 2005 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 accrue dividends on our Series C
preferred stock at a rate of 5.5% per annum. These dividends are payable on the Series C preferred stock in February and August of each year, but we may defer payments for up to 10 consecutive semi-annual periods. If the holders of the Series C
preferred stock do not receive the full dividends to which they are entitled on any specified dividend payment date, then such unpaid dividends will be deferred, will cumulate and will accrue additional dividends at the rate of 5.5% per annum. In
February 2005, we made our semi-annual dividend payment of $11 million. In July 2005, we declared a dividend of $11 million to be paid on or before August 11, 2005. Please read Note 14Redeemable Preferred SecuritiesSeries C Convertible
Preferred Stock beginning on page F-54 of our Form 10-K for further discussion.



Pursuant to the indenture governing DHIs second priority senior secured notes, following the August 2005 expiration of the two-year grace period provided therein, we are permitted to pay dividends on the Series
C preferred stock only if we meet or exceed the fixed charge coverage ratio specified in such indenture. As a result, we may be required to defer payment of dividends on the Series C preferred stock beginning in February 2006.



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. Please see Note 7Debt for further discussion of our revolving credit facility.



Current Liquidity.The following table summarizes our
consolidated revolver capacity and liquidity position at August 4, 2005, June 30, 2005 and December 31, 2004:



|                                                              |  |               |      |        |              |   |      |                  |  |   |       |       
|------------------------------------------------------------- |  | ------------- | ---- | ------ | ------------ | - | ---- | ---------------- |  | - | ----- | ------
|                                                              |  | August 4,2005 |      |        | June 30,2005 |   |      | December 31,2004 | 
|                                                              |  | (in millions) |     
|Total revolver capacity                                       |  | $             | 700  |        |              | $ | 700  |                  |  | $ | 700   |       
|Outstanding letters of credit under revolving credit facility |  |               | (322 | )      |              |   | (293 | )                |  |   | (94   | )     
|                                                              |  |               |      |        |              |   |      |                  |  |   |       |       
|Unused revolver capacity                                      |  |               | 378  |        |              |   | 407  |                  |  |   | 606   |       
|Cash                                                          |  |               | 320  | (1)(2) |              |   | 358  | (1)(2)           |  |   | 628   | (1)(2)
|                                                              |  |               |      |        |              |   |      |                  |  |   |       |       
|Total available liquidity                                     |  | $             | 698  |        |              | $ | 765  | (3)              |  | $ | 1,234 |       
|                                                              |  |               |      |        |              |   |      |                  |  |   |       |       

---

|(1) | The August 4, 2005, June 30, 2005 and December 31, 2004 amounts include approximately $31 million, $32 million and $47 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.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | The August 4, 2005, June 30, 2005 and December 31, 2004 amounts include approximately $14 million, $16 million and $13 million, respectively, of cash held by our NGL business. See
Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|(3) | The decrease in liquidity from December 31, 2004 to June 30, 2005 is primarily due to (i) cash paid for the Sithe acquisition of $120 million, net of cash acquired, (ii) our payment
of $175 million in May 2005 in connection with the settlement of the shareholder class action litigation and (iii) capital expenditures of $93 million.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Cash Flows from Operations. We had operating cash outflows of $9 million in the six months ended June 30,
2005. This consisted of $372 million in operating cash flows from our GEN and NGL segments, reflecting positive earnings for the period. The cash flows from our operating segments were more than offset by $381 million of cash outflows relating to
our CRM business and corporate-level expenses. Please read Results of OperationsOperating Income (Loss) and Cash Flow Disclosures for further discussion of factors impacting our operating cash flows for the
periods presented.



For 2005, we have projected operating cash
outflows of $43 to $33 million. This projection, which is subject to change based on a number of factors, many of which are beyond our control, reflects $725 to $730 million in forecasted operating cash flows from our GEN and NGL business segments,
offset by projected cash outflows of $31 million from our CRM business segment and $737 to $732 million in corporate-level expenses, including $435 million of interest.



Upon the anticipated sale of DMSLP, cash interest expense associated with the term loan and the generation facility debt
will be eliminated, as these instruments will be repaid immediately. However, until the remaining cash proceeds from the sale are re-invested or utilized in a liability management program, as more fully described in Note 7DebtNatural Gas
Liquids, the interest income from the cash proceeds will be more than offset by the reduced operating cash flows from the NGL business.



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, we entered into long-term rail transportation contracts and commodities contracts that will reduce our exposure to future changes in costs associated with fuel procurement at our coal-fired
generation facilities in the Midwest; however, these fee reductions were substantially offset by continued high fuel prices in the Northeast and higher costs associated with the purchase of emission credits. Our ability to achieve fuel-related and
other targeted cost savings in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, will impact our future operating cash flows. Please read Results of
OperationsOutlookGEN Outlook for further discussion.



In addition, our CDWR power purchase agreement expired by its terms in December 2004. Please read Item 1.Business Segment DiscussionPower Generation beginning on page 2 of our Form 10-K for a
discussion of West Coast Powers current contractual arrangements. Our share of West Coast Powers earnings during 2004, excluding impairments of $85 million, totaled $165 million, approximately 70% of which was derived from the CDWR
agreement. Cash distributions from this investment totaled $103 million in 2004. Although we received a cash distribution of $52 million in April 2005, as the partnership distributed cash in excess of its operating requirements, we expect future
cash distributions from West Coast Power to be significantly less.In Californias current energy market, the West Coast Power generating facilities which previously supported the CDWR contract are significantly less profitable under the
RMR contracts or as merchant facilities, and we may consider other alternatives if necessary, including shutting down units if we no longer consider them commercially viable. For instance, we determined that it was not economically feasible to
continue operating our Long Beach generation facility beyond the expiration of the CDWR contract, so we retired the asset effective January 1, 2005.



Cash on Hand. At August 4, 2005 and June 30, 2005, we had cash on hand of $320 million and $358 million, respectively, as compared to $628
million at the end of 2004. This decrease in cash on hand as compared to the end of 2004 is primarily attributable to (i) the closing of the Sithe Energies acquisition in January 2005,



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for which we paid $120 million, net of business acquisition costs and cash acquired and (ii) our payments of $175 million in May 2005 and $80 million in July
2005 in connection with the settlement of the shareholder class action and derivative litigation, partially offset by the return of cash collateral as a result of our transition to letters of credit.



Revolver Capacity. In May 2004, DHI entered into a $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 August 4, 2005, we had $322 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 11DebtDHI Term Loan and
Credit Facility beginning on page F-43 of our Form 10-K for further discussion of our credit facility.



In connection with the sale of DMSLP, we anticipate amending or replacing our current revolving credit facility with a new, smaller facility that, when
collateralized with cash, gives us the ability to post letters of credit. Please read Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids for further discussion.



External Liquidity Sources



Over the last twelve months, our primary external liquidity source has been
proceeds from asset sales. Looking forward, we expect our primary external liquidity sources to be proceeds from asset sales and other types of capital-raising transactions, including potential equity issuances.



Asset Sale Proceeds.On August 2, 2005, we entered into an
agreement to sell DMSLP for an estimated $2.475 billion in cash proceeds. Please read Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids for further discussion.



Upon repayment of the credit facility ($594 million scheduled
to mature in 2010), we must also repay the generation facility ($189 scheduled to mature 2007). As of June 30, 2005, there were no borrowings outstanding under our $700 million revolving credit facility. We anticipate amending or replacing our
current revolving credit facility with a new, smaller facility that, when collateralized with cash, gives us the ability to post letters of credit.



Under the terms of the SPNs, we can elect to use the balance of the proceeds to (i) repay parity lien debt, provided that any offer to repay parity lien
debt holders is made on a pro rata basis, or (ii) make a capital expenditure or invest in various types of assets defined as Replacement Assets in the SPN indenture. Any net proceeds from a sale of DMSLP that are not applied or invested in the
manner described above constitute Excess Proceeds. If Excess Proceeds exceed $50 million, we must within 365 days from the closing of the sale, offer to use the proceeds to repurchase the SPNs at par. Sales proceeds remaining after such an offer can
be used for any purpose not otherwise restricted by the SPN indenture. We will evaluate alternative uses for the remaining proceeds from the transaction, such as reducing our outstanding debt or other obligations to further deleverage our capital
structure to position our GEN business favorably in relation to future combination or consolidation opportunities.



In an effort to maximize our return on investment and to further clarify our business strategy, we have previously sold assets that we did not consider
core to our operations. The aggregate loss of earnings in 2004 associated with these assets (other than Illinois Power) was not material and was more than offset by net gains on sale in 2004. However, beginning in 2005, the lost earnings, before
consideration of interest savings, of approximately $15 million annually from such assets will no longer be offset by gains on sale.



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Capital-Raising Transactions.As part of our ongoing efforts to move toward 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 will continue to consider 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 strategic growth opportunities, legal judgments or regulatory requirements, which could 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. We do not anticipate that this availability will be reduced by
the issuance of 17,578,781 shares of Dynegy Class A common stock pursuant to the settlement of the shareholder class action litigation, as such issuance will be exempt from registration under the Securities Act of 1933. 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 would likely have other effects as well, including shareholder dilution. Further, our ability to issue debt securities is limited by our financing agreements, including our credit facility. Please read Note
11DebtDHI Term Loan and Credit Facility beginning on page F-43 of our Form 10-K for further discussion.



Conclusion



For the remainder of 2005, we intend to continue to meet our customer and supplier commitments and operate our business safely, reliably and efficiently.
We will maintain our focus on fiscal discipline and manage our costs and capital expenditures. We will continually review our portfolio to seek ways to improve our return on capital employed. We will continue to work toward a sustainable capital
structure in line with our underlying business risks. Finally, we will consider fiscally responsible growth and sector consolidation opportunities that will add scale and scope to our business.



As previously indicated, our decision to sell DMSLP could positively impact
the future of our power generation business. The sale of DMSLP will be a tax efficient sale, as tax benefits, including net operating losses and capital loss-carryforwards provide us with a large tax asset position. By utilizing these tax attributes
to offset the gain from the sale of DMSLP, we maximize our after-tax proceeds.



The proceeds from the transaction will enable us to further improve our overall financial condition and liquidity position, as well as significantly lower our net debt-to-capital ratio. These benefits will position
our power generation business with a more sustainable capital structure, stronger business platform and the flexibility to consider new strategic directions  be it either organic growth, growth through opportunistic expansion and/or
participation in power sector consolidation or combination.



Our desire or ability to pursue any such opportunities is subject to a number of factors beyond our control. As such, we cannot guarantee that any such strategic direction(s) will be available to us, nor can we predict with any degree of
certainty the impact of any such strategic direction(s) on our financial condition or results of operations. In the meantime, however, we intend to remain focused on meeting our customers energy services and supply needs in a safe, reliable
and efficient manner.



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 37 of our Form
10-K, we detailed the primary factors that have impacted, and are expected to



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continue to impact, the earnings and cash flows from our business segments and other operations. Our results of operations during the remainder of 2005 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 relationship between prices for natural gas liquids and natural gas;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 long-term payment obligations associated with our remaining unrestructured power tolling arrangement, the restructuring or termination of
which likely would require a significant cash payment;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | Our ability to consummate the agreed upon sale of DMSLP on the terms and in the timeframes anticipated;
| | - |  | -------------------------------------------------------------------------------------------------------



| |  |  | Our ability to achieve our financial and operational goals associated with the Sithe Energies acquisition; and
| | - |  | --------------------------------------------------------------------------------------------------------------



| |  |  | Our ability to participate in growth opportunities in the power sector.
| | - |  | -----------------------------------------------------------------------



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



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 six-month periods ended June 30, 2005 and 2004. At the end of this section, we have 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.



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Three Months Ended June 30, 2005 and 2004



Summary Financial Information.The following tables provide summary financial data regarding our consolidated
and segmented results of operations for the three-month periods ended June 30, 2005 and 2004, respectively:



Quarter Ended June 30, 2005



|                                                  |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   |      |  
|------------------------------------------------- |  | ------------- | -- | --- | - | --- |  | --- | - |  | --------------------- | --- | - | ----- | - | --- | - |  | - | ---- | -
|                                                  |  | GEN           |    | NGL |   | REG |  | CRM |   |  | Other andEliminations |     |   | Total |  
|                                                  |  | (in millions) |   
|Operating income (loss)                           |  | $             | 19 |     | $ |    |  | $   |  |  | $                     | (15 | ) |       | $ | (68 | ) |  | $ | (64  | )
|Earnings from unconsolidated investments          |  |               | 4  |     |   |    |  |     |  |  |                       |    |   |       |   |    |   |  |   | 4    |  
|Other items, net                                  |  |               | 2  |     |   |    |  |     |  |  |                       | (1  | ) |       |   | 5   |   |  |   | 6    |  
|Interest expense                                  |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   | (96  | )
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   |      |  
|Loss from continuing operations before taxes      |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   | (150 | )
|Income tax benefit                                |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   | 41   |  
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   |      |  
|Loss from continuing operations                   |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   | (109 | )
|Income from discontinued operations, net of taxes |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   | 147  |  
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   |      |  
|Net income                                        |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  | $ | 38   |  
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |     |   |       |   |     |   |  |   |      |  



Quarter Ended June
30, 2004



|                                                  |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   |      |  
|------------------------------------------------- |  | ------------- | -- | --- | - | --- |  | --- | -- |  | --------------------- | -- | - | ----- | - | --- | - |  | - | ---- | -
|                                                  |  | GEN           |    | NGL |   | REG |  | CRM |    |  | Other andEliminations |    |   | Total |  
|                                                  |  | (in millions) |   
|Operating income (loss)                           |  | $             | 35 |     | $ |    |  | $   | 22 |  | $                     | 90 |   |       | $ | (91 | ) |  | $ | 56   |  
|Earnings from unconsolidated investments          |  |               | 50 |     |   |    |  |     |   |  |                       |   |   |       |   |    |   |  |   | 50   |  
|Other items, net                                  |  |               |   |     |   |    |  |     |   |  |                       | (1 | ) |       |   | (8  | ) |  |   | (9   | )
|Interest expense                                  |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   | (141 | )
|                                                  |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   |      |  
|Loss from continuing operations before taxes      |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   | (44  | )
|Income tax benefit                                |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   | 29   |  
|                                                  |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   |      |  
|Loss from continuing operations                   |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   | (15  | )
|Income from discontinued operations, net of taxes |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   | 23   |  
|                                                  |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   |      |  
|Net income                                        |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  | $ | 8    |  
|                                                  |  |               |    |     |   |     |  |     |    |  |                       |    |   |       |   |     |   |  |   |      |  



The following table
provides summary segmented operating statistics for the three months ended June 30, 2005 and 2004, respectively:



|                                                  |  |                        |      |      |   |     
|------------------------------------------------- |  | ---------------------- | ---- | ---- | - | ----
|                                                  |  | Quarter Ended June 30,
|                                                  |  | 2005                   |      | 2004
|Power Generation                                  |  |                        |      |      |   |     
|Million megawatt hours generatedgross            |  |                        | 8.6  |      |   | 9.0 
|Million megawatt hours generatednet              |  |                        | 8.3  |      |   | 8.6 
|Average natural gas priceHenry Hub ($/MMBtu) (1) |  | $                      | 6.94 |      | $ | 6.09
|Average on-peak market power prices ($/MW hour)   |  |                        |      |      |   |     
|Cinergy                                           |  | $                      | 54   |      | $ | 45  
|NI Hub/ComEd                                      |  | $                      | 52   |      | $ | 44  
|Southern                                          |  | $                      | 57   |      | $ | 52  
|New YorkZone G                                   |  | $                      | 78   |      | $ | 63  
|New YorkZone A                                   |  | $                      | 62   |      | $ | 53  
|ERCOT                                             |  | $                      | 68   |      | $ | 54  
|SP-15                                             |  | $                      | 55   |      | $ | 55  



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|                                              |  |                        |         |      |   |        
|--------------------------------------------- |  | ---------------------- | ------- | ---- | - | -------
|                                              |  | Quarter Ended June 30,
|                                              |  | 2005                   |         | 2004
|Natural Gas Liquids                           |  |                        |         |      |   |        
|Gross NGL production (MBbls/d):               |  |                        |         |      |   |        
|Field plants                                  |  |                        | 58.0    |      |   | 56.1   
|Straddle plants                               |  |                        | 28.6    |      |   | 23.6   
|                                              |  |                        |         |      |   |        
|Total gross NGL production                    |  |                        | 86.6    |      |   | 79.7   
|                                              |  |                        |         |      |   |        
|Natural gas (residue) sales (Bbtu/d)          |  |                        | 181.1   |      |   | 181.9  
|                                              |  |                       
|Natural gas inlet volumes (MMCFD):            |  |                        |         |      |   |        
|Field plants                                  |  |                        | 516.3   |      |   | 529.9  
|Straddle plants                               |  |                        | 1,212.5 |      |   | 785.1  
|                                              |  |                        |         |      |   |        
|Total natural gas inlet volumes               |  |                        | 1,728.8 |      |   | 1,315.0
|                                              |  |                        |         |      |   |        
|Fractionation volumes (MBbls/d)               |  |                        | 176.6   |      |   | 213.1  
|Natural gas liquids sold (MBbls/d)            |  |                        | 242.2   |      |   | 252.3  
|Average commodity prices:                     |  |                        |         |      |   |        
|Crude oilWTI ($/Bbl)                         |  | $                      | 51.96   |      | $ | 38.51  
|Natural gasHenry Hub ($/MMBtu) (2)           |  | $                      | 6.74    |      | $ | 6.00   
|Natural gas liquids ($/Gal)                   |  | $                      | 0.79    |      | $ | 0.64   
|Fractionation spread ($/MMBtu)daily          |  | $                      | 1.97    |      | $ | 1.15   
|                                              |  |                       
|Regulated Energy Delivery (3)                 |  |                        |         |      |   |        
|Electric sales in KWH (millions)              |  |                        |         |      |   |        
|Residential                                   |  |                        |        |      |   | 1,135  
|Commercial                                    |  |                        |        |      |   | 1,118  
|Industrial                                    |  |                        |        |      |   | 1,371  
|Transportation of customer-owned electricity  |  |                        |        |      |   | 803    
|Other                                         |  |                        |        |      |   | 90     
|                                              |  |                        |         |      |   |        
|Total electric sales                          |  |                        |        |      |   | 4,517  
|                                              |  |                        |         |      |   |        
|Gas sales in Therms (millions)                |  |                        |         |      |   |        
|Residential                                   |  |                        |        |      |   | 34     
|Commercial                                    |  |                        |        |      |   | 16     
|Industrial                                    |  |                        |        |      |   | 10     
|Transportation of customer-owned gas          |  |                        |        |      |   | 56     
|                                              |  |                        |         |      |   |        
|Total gas delivered                           |  |                        |        |      |   | 116    
|                                              |  |                        |         |      |   |        
|Cooling degree days  actual (4)              |  |                        |        |      |   | 373    
|Cooling degree days  10-year rolling average |  |                        |        |      |   | 373    
|Heating degree daysactual (5)                |  |                        |        |      |   | 388    
|Heating degree days10-year rolling average   |  |                        |        |      |   | 453    

---

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

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

|(3) | We sold Illinois Power, our regulated utility, to Ameren on September 30, 2004.
|--- | -------------------------------------------------------------------------------

|(4) | 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.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) | 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.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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The following tables summarize significant items on a pre-tax basis, with the exception of the 2005 and
2004 tax items, affecting net income for the periods presented.



|                                        |  |                             |   |     |   |     |  |   |     |   |       |   |    |       |   |     |   |  |   |     |  
|--------------------------------------- |  | --------------------------- | - | --- | - | --- |  | - | --- | - | ----- | - | -- | ----- | - | --- | - |  | - | --- | -
|                                        |  | Quarter Ended June 30, 2005 |  
|                                        |  | GEN                         |   | NGL |   | REG |  |   | CRM |   | Other |   |    | Total |  
|                                        |  | (in millions)               |  
|Legal and settlement charges            |  | $                           |  |     | $ |    |  | $ |    |   |       | $ |   |       | $ | (31 | ) |  | $ | (31 | )
|Independence toll settlement adjustment |  |                             |  |     |   |    |  |   |    |   |       |   | 13 |       |   |    |   |  |   | 13  |  
|Discontinued operations                 |  |                             |  |     |   | 35  |  |   |    |   |       |   | 1  |       |   |    |   |  |   | 36  |  
|Taxes                                   |  |                             |  |     |   |    |  |   |    |   |       |   |   |       |   | 112 |   |  |   | 112 |  
|                                        |  |                             |   |     |   |     |  |   |     |   |       |   |    |       |   |     |   |  |   |     |  
|Total                                   |  | $                           |  |     | $ | 35  |  | $ |    |   |       | $ | 14 |       | $ | 81  |   |  | $ | 130 |  
|                                        |  |                             |   |     |   |     |  |   |     |   |       |   |    |       |   |     |   |  |   |     |  
|                                        | 
|                                        |  | Quarter Ended June 30, 2004 |  
|                                        |  | GEN                         |   | NGL |   | REG |  |   | CRM |   | Other |   |    | Total |  
|                                        |  | (in millions)               |  
|Illinois Power asset impairment         |  | $                           |  |     | $ |    |  | $ | (48 | ) |       | $ |   |       | $ |    |   |  | $ | (48 | )
|Legal and settlement charges            |  |                             |  |     |   |    |  |   | 1   |   |       |   |   |       |   | (42 | ) |  |   | (41 | )
|Acceleration of financing costs         |  |                             |  |     |   |    |  |   |    |   |       |   |   |       |   | (14 | ) |  |   | (14 | )
|Taxes                                   |  |                             |  |     |   |    |  |   |    |   |       |   |   |       |   | (9  | ) |  |   | (9  | )
|Gas transportation contracts            |  |                             |  |     |   |    |  |   |    |   |       |   | 88 |       |   |    |   |  |   | 88  |  
|Discontinued operations                 |  |                             |  |     |   | 70  |  |   |    |   |       |   | 1  |       |   |    |   |  |   | 71  |  
|                                        |  |                             |   |     |   |     |  |   |     |   |       |   |    |       |   |     |   |  |   |     |  
|Total                                   |  | $                           |  |     | $ | 70  |  | $ | (47 | ) |       | $ | 89 |       | $ | (65 | ) |  | $ | 47  |  
|                                        |  |                             |   |     |   |     |  |   |     |   |       |   |    |       |   |     |   |  |   |     |  



Operating
Income/Loss



Operating loss was $64 million for the
quarter ended June 30, 2005, compared to operating income of $56 million for the quarter ended June 30, 2004.



GEN.Operating income for our GEN segment was $19 million for the three months ended June 30, 2005, compared to $35 million for the three
months ended June 30, 2004.



In the Midwest-MAIN region, where
we produce approximately 60% of our generated volumes, results decreased $7 million year over year, from $100 million for the second quarter 2004 to $93 million for the second quarter 2005. Volumes were up 11%, from 4.8 million MWh for the second
quarter 2004 to 5.4 million MWh for the second quarter 2005. Additionally, the Midwest regions results for the second quarter 2005 include a $3 million benefit from mark-to-market income, primarily in connection with hedge ineffectiveness,
compared with a mark-to-market loss of $1 million for the second quarter 2004. However, although energy consumed by AmerenIP was more than 35% higher in 2005s second quarter than in 2004, incremental energy sold to AmerenIP under this power
purchase agreement, that expires at the end of 2006, is priced significantly below current on-peak market prices. Additionally, operating expenses were up $2 million over the prior year, as a result of the timing of maintenance expense.



Earnings were also down in the Northeast region, where results declined
from a loss of $3 million for the three months ended June 30, 2004 to a loss of $4 million for the same period in 2005. Beginning in February 2005, our Northeast regions results include earnings from the Independence facility. See Note
2AcquisitionSithe Energies for further discussion of the acquisition of Independence. For the second quarter of 2005, earnings for the Independence facility were $3 million. However, earnings at our existing Northeast facilities declined
as a result of increased operating expense and decreased volumes at our Roseton facility. Volumes at Roseton decreased 0.4 million MWh, primarily due to compressed margins resulting from an increase in the price of fuel oil in relation to the price
of generated power. Operating expense increased by $4 million at our existing facilities, primarily related to the timing of maintenance expense. Total volumes for the region inclusive of our



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Independence facility were up slightly, from 1.4 million MWh in the second quarter 2004 to 1.5 million MWh for the same period in 2005, as additional volumes
resulting from the acquisition of the Independence facility were largely offset by the decrease at the Roseton facility. The decrease in generated volumes and increase in operating expense was partially mitigated as average on-peak prices were up
24% in the market served by our Danskammer and Roseton facilities. Our Northeast results for the second quarter of 2005 include a mark-to-market charge of $2 million in connection with hedge ineffectiveness.



Results for our peaking facilities in the Midwest-ECAR region were improved
by $3 million, from a loss of $1 million for the second quarter 2004 to earnings of $2 million for 2005. This improvement was a result of both favorable pricing and an increase in volumes. Results in our Southeast region decreased by $1 million,
from earnings of $1 million for the second quarter 2004 to zero for 2005, as a result of decreased volumes. Results in our Texas region improved by $7 million, from a loss of $4 million for the second quarter 2004 to earnings of $3 million for the
second quarter 2005. Earnings in the Texas Region during 2005 included a charge of $2 million related to hedge ineffectiveness. Although natural gas prices have remained high, power prices increased by 26% compared to 2004, resulting in improved
spark spreads. Additionally, we were able to mitigate the negative impact of high gas prices by providing additional ancillary services to the market.



General and administrative expense increased from $14 million for the three months ended June 30, 2004 to $19 million for the same period in 2005. The
increase is primarily the result of expense associated with the New York City office we acquired in our Sithe Energies acquisition, which we are in the process of closing. Depreciation expense increased from $47 million for the second quarter 2004
to $50 million for the second quarter 2005, primarily as a result of depreciation associated with the Independence facility acquired in 2005. Additionally, our 2005 results include a $7 million charge associated with the write-off of an
environmental project.



GENs reported operating income
for the three-month periods ended June 30, 2005 and 2004 also includes approximately $1 million and zero, respectively, of mark-to-market losses in addition to those discussed above, related to purchases and sales that did not meet the criteria for
hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market basis.



REG. Operating income for the REG segment was $22 million for the quarter ended June 30, 2004. We sold Illinois Power to Ameren on September
30, 2004. The 2004 period includes a $48 million charge related to an asset impairment at Illinois Power.



CRM.Operating loss for the CRM segment was $15 million for the quarter ended June 30, 2005, compared to operating income of $90 million in
2004.



In the second quarter 2005, we substantially completed
the determination of the tax basis of the assets and liabilities acquired in connection with our purchase of Sithe Energies, and we do not expect any material changes to our purchase price allocation. Prior to the acquisition, Independence held a
power tolling contract and a gas supply agreement with our CRM segment. Upon completion of the purchase, these contracts became intercompany agreements under our GEN segment, and were effectively eliminated on a consolidated basis, resulting in a
$183 million charge recorded in the first quarter of 2005. In the second quarter of 2005, we revised the purchase price allocation, which resulted in a $13 million reduction of the charge recorded in the first quarter, resulting in a net charge of
$170 million. Results for the second quarter 2005 reflect $22 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold, as well as net mark-to-market losses of $6 million on our
legacy coal, gas and power positions.



2004 results included an
$88 million gain related to our exit of four natural gas transportation contracts. In addition, results for the second quarter 2004 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. Additionally, our results include net mark-to-market-gains of $13 million on our legacy coal, gas and power positions. These



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gains were partly offset by $22 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and
sold.



Other. Other operating loss was $68
million for the quarter ended June 30, 2005, compared to a loss of $91 million for the quarter ended June 30, 2004. Results for 2005 include an $18 million charge associated with the recent settlement of our shareholder class action litigation and
other legal and settlement charges totaling $13 million. For more information, please read Note 10Commitment and ContingenciesShareholder Litigation. Results for 2004 include approximately $42 million of expenses related to increased
legal and severance reserves. The increased legal reserves resulted from additional activities during the quarter that affected managements assessment of the probable and estimable loss associated with the applicable proceedings. In addition,
2005 results benefited from lower compensation, insurance and external consultant costs compared to the same period in 2004.



Earnings from Unconsolidated Investments



Our earnings from unconsolidated investments were approximately $4 million for the quarter ended June 30, 2005, compared to $50 million for the quarter
ended June 30, 2004. Our West Coast Power investment was the primary driver of the decrease. Total earnings from this investment were approximately $1 million for the three months ended June 30, 2005, compared to $47 million for the same period in
2004. The decrease in earnings is primarily the result of the expiration of West Coast Powers CDWR contract at the end of 2004. Please read Item 1. BusinessSegment DiscussionPower Generation beginning on page 2 of our Form 10-K for
a discussion of West Coast Powers current contractual arrangements.



Other Items, Net



Other items, net, totaled $6 million of income for the quarter ended June 30, 2005, compared to an expense of $9 million for the quarter ended June 30, 2004. The increase is primarily a result of mark-to-market losses recognized in the
second quarter 2004 associated with interest rate swaps as well as higher interest income in the second quarter 2005 due to higher interest rates.



Interest Expense



Interest expense totaled $96 million for the quarter ended June 30, 2005, compared to $141 million for the quarter ended June 30, 2004. The significant
decrease is primarily attributable to the sale of Illinois Power in September 2004.



Income Tax Benefit



We reported an income tax benefit during the quarter ended June 30, 2005 of $41 million compared to $29 million for the quarter ended June 30, 2004.The income tax benefit in 2005 includes a $13 million expense, primarily related to
an adjustment to the effective state rate and an increase to the valuation allowance. The income tax benefit in 2004 includes an $11 million benefit associated primarily with reducing a valuation allowance related to our capital loss carryforward.
We reduced the valuation allowance related to our capital loss carryforward as a result of capital gains expected to be recognized from anticipated non-core asset sales in 2004. Excluding these items, the 2005 and 2004 effective tax rates would be
36% and 41%, respectively. 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 differences.



Discontinued Operations



Discontinued operations includes our NGL business in our NGL segment, our
U.K. CRM business in our CRM segment and our communications business in Other and Eliminations. The following summarizes the activity included in income from discontinued operations:



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Quarter Ended June 30, 2005



|                                                                                         |  |               |   |     |   |     |  |   |       |   |  |   |     |  
|---------------------------------------------------------------------------------------- |  | ------------- | - | --- | - | --- |  | - | ----- | - |  | - | --- | -
|                                                                                         |  | U.K. CRM      |   | DGC |   | NGL |  |   | Total |  
|                                                                                         |  | (in millions) |  
|Operating income included in income from discontinued operations                         |  | $             | 1 |     | $ |    |  | $ | 53    |   |  | $ | 54  |  
|Earnings from unconsolidated investments included in income from discontinued operations |  |               |  |     |   |    |  |   | 2     |   |  |   | 2   |  
|Other items, net included in income from discontinued operations                         |  |               |  |     |   |    |  |   | (6    | ) |  |   | (6  | )
|Interest expense included in income from discontinued operations                         |  |               |   |     |   |     |  |   |       |   |  |   | (14 | )
|                                                                                         |  |               |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |   |     |   |     |  |   |       |   |  |   | 36  |  
|Income tax benefit                                                                       |  |               |   |     |   |     |  |   |       |   |  |   | 111 |  
|                                                                                         |  |               |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations                                                      |  |               |   |     |   |     |  |   |       |   |  | $ | 147 |  
|                                                                                         |  |               |   |     |   |     |  |   |       |   |  |   |     |  



Quarter Ended June
30, 2004



|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|---------------------------------------------------------------------------------------- |  | ------------- | -- | - | --- | - | --- |  | - | ----- | - |  | - | --- | -
|                                                                                         |  | U.K. CRM      |    |   | DGC |   | NGL |  |   | Total |  
|                                                                                         |  | (in millions) |   
|Operating income included in income from discontinued operations                         |  | $             | 2  |   |     | $ |    |  | $ | 77    |   |  | $ | 79  |  
|Earnings from unconsolidated investments included in income from discontinued operations |  |               |   |   |     |   |    |  |   | 2     |   |  |   | 2   |  
|Other items, net included in income from discontinued operations                         |  |               | (1 | ) |     |   |    |  |   | (5    | ) |  |   | (6  | )
|Interest expense included in income from discontinued operations                         |  |               |    |   |     |   |     |  |   |       |   |  |   | (4  | )
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |    |   |     |   |     |  |   |       |   |  |   | 71  |  
|Income tax expense                                                                       |  |               |    |   |     |   |     |  |   |       |   |  |   | (48 | )
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations                                                      |  |               |    |   |     |   |     |  |   |       |   |  | $ | 23  |  
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  



Income from
discontinued operations before taxes. Income from discontinued operations before taxes was primarily driven by the results of operations of our NGL segment, which was reclassified to discontinued operations due to the anticipated sale of
DMSLP. For further information regarding the sale, please see Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids.



Operating income for the NGL segment was $53 million for the quarter ended
June 30, 2005, compared to $77 million in the quarter ended June 30, 2004. Operating income for the quarter ended June 30, 2004 included a $36 million gain associated with the sale of our financial interest in Indian Basin.



Gathering and processing operating results increased by $16 million for the
quarter ended June 30, 2005 compared to the quarter ended June 30, 2004, primarily benefiting from 12% higher absolute commodity prices for natural gas and 23% higher absolute commodity prices for natural gas liquids year over year. At our field
plants, results increased $13 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from higher prices. Operating results for the quarter ended June 30, 2004 included $2 million in operating margin from our
Sherman plant, which was sold in November 2004. At our straddle plants, operating results increased $3 million, due largely to the impact of higher natural gas liquids prices under our POL contract settlements.



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Results of our fractionation, storage and terminalling and transportation and logistics businesses
decreased $4 million for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. Overall fractionation volumes decreased period over period due to the loss of a large fractionation customer at the end of September 2004 at our
Cedar Bayou Fractionator. This was partially offset by increased fractionation volumes at our Lake Charles Fractionator caused by industry-wide increased liquids production in Louisiana primarily as a result of higher frac spreads.



Wholesale marketing results were $1 million unfavorable for the quarter ended
June 30, 2005 compared to the quarter ended June 30, 2004, primarily as a result of the first quarter 2005 buyout of a refinery services contract. Higher natural gas liquids prices contributed higher earnings on our net back refinery services
contracts.



NGL marketing services and distribution results
decreased approximately $13 million for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. Although average natural gas liquids prices were higher in the quarter ended June 30, 2005 compared to the quarter ended June 30,
2004, sharp declines in natural gas liquids prices during the quarter ended June 30, 2005 contributed to lower marketing margins. Further, although within acceptable measurement tolerances, natural gas liquids well losses also contributed to lower
marketing margins during the quarter ended June 30, 2005. In addition, in the second quarter 2004, we terminated an inactive natural gas liquids sales contract which allowed us to recognize a $6 million gain on sales of natural gas liquids at
current market prices previously held outside our normal inventory at historic below-current market prices.



Depreciation and amortization expense decreased $10 million for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. We stopped
depreciating our NGL assets on June 1, 2005, as they are classified as held for sale, which resulted in reduced depreciation of $7 million during the quarter ended June 30, 2005. In addition, depreciation expense in the quarter ended June 30, 2004
included a $6 million charge related to an adjustment to accumulated depreciation.



At both June 2005 and June 2004, we tested certain of our assets for impairment based on the identification of triggering events as defined by SFAS No. 144. After testing, we recorded a pre-tax impairment of $5
million for our Puckett gas treating plant and gathering system due to rapidly depleting reserves associated with that facility in the second quarter 2004. We concluded that no impairment was necessary for any of the other facilities in either
period as estimated undiscounted cash flows exceeded facility book values.



Interest expense included in income from discontinued operations includes interest incurred on our $594 million Term Loan scheduled to mature in 2010 and our $189 million Generation facility debt scheduled to mature
in 2007. In accordance with EITF Issue 87-24, Allocation of Interest to Discontinued Operations, we have allocated interest expense associated with these two debt instruments to discontinued operations, as they are required to be paid
upon the sale of DMSLP. The increase in interest expense is due primarily to the Term Loan, which was entered into on May 28, 2004. As a result, 2004 results include one month of interest, compared to three months of interest in 2005.



Income tax benefit (expense) from discontinued operations. The
income tax benefit in 2005 includes a $125 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of NNG. We reduced the valuation allowance
related to our capital loss carryforward as a result of capital gains expected to be recognized from our anticipated sale of DMSLP. For further information regarding the sale, please see Note 3Discontinued Operations, Dispositions and Contract
TerminationsDiscontinued OperationsNatural Gas Liquids. The income tax expense in 2004 includes $20 million in tax expenses related to the conclusion of prior year tax audits. Please see Note 13Income TaxesPrior Year Tax
Audits for further discussion. Excluding these items, the 2005 and 2004 effective tax rates would be 37% and 39%, respectively. 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 differences.



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Six Months Ended June 30, 2005 and 2004



The following tables provide summary financial data regarding our consolidated and segmented results of operations for the
six-month periods ended June 30, 2005 and 2004, respectively.



Six Months Ended June 30, 2005



|                                                  |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|------------------------------------------------- |  | ------------- | -- | --- | - | --- |  | --- | - |  | --------------------- | ---- | - | ----- | - | ---- | - |  | - | ---- | -
|                                                  |  | GEN           |    | NGL |   | REG |  | CRM |   |  | Other andEliminations |      |   | Total |  
|                                                  |  | (in millions) |   
|Operating income (loss)                           |  | $             | 79 |     | $ |    |  | $   |  |  | $                     | (207 | ) |       | $ | (321 | ) |  | $ | (449 | )
|Earnings from unconsolidated investments          |  |               | 7  |     |   |    |  |     |  |  |                       |     |   |       |   |     |   |  |   | 7    |  
|Other items, net                                  |  |               | 2  |     |   |    |  |     |  |  |                       |     |   |       |   | 7    |   |  |   | 9    |  
|Interest expense                                  |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   | (185 | )
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|Loss from continuing operations before taxes      |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   | (618 | )
|Income tax benefit                                |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   | 215  |  
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|Loss from continuing operations                   |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   | (403 | )
|Income from discontinued operations, net of taxes |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   | 179  |  
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|Net loss                                          |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  | $ | (224 | )
|                                                  |  |               |    |     |   |     |  |     |   |  |                       |      |   |       |   |      |   |  |   |      |  



Six Months Ended
June 30, 2004



|                                                  |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   |      |  
|------------------------------------------------- |  | ------------- | -- | --- | - | --- |  | --- | -- | --------------------- | - | -- | ----- | - | ---- | - |  | - | ---- | -
|                                                  |  | GEN           |    | NGL |   | REG |  | CRM |    | Other andEliminations |   |    | Total |  
|                                                  |  | (in millions) |   
|Operating income (loss)                           |  | $             | 88 |     | $ |    |  | $   | 76 |                       | $ | 77 |       | $ | (145 | ) |  | $ | 96   |  
|Earnings from unconsolidated investments          |  |               | 88 |     |   |    |  |     |   |                       |   |   |       |   |     |   |  |   | 88   |  
|Other items, net                                  |  |               |   |     |   |    |  |     | 1  |                       |   | 2  |       |   | 3    |   |  |   | 6    |  
|Interest expense                                  |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   | (271 | )
|                                                  |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   |      |  
|Loss from continuing operations before taxes      |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   | (81  | )
|Income tax benefit                                |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   | 82   |  
|                                                  |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   |      |  
|Income from continuing operations                 |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   | 1    |  
|Income from discontinued operations, net of taxes |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   | 77   |  
|                                                  |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   |      |  
|Net income                                        |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  | $ | 78   |  
|                                                  |  |               |    |     |   |     |  |     |    |                       |   |    |       |   |      |   |  |   |      |  



The following table
provides summary segmented operating statistics for the six months ended June 30, 2005 and 2004, respectively.



|                                                  |  |                           |      |      |   |     
|------------------------------------------------- |  | ------------------------- | ---- | ---- | - | ----
|                                                  |  | Six Months Ended June 30,
|                                                  |  | 2005                      |      | 2004
|Power Generation                                  |  |                           |      |      |   |     
|Million megawatt hours generatedgross            |  |                           | 17.5 |      |   | 19.6
|Million megawatt hours generatednet              |  |                           | 16.7 |      |   | 18.7
|Average natural gas priceHenry Hub ($/MMBtu) (1) |  | $                         | 6.67 |      | $ | 5.86
|Average on-peak market power prices ($/MW hour)   |  |                           |      |      |   |     
|Cinergy                                           |  | $                         | 52   |      | $ | 43  
|NI Hub/Com Ed                                     |  | $                         | 50   |      | $ | 42  
|Southern                                          |  | $                         | 53   |      | $ | 47  
|New YorkZone G                                   |  | $                         | 74   |      | $ | 63  
|New YorkZone A                                   |  | $                         | 60   |      | $ | 55  
|ERCOT                                             |  | $                         | 60   |      | $ | 49  
|SP-15                                             |  | $                         | 55   |      | $ | 52  



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|                                             |  |                           |         |      |   |        
|-------------------------------------------- |  | ------------------------- | ------- | ---- | - | -------
|                                             |  | Six Months Ended June 30,
|                                             |  | 2005                      |         | 2004
|Natural Gas Liquids                          |  |                           |         |      |   |        
|Gross NGL production (MBbls/d):              |  |                           |         |      |   |        
|Field plants                                 |  |                           | 56.7    |      |   | 57.0   
|Straddle plants                              |  |                           | 29.7    |      |   | 23.8   
|                                             |  |                           |         |      |   |        
|Total gross NGL production                   |  |                           | 86.4    |      |   | 80.8   
|                                             |  |                           |         |      |   |        
|Natural gas (residue) sales (Bbtu/d)         |  |                           | 182.6   |      |   | 182.4  
|                                             |  |                          
|Natural gas inlet volumes (MMCFD):           |  |                           |         |      |   |        
|Field plants                                 |  |                           | 517.2   |      |   | 551.3  
|Straddle plants                              |  |                           | 1,275.9 |      |   | 826.7  
|                                             |  |                           |         |      |   |        
|Total natural gas inlet volumes              |  |                           | 1,793.1 |      |   | 1,378.0
|                                             |  |                           |         |      |   |        
|Fractionation volumes (MBbls/d)              |  |                           | 168.6   |      |   | 199.0  
|Natural gas liquids sold (MBbls/d)           |  |                           | 268.2   |      |   | 276.9  
|Average commodity prices:                    |  |                           |         |      |   |        
|Crude oilWTI ($/Bbl)                        |  | $                         | 49.96   |      | $ | 36.64  
|Natural gasHenry Hub ($/MMBtu) (2)          |  | $                         | 6.51    |      | $ | 5.84   
|Natural gas liquids ($/Gal)                  |  | $                         | 0.78    |      | $ | 0.63   
|Fractionation spread ($/MMBtu)daily         |  | $                         | 2.15    |      | $ | 1.27   
|                                             |  |                          
|Regulated Energy Delivery (3)                |  |                           |         |      |   |        
|Electric sales in KWH (millions)             |  |                           |         |      |   |        
|Residential                                  |  |                           |        |      |   | 2,590  
|Commercial                                   |  |                           |        |      |   | 2,172  
|Industrial                                   |  |                           |        |      |   | 2,691  
|Transportation of customer-owned electricity |  |                           |        |      |   | 1,432  
|Other                                        |  |                           |        |      |   | 188    
|                                             |  |                           |         |      |   |        
|Total electric sales                         |  |                           |        |      |   | 9,073  
|                                             |  |                           |         |      |   |        
|Gas sales in Therms (millions)               |  |                           |         |      |   |        
|Residential                                  |  |                           |        |      |   | 194    
|Commercial                                   |  |                           |        |      |   | 74     
|Industrial                                   |  |                           |        |      |   | 29     
|Transportation of customer-owned gas         |  |                           |        |      |   | 125    
|                                             |  |                           |         |      |   |        
|Total gas delivered                          |  |                           |        |      |   | 422    
|                                             |  |                           |         |      |   |        
|Cooling degree daysactual (4)               |  |                           |        |      |   | 373    
|Cooling degree days10-year rolling average  |  |                           |        |      |   | 374    
|Heating degree daysactual (5)               |  |                           |        |      |   | 3,096  
|Heating degree days10-year rolling average  |  |                           |        |      |   | 3,131  

---

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

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

|(3) | We sold Illinois Power, our regulated utility, to Ameren on September 30, 2004.
|--- | -------------------------------------------------------------------------------

|(4) | 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.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) | 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.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

The following tables summarize significant items on a pre-tax basis, with the exception of the 2005 and
2004 tax items, affecting net income (loss) for the periods presented.



|                                           |  |                                |   |     |   |     |  |   |     |   |  |       |      |   |       |   |      |   |  |   |      |  
|------------------------------------------ |  | ------------------------------ | - | --- | - | --- |  | - | --- | - |  | ----- | ---- | - | ----- | - | ---- | - |  | - | ---- | -
|                                           |  | Six Months Ended June 30, 2005 |  
|                                           |  | GEN                            |   | NGL |   | REG |  |   | CRM |   |  | Other |      |   | Total |  
|                                           |  | (in millions)                  |  
|Legal and settlement charges               |  | $                              |  |     | $ |    |  | $ |    |   |  | $     |     |   |       | $ | (253 | ) |  | $ | (253 | )
|Independence toll settlement charge        |  |                                |  |     |   |    |  |   |    |   |  |       | (170 | ) |       |   |     |   |  |   | (170 | )
|Discontinued operations                    |  |                                |  |     |   | 81  |  |   |    |   |  |       | 5    |   |       |   |     |   |  |   | 86   |  
|Taxes                                      |  |                                |  |     |   |    |  |   |    |   |  |       |     |   |       |   | 125  |   |  |   | 125  |  
|                                           |  |                                |   |     |   |     |  |   |     |   |  |       |      |   |       |   |      |   |  |   |      |  
|Total                                      |  | $                              |  |     | $ | 81  |  | $ |    |   |  | $     | (165 | ) |       | $ | (128 | ) |  | $ | (212 | )
|                                           |  |                                |   |     |   |     |  |   |     |   |  |       |      |   |       |   |      |   |  |   |      |  
|                                           | 
|                                           |  | Six Months Ended June 30, 2004 |  
|                                           |  | GEN                            |   | NGL |   | REG |  |   | CRM |   |  | Other |      |   | Total |  
|                                           |  | (in millions)                  |  
|Legal and settlement charges               |  | $                              | 2 |     | $ |    |  | $ | (1  | ) |  | $     |     |   |       | $ | (57  | ) |  | $ | (56  | )
|Illinois Power goodwill impairment         |  |                                |  |     |   |    |  |   | (54 | ) |  |       |     |   |       |   |     |   |  |   | (54  | )
|Loss on anticipated sale of Illinois Power |  |                                |  |     |   |    |  |   | (15 | ) |  |       |     |   |       |   |     |   |  |   | (15  | )
|Acceleration of financing costs            |  |                                |  |     |   |    |  |   |    |   |  |       |     |   |       |   | (14  | ) |  |   | (14  | )
|Discontinued operations                    |  |                                |  |     |   | 134 |  |   |    |   |  |       | 18   |   |       |   | 3    |   |  |   | 155  |  
|Gas transportation contracts               |  |                                |  |     |   |    |  |   |    |   |  |       | 88   |   |       |   |     |   |  |   | 88   |  
|Taxes                                      |  |                                |  |     |   |    |  |   |    |   |  |       |     |   |       |   | 30   |   |  |   | 30   |  
|                                           |  |                                |   |     |   |     |  |   |     |   |  |       |      |   |       |   |      |   |  |   |      |  
|Total                                      |  | $                              | 2 |     | $ | 134 |  | $ | (70 | ) |  | $     | 106  |   |       | $ | (38  | ) |  | $ | 134  |  
|                                           |  |                                |   |     |   |     |  |   |     |   |  |       |      |   |       |   |      |   |  |   |      |  



Operating
Income/Loss



Operating loss was $449 million
for the six months ended June 30, 2005, compared to operating income of $96 million for the six months ended June 30, 2004.



GEN.Operating income for our GEN segment was $79 million for the six months ended June 30, 2005, compared to $88 million for the six months
ended June 30, 2004.



In the Midwest-MAIN region, results
remained flat at $200 million for the first six months of 2004 and 2005. Although average on-peak prices increased from $42 per MWh for the first half of 2004 to $50 per MWh for the first half of 2005, a significant portion of our production was
under contract, preventing us from realizing the full benefit of the increase in market prices. Volumes increased slightly, from 10.3 million MWh for the six months ended June 30, 2004 to 10.4 million MWh for the six months ended June 30, 2005. Our
Midwest results for the six months ended June 30, 2005 include $3 million of mark-to-market income, compared with a loss of $2 million in the same period 2004.



Results for our peaking facilities in the Midwest-ECAR region were improved by $6 million, from a loss of $5 million for the six months ended June 30,
2004 to income of $1 million for 2005. This improvement was a result of both favorable pricing and an increase in volumes. Results in our Southeast region decreased slightly, from $1 million for the six months ended June 30, 2004 to zero for 2005.
Results in our Texas region improved by $8 million, from a loss of $10 million for the six months ended June 30, 2004 to a loss of $2 million for the six months ended June 30, 2005. Although natural gas prices have remained high, power prices
increased by 22% in the region. Further, we were able to partially mitigate the negative impact on earnings by providing additional ancillary services to the market. Our 2005 results for Texas include a charge of approximately $2 million related to
hedge ineffectiveness.



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Improved earnings in the Midwest and Texas regions were offset in the Northeast region, where results
decreased from $17 million for the six months ended June 30, 2004 to $11 million for the same period in 2005. Beginning in February 2005, our Northeast regions results include earnings from the Independence facility. See Note
2AcquisitionSithe Energies for further discussion of the acquisition of Independence. Earnings associated with the Independence facility were $5 million for the six months ended June 30, 2005. However, these results were offset primarily
as a result of increased operating expense and decreased volumes at our Roseton facility. Volumes at Roseton decreased 1.2 million MWh, primarily due to compressed margins resulting from an increase in the price of fuel oil in relation to the price
of generated power. Operating expense increased by $8 million at our existing facilities, primarily related to maintenance at Roseton. Total volumes for the region, inclusive of our Independence facility, were down slightly, from 3.7 million MWh for
the six months ended June 30, 2004 to 3.5 million MWh for the same period in 2005, as additional volumes resulting from the acquisition of the Independence facility were offset by the decrease at the Roseton facility. Additionally, we realized $8
million less revenue in the first six months of 2005 due to the expiration of a transitional power purchase agreement in October 2004. The decrease in generated volumes and increase in operating expense were partially mitigated as average on-peak
prices were up 17% in the market served by our Danskammer and Roseton facilities.



General and administrative expense increased from $28 million for the six months ended June 30, 2004 to $36 million for the same period in 2005. The increase is primarily the result of expense associated with the New
York City office we acquired in our Sithe Energies acquisition, which we are in the process of shutting down. Depreciation expense increased from $95 million for the six months ended June 30, 2004 to $97 million for the six months ended June 30,
2005, primarily as a result of depreciation associated with the Independence facility acquired in 2005. Additionally, 2005 earnings include a $7 million charge related to the write-off of an environmental project.



GENs reported operating income for the six-month periods ended June 30,
2005 and 2004 also includes approximately $5 million of mark-to-market income in addition to that discussed above, related to purchases and sales that did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted
for on a mark-to-market basis.



REG. Operating
income for the REG segment was $76 million for the six months ended June 30, 2004. The 2004 period includes a $15 million charge related to the sale of Illinois Power and a $54 million charge for the impairment of assets associated with this
segment.



CRM.Operating loss for the CRM segment
was $207 million for the six months ended June 30, 2005, compared to operating income of $77 million in 2004.



Results for 2005 were negatively impacted by a $170 million charge associated with the Sithe Energies acquisition. Prior to the acquisition, Independence
held a power tolling contract and a gas supply agreement with our CRM segment. Upon completion of the purchase, these contracts became intercompany agreements under our GEN segment, and were effectively eliminated on a consolidated basis, resulting
in the $170 million charge upon completion of the acquisition. Results for 2005 also reflect $46 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold, and a net
mark-to-market benefit of $11 million from our legacy gas, power and coal positions.



2004 results included an $88 million gain related to our exit of four natural gas transportation contracts. In addition, 2004 results 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 also include mark-to-market gains of $44 million associated with our legacy gas, power and coal positions, and $6 million of income from our Canadian
business. These gains were partly offset by the $70 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold.



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Other.Other operating loss was $321 million for the six months ended June 30, 2005,
compared to a loss of $145 million for the six months ended June 30, 2004. Results for 2005 include a $240 million charge associated with the recent settlement of our shareholder class action litigation and other legal settlement charges totaling
$13 million. For more information, please read Note 10Commitment and ContingenciesShareholder Litigation. Results for 2004 include approximately $57 million of expenses related to increased legal and severance reserves. The increased
legal reserves resulted from additional activities during the quarter that affected managements assessment of the probable and estimable loss associated with the applicable proceedings. In addition, 2005 results benefited from lower
compensation, insurance and external consultant costs compared to the same period in 2004.



Earnings from Unconsolidated Investments



Our earnings from unconsolidated investments were approximately $7 million for the six months ended June 30, 2005, compared
to $88 million for the same period 2004. Our West Coast Power investment was the primary driver of the decrease. Total earnings from this investment were approximately $2 million for the six months ended June 30, 2005, compared to $82 million for
2004. The decrease in earnings is primarily the result of the expiration of West Coast Powers CDWR contract at the end of 2004. Please read Item 1. BusinessSegment DiscussionPower Generation beginning on page 2 of our Form 10-K for
a discussion of West Coast Powers current contractual arrangements.



Other Items, Net



Other items, net totaled $9 million for the six months ended June 30, 2005, compared to $6 million for the six months ended June 30, 2004. The increase is primarily associated with higher interest income in 2005 due
to higher interest rates.



Interest
Expense



Interest expense totaled $185 million
for the six months ended June 30, 2005, compared to $271 million for the six months ended June 30, 2004. The significant decrease is primarily attributable to the sale of Illinois Power in September 2004.



Income Tax Benefit



We reported an income tax benefit during the six months ended June 30, 2005
of $215 million compared to a benefit of $82 million for the six months ended June 30, 2004. The 2005 effective tax rate was 35%, compared to 101% in 2004. The 2004 tax benefit includes a $47 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 related to the release of reserves upon the conclusion of prior year tax audits. Please read Note 13Income Taxes for further
discussion. Excluding these items from the 2004 calculation would result in an effective tax rate of 40%. 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 NGL business in our NGL segment, our
U.K. CRM business in our CRM segment and our communications business in Other and Eliminations. The following summarizes the activity included in income from discontinued operations:



|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|---------------------------------------------------------------------------------------- |  | ------------- | -- | - | --- | - | --- |  | - | ----- | - |  | - | --- | -
|Six Months Ended June 30, 2005                                                           | 
|                                                                                         |  |               |    |  
|                                                                                         |  | U.K. CRM      |    |   | DGC |   | NGL |  |   | Total |  
|                                                                                         |  | (in millions) |   
|Operating income included in income from discontinued operations                         |  | $             | 6  |   |     | $ |    |  | $ | 112   |   |  | $ | 118 |  
|Earnings from unconsolidated investments included in income from discontinued operations |  |               |   |   |     |   |    |  |   | 4     |   |  |   | 4   |  
|Other items, net included in income from discontinued operations                         |  |               | (1 | ) |     |   |    |  |   | (10   | ) |  |   | (11 | )
|Interest expense included in income from discontinued operations                         |  |               |    |   |     |   |     |  |   |       |   |  |   | (25 | )
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |    |   |     |   |     |  |   |       |   |  |   | 86  |  
|Income tax benefit                                                                       |  |               |    |   |     |   |     |  |   |       |   |  |   | 93  |  
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations                                                      |  |               |    |   |     |   |     |  |   |       |   |  | $ | 179 |  
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|                                                                                        
|Six Months Ended June 30, 2004                                                           | 
|                                                                                         |  |               |    |  
|                                                                                         |  | U.K. CRM      |    |   | DGC |   | NGL |  |   | Total |  
|                                                                                         |  | (in millions) |   
|Operating income included in income from discontinued operations                         |  | $             | 3  |   |     | $ |    |  | $ | 145   |   |  | $ | 148 |  
|Earnings from unconsolidated investments included in income from discontinued operations |  |               |   |   |     |   |    |  |   | 4     |   |  |   | 4   |  
|Other items, net included in income from discontinued operations                         |  |               | 15 |   |     |   | 3   |  |   | (9    | ) |  |   | 9   |  
|Interest expense included in income from discontinued operations                         |  |               |    |   |     |   |     |  |   |       |   |  |   | (6  | )
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |    |   |     |   |     |  |   |       |   |  |   | 155 |  
|Income tax expense                                                                       |  |               |    |   |     |   |     |  |   |       |   |  |   | (78 | )
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  
|Income from discontinued operations                                                      |  |               |    |   |     |   |     |  |   |       |   |  | $ | 77  |  
|                                                                                         |  |               |    |   |     |   |     |  |   |       |   |  |   |     |  



Income from
discontinued operations before taxes. Income from discontinued operations before taxes was primarily driven by the results of operations of our NGL segment, which was reclassified to discontinued operations due to the anticipated sale of
DMSLP. For further information regarding the sale, please see Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued OperationsNatural Gas Liquids.



Operating income for the NGL segment was $112 million for the six months
ended June 30, 2005, compared to $145 million for the six months ended June 30, 2004. Operating income for the six months ended June 30, 2004 included pre-tax gains of $17 million and $36 million, respectively, from our Hackberry LNG and Indian
Basin sales.



Excluding the Hackberry and Indian Basin gains,
the significant improvement in operating income was driven by natural gas, crude oil and natural gas liquids prices, which increased dramatically year over year. The first half of 2005 was marked by continued high run times experienced across our
facilities.



Gathering and processing operating results
increased by $27 million for the six months ended June 30, 2005 compared to the six months ended June 30, 2004, primarily benefiting from 11% higher absolute commodity prices for natural gas and 24% higher absolute commodity prices for natural gas
liquids year over year. At our



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field plants, results increased $20 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from higher prices. Operating
results for the six months ended June 30, 2004 included $6 million in operating margin from our Indian Basin and Sherman plants, which were sold in April 2004 and November 2004, respectively. At our straddle plants, operating results increased $7
million, due largely to the impact of higher natural gas liquids prices under our POL contract settlements.



Results of our fractionation, storage and terminalling and transportation and logistics businesses decreased $5 million for the six months ended June 30,
2005 compared to the six months ended June 30, 2004. Overall fractionation volumes decreased period over period due to the loss of a fractionation customer at the end of September 2004 at our Cedar Bayou Fractionator. This was partially offset by
increased fractionation volumes at our Lake Charles Fractionator caused by industry-wide increased liquids production primarily as a result of higher frac spreads. Natural gas liquids storage and transportation operations operating results
increased period over period, partially offsetting fractionation impacts.



Wholesale marketing results were $3 million unfavorable for the six months ended June 30, 2005 compared to the six months ended June 30, 2004, primarily as a result of milder than usual weather and the first quarter
buyout of a refinery services contract. Higher natural gas liquids prices contributed higher earnings on our net back refinery services contracts.



NGL marketing services and distribution results decreased approximately $11 million for the six months ended June 30, 2005 compared to the six months
ended June 30, 2004. Although average natural gas liquids prices were higher during the six months ended June 30, 2005 compared to the six months ended June 30, 2004, sharp declines in natural gas liquids prices during the six months ended June 30,
2005 contributed to lower marketing margins. Further, although within acceptable measurement tolerances, natural gas liquids well losses also contributed to lower marketing margins during the six months ended June 30, 2005. In addition, during the
six months ended June 30, 2004, we terminated an inactive natural gas liquids sales contract and reevaluated liquid pipelines contractual requirements which allowed us to recognize a $9 million gain on sales of natural gas liquids at current market
prices previously held outside our normal inventory at historic below-current market prices.



Depreciation and amortization expense decreased $10 million for the six months ended June 30, 2005 compared to the six months ended June 30, 2004. We stopped depreciating our NGL assets on June 1, 2005, as they are
classified as held for sale, which resulted in reduced depreciation of $7 million during the six months ended June 30, 2005. In addition, depreciation expense in the six months ended June 30, 2004 included a $6 million charge related to an
adjustment to accumulated depreciation.



In June 2005 and June
2004, we tested certain of our assets for impairment based on the identification of triggering events as defined by SFAS No. 144. After testing, we recorded a pre-tax impairment of $5 million for our Puckett gas treating plant and gathering system
due to rapidly depleting reserves associated with that facility in second quarter 2004. We concluded that no impairment was necessary for any of the other facilities in either period as estimated undiscounted cash flows exceeded facility book
values.



During 2005, U.K. CRM recognized $5 million of pre-tax
income primarily associated with the receipt of a third-party bankruptcy settlement. During 2004, U.K. CRM recognized $17 million of translation gains on the repatriation of cash from the U.K. Also during 2004, DGC recognized $3 million of pre-tax
income associated with the receipt from a third party of a prior contractual claim.



Interest expense included in income from discontinued operations includes interest incurred on our $594 million Term Loan scheduled to mature in 2010 and our $189 million Generation facility debt scheduled to mature
in 2007. In accordance with EITF Issue 87-24, Allocation of Interest to Discontinued Operations, we have allocated interest expense associated with these two debt instruments to discontinued operations, as they are required to be paid
upon the sale of DMSLP. The increase in interest expense is due primarily to the Term Loan,



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which was entered into on May 28, 2004. As a result, 2004 results include one month of interest, compared to six months of interest in 2005.



Income tax benefit (expense) from discontinued operations. The
income tax benefit in 2005 includes a $125 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of NNG. We reduced the valuation allowance
related to our capital loss carryforward as a result of capital gains expected to be recognized from our anticipated sale of DMSLP. For further information regarding the sale, please see Note 3Discontinued Operations, Dispositions and Contract
TerminationsDiscontinued OperationsNatural Gas Liquids. The income tax expense in 2004 includes $20 million in tax expenses related to the conclusion of prior year tax audits. Please see Note 13Income TaxesPrior Year Tax
Audits for further discussion. Excluding these items, the 2005 and 2004 effective tax rates would both be 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 differences.



Outlook



The following summarizes our outlook
for our three reportable segments.



GEN Outlook.We expect that this segments future financial results will continue to reflect sensitivity to commodity prices, including the cost of emission allowances, 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, consistent with our views on market recovery in the regions we serve. 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 may 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 fuel. Power generators in the Midwest and the Northeast have experienced 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. While we believe our physical inventories and contractual
commitments provide us with a stable fuel supply, we are subject to physical delivery risks outside of our control. 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. During 2004 and 2005, we have seen increases in the market for capacity-related products from our peaking and intermediate generation
facilities.



Power Generation benefited from the operation of
substantially all of our peaking plants during the second quarter 2005. During the first six months of 2005, our peaking plants have generated more electricity than they did throughout all of 2004. We believe this increase is attributable to
increased demand as well as market design changes including MISO implementation.



Throughout 2004, a substantial portion of our 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, both of which terminated in December 2004. Our future results of operations will be significantly impacted by the expiration of the CDWR contract. West Coast Power, whose equity earnings were primarily
derived from the CDWR contract, had been our largest contributor to earnings from unconsolidated investments prior to 2005. As a result of the expiration of the CDWR contract, future earnings from the investment will be substantially reduced. Please
read Item 1. BusinessSegment



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DiscussionPower Generation beginning on page 2 of our Form 10-K for a discussion of West Coast Powers current contractual arrangements. Based on
our ongoing evaluation of strategic alternatives for our West Coast Power assets, we determined that it was not economically feasible to continue to operate our Long Beach generation facility beyond the expiration of the CDWR contract. Therefore, we
retired the asset as of January 1, 2005. Please read Liquidity and Capital ResourcesInternal Liquidity SourcesCash Flows from Operations for a discussion of our efforts to replace the CDWR contract.



Our former power purchase agreement between DMG and Illinois Power terminated
in December 2004. In September 2004, in connection with the sale of Illinois Power to Ameren, DPM entered into a new two-year power purchase agreement with AmerenIP with expected volumes comparable to the former agreement. Under the terms of this
agreement, effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48 per kW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. Under this agreement, we are no longer
the provider of last resort for Illinois Power, which exposed us to volume and price uncertainties under the former agreement. Under the former agreement, we received contract revenues based on a higher fixed capacity payment and lower variable
energy payments. Accordingly, GENs operating income under the new agreement will be impacted more significantly by deviations from expected energy purchases by Illinois Power.



During 2004, we sold our 50% interests in the Oyster Creek, Michigan Power, Hartwell, and Commonwealth facilities, as well
as our 20% interest in the Joppa facility. Additionally, we sold our 100% interest in Plantas Eolicas, S.A. de R.L. and 17.55% interest in Jamaica Energy Partners. Our 2004 results include an aggregate $99 million of earnings from these investments,
including $82 million of net gains on sales. However, beginning in 2005, the lost earnings from these assets will no longer be offset by gains on sale.



On January 31, 2005, in connection with the Sithe Energies acquisition, we acquired the 1,021 MW, combined-cycle Independence power generation facility,
four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. GENs 2005 results will include the results of this acquisition, including general and administrative costs associated with
Sithe Energies New York City office until such time as those costs can be mitigated. Please read Note 2AcquisitionSithe Energies for further discussion of this transaction.



NGL Outlook.Financial results for our NGL segment are impacted
by natural gas and natural gas liquids prices, as well as the frac spread. Provided that a strong pricing environment continues throughout 2005, our upstream contract settlements under POP and POL contracts will continue to benefit.



The effects of the NGL segment on our consolidated results of operations will
be significantly impacted by our ability to consummate the anticipated sale of DMSLP, as well as the timing of such sale. Please read Note 3Discontinued Operations, Dispositions and Contract TerminationsDiscontinued
OperationsNatural Gas Liquids for further discussion of this anticipated transaction.



CRM Outlook.Our CRM business future results of operations will be significantly impacted by our ability to complete our exit from this business. During 2004, we were successful in reaching
agreements to exit four of our natural gas transportation agreements. In November 2004, we entered into a back-to-back power purchase agreement with a subsidiary of Constellation, under which we will receive $161 million in payments
through November 2008 to offset our fixed payment obligations under our Kendall tolling arrangement, while positioning us to take advantage of the market recovery expected in 2008 and beyond. In January 2005, we completed the purchase from Exelon
Corporation of all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies and Independence. Please read Note 2AcquisitionSithe Energies for further discussion. As a result of this agreement, our
Independence power tolling arrangement has been transformed into



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an intercompany agreement under our GEN segment, which now includes the Independence facility. This substantially eliminates its future financial statement
impact. Our Gregory tolling arrangement expired by its terms in July 2005.



Our Sterlington tolling arrangement remains in place through 2017. We are open to opportunities to assign or renegotiate the terms of this arrangement, but we cannot guarantee that we will be successful. If we do not
renegotiate or terminate this remaining arrangement, it 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 this long-term contract 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 beginning on page 43 of our Form 10-K and Item 1. BusinessSegment DiscussionCustomer Risk Management beginning on page 18 of our Form 10-K.



Cash Flow Disclosures



The following table includes data from the operating section of our unaudited condensed consolidated statements of cash flows and include cash flows from
our discontinued operations, which are disclosed on a net basis in income from discontinued operations, net of taxes, in our unaudited condensed consolidated statements of operations:



|                                       |  |               |     |     |   |     |  |     |     |  |                       |      |   |              |   |      |   |  |   |    |  
|-------------------------------------- |  | ------------- | --- | --- | - | --- |  | --- | --- |  | --------------------- | ---- | - | ------------ | - | ---- | - |  | - | -- | -
|                                       |  | GEN           |     | NGL |   | REG |  | CRM |     |  | Other andEliminations |      |   | Consolidated |  
|                                       |  | (in millions) |    
|For the six months ended June 30, 2005 |  | $             | 194 |     | $ | 178 |  | $   |    |  | $                     | 41   |   |              | $ | (422 | ) |  | $ | (9 | )
|                                       |  |               |     |     |   |     |  |     |     |  |                       |      |   |              |   |      |   |  |   |    |  
|For the six months ended June 30, 2004 |  | $             | 200 |     | $ | 170 |  | $   | 181 |  | $                     | (182 | ) |              | $ | (308 | ) |  | $ | 61 |  
|                                       |  |               |     |     |   |     |  |     |     |  |                       |      |   |              |   |      |   |  |   |    |  



Operating Cash
Flow. Our cash flow used in operations totaled $9 million for the six months ended June 30, 2005. During the period, our GEN, NGL and CRM segments provided positive cash flow from operations. GEN provided cash flow from operations of $194
million, and NGL provided cash flow from operations of $178 million primarily due to positive earnings for the period as well as the return of cash collateral. Our CRM segment provided cash flow of approximately $41 million in cash primarily due to
the return of cash collateral offset by fixed payments associated with the power tolling arrangements and our final payment of $26 million related to our exit from gas transportation contracts. Other and Eliminations includes a use of approximately
$422 million in cash primarily due to our payment of $175 million in May 2005 in connection with the settlement of the shareholder class action litigation, interest payments to service debt and general and administrative expenses.



Our cash flow provided by operations totaled $61 million for the six months
ended June 30, 2004. During the period, our GEN, NGL and REG segments provided positive cash flow from operations. GEN provided cash flow from operations of $200 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 $170 million due primarily to positive earnings and seasonality of the wholesale business for the period; and REG provided cash flow from
operations of $181 million due primarily to positive earnings for the period and the withdrawals of gas in storage. Our CRM segment used approximately $182 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 and eliminations includes a use of approximately $308
million in cash due primarily to interest payments to service debt, settlement payments and general and administrative expenses.



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Capital Expenditures and Investing Activities. Cash used in investing activities during the
six months ended June 30, 2005 totaled $218 million. Capital spending of $93 million was primarily comprised of $65 million and $23 million in the GEN and NGL segments, respectively. The capital spending for the GEN segment primarily related to
maintenance capital projects, as well as $10 million in development capital associated with the completion of the Havana PRB conversion. Capital spending in our NGL segment primarily related to maintenance capital projects and wellconnects. The cost
to acquire Sithe Energies, net of cash proceeds, totaled $120 million. Proceeds from asset sales consisted of a $5 million payment to Ameren associated with the working capital adjustment related to the sale of Illinois Power.



Cash used in investing activities during the six months ended June 30, 2004
totaled $70 million. Capital spending of $151 million was comprised primarily of $58 million, $27 million and $61 million in the GEN, NGL and REG segments, respectively. The capital spending for our GEN segment related primarily to maintenance
capital projects. Capital spending in our NGL segment related primarily to maintenance capital projects and wellconnects, as well as approximately $5 million on a gathering system expansion. Capital spending in our REG segment related primarily to
projects intended to maintain system reliability and new business services. Proceeds from asset sales included primarily $17 million in proceeds from the sale of our remaining financial interest in the Hackberry LNG project, $48 million from the
sale of Indian Basin, $9 million from the sale of PESA and approximately $5.5 million from the sale of our interest in a power generating facility located in Jamaica.



Financing Activities. Cash used in financing activities during the six months ended June 30, 2005 totaled $43
million. Repayments of long-term debt totaled $38 million for the six months ended June 30, 2005 and consisted of the following: (i) payments of $18 million on a maturing series of DHI senior notes; (ii) payments of $17 million on the Independence
Senior Notes due 2007 and (iii) payments of $3 million on DHIs term loan. Cash used in financing activities also includes a semi-annual dividend payment of $11 million on our Series C preferred stock.



Net cash provided by financing activities during the six months ended June
30, 2004 totaled $370 million. The cash provided was due primarily to proceeds from a new $600 million secured term loan, net of issuance costs of $19 million, which was offset partially by repayments of long-term debt. Repayments of long-term debt
totaled $193 million for the six months ended June 30, 2004 and consisted of the following: (i) payments of $95 million on a maturing series of Illinova senior notes; (ii) payments of $43 million on Illinois Powers transitional funding trust
notes; (iii) payments of $39 million under our ABG Gas Supply financing and (iv) payments of $16 million on the junior notes. Net cash provided by financing activities was also offset by a semi-annual dividend payment of $11 million on our Series C
preferred stock.



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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 theSix Months EndedJune 30, 2005 |     
|                                                                                  |  | (in millions)                                  |     
|Balance Sheet Risk-Management Accounts                                            |  |                                                |      |  
|Fair value of portfolio at January 1, 2005                                        |  | $                                              | (133 | )
|Risk-management losses recognized through the income statement in the period, net |  |                                                | (2   | )
|Cash paid related to risk-management contracts settled in the period, net         |  |                                                | 18   |  
|Changes in fair value as a result of a change in valuation technique (1)          |  |                                                |     |  
|Non-cash adjustments and other (2)                                                |  |                                                | 32   |  
|                                                                                  |  |                                                |      |  
|Fair value of portfolio at June 30, 2005                                          |  | $                                              | (85  | )
|                                                                                  |  |                                                |      |  
|Income Statement Reconciliation                                                   |  |                                                |      |  
|Risk-management losses recognized through the income statement in the period, net |  | $                                              | (2   | )
|Physical business recognized through the income statement in the period, net (3)  |  |                                                | (154 | )
|Non-cash adjustments and other                                                    |  |                                                | 4    |  
|                                                                                  |  |                                                |      |  
|Net recognized operating loss                                                     |  | $                                              | (152 | )
|                                                                                  |  |                                                |      |  
|Cash Flow Statement                                                               |  |                                                |      |  
|Cash paid related to risk-management contracts settled in the period, net         |  | $                                              | (18  | )
|Estimated cash paid related to physical business settled in the period, net (3)   |  |                                                | (154 | )
|Timing and other, net (4)                                                         |  |                                                | 19   |  
|                                                                                  |  |                                                |      |  
|Cash paid during the period                                                       |  | $                                              | (153 | )
|                                                                                  |  |                                                |      |  
|Risk-Management cash flow adjustment for the quarter ended June 30, 2005 (5)      |  | $                                              | (1   | )
|                                                                                  |  |                                                |      |  

---

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

|(2) | This amount consists of changes in value associated with cash flow hedges on forward power sales and fair value hedges on debt, which were more than offset by the $62 million
risk-management asset acquired in connection with the Sithe Energies transaction.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | This amount includes capacity payments on our power tolling arrangements and the $170 million pre-tax charge for the Independence toll settlement.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------

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

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



The net risk management liability of $85 million is the aggregate of the
following line items on our 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 June 30, 2005 and December 31, 2004. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may
receive or pay cash in periods other than those depicted below:



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



|                  |  |               |     |   |         |   |    |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |    |  
|----------------- |  | ------------- | --- | - | ------- | - | -- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- |  | - | --- | - |  | - | -- | -
|                  |  | Total         |     |   | 2005(3) |   |    | 2006 |  |   | 2007 |   |  | 2008 |     |   | 2009 |   |     | Thereafter | 
|                  |  | (in millions) |    
|June 30, 2005 (2) |  | $             | (30 | ) |         | $ | 7  |      |  | $ | 15   |   |  | $    | (39 | ) |      | $ | (12 | )          |  | $ | (4  | ) |  | $ | 3  |  
|December 31, 2004 |  |               | (96 | ) |         |   | (7 | )    |  |   | (8   | ) |  |      | (48 | ) |      |   | (21 | )          |  |   | (10 | ) |  |   | (2 | )
|                  |  |               |     |   |         |   |    |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |    |  
|Increase (4)      |  | $             | 66  |   |         | $ | 14 |      |  | $ | 23   |   |  | $    | 9   |   |      | $ | 9   |            |  | $ | 6   |   |  | $ | 5  |  
|                  |  |               |     |   |         |   |    |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |    |  

---

|(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 June 30, 2005 of $85 million on the unaudited condensed consolidated balance sheets include the $30 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) | Our mark-to-market values at June 30, 2005 were derived solely from market quotations instead of the combination of long-term valuation models and market quotations used at December
31, 2004. Following our Sithe Energies acquisition and the resulting restructuring of the Independence toll, we no longer use long-term valuation models, as our risk-management portfolio can be fully valued based on market quotations.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Amounts represent July 1 to December 31, 2005 values in the June 30, 2005 row and January 1 to December 31, 2005 values in the December 31, 2004 row.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | The increase relates primarily to our Sithe Energies acquisition and resulting restructuring of the Independence toll.
|--- | ----------------------------------------------------------------------------------------------------------------------



Cash Flow Components of Net Risk-Management Assets



|                  |  |                              |   |                                 |   |           |  |   |      |   |  |      |    |   |      |   |     |      |  |   |            |   |  |   |     |   |  |   |    |  
|----------------- |  | ---------------------------- | - | ------------------------------- | - | --------- |  | - | ---- | - |  | ---- | -- | - | ---- | - | --- | ---- |  | - | ---------- | - |  | - | --- | - |  | - | -- | -
|                  |  | Six MonthsEndedJune 30, 2005 |   | Six MonthsEndedDecember 31,2005 |   | Total2005 |  |   | 2006 |   |  | 2007 |    |   | 2008 |   |     | 2009 |  |   | Thereafter |  
|                  |  | (in millions)                |  
|June 30, 2005 (1) |  | $                            | 1 |                                 | $ | 7         |  | $ | 8    |   |  | $    | 17 |   |      | $ | (41 | )    |  | $ | (14        | ) |  | $ | (5  | ) |  | $ | 4  |  
|December 31, 2004 |  |                              |   |                                 |   |           |  |   | (5   | ) |  |      | (7 | ) |      |   | (51 | )    |  |   | (23        | ) |  |   | (12 | ) |  |   | (1 | )
|                  |  |                              |   |                                 |   |           |  |   |      |   |  |      |    |   |      |   |     |      |  |   |            |   |  |   |     |   |  |   |    |  
|Increase (2)      |  |                              |   |                                 |   |           |  | $ | 13   |   |  | $    | 24 |   |      | $ | 10  |      |  | $ | 9          |   |  | $ | 7   |   |  | $ | 5  |  
|                  |  |                              |   |                                 |   |           |  |   |      |   |  |      |    |   |      |   |     |      |  |   |            |   |  |   |     |   |  |   |    |  

---

|(1) | The cash flow values for 2005 reflect realized cash flows for the six months ended June 30, 2005 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.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | The increase relates primarily to our Sithe Energies acquisition and resulting restructuring of the Independence toll.
|--- | ----------------------------------------------------------------------------------------------------------------------



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



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



| |  |  | our ability to continue execution of 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 the matters involving the western power and natural gas markets, master netting agreement matters, and
the investigations primarily relating to past trading practices;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the effects of the Sithe Energies acquisition;
| | - |  | ----------------------------------------------



| |  |  | consummation of the agreed upon sale of DMSLP;
| | - |  | ----------------------------------------------



| |  |  | positioning GEN for future growth; and
| | - |  | --------------------------------------



| |  |  | our ability to complete our exit from the CRM business 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, which represents the relationship between the prices for natural gas and natural gas liquids;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | our ability to achieve our financial and operational goals associated with the Sithe Energies acquisition;
| | - |  | ----------------------------------------------------------------------------------------------------------



| |  |  | our ability to achieve tax and capital structure objectives associated with, our receipt of required regulatory approvals for, the satisfaction of other conditions precedent to the
consummation of, and the effects on our financial condition of, the agreed upon sale of DMSLP;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the availability of, and our ability to participate in, organic growth, controlled expansion, or consolidation or combination opportunities for our power generation business, and
the impact of any such opportunities on our financial condition and results of operations;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | our ability to fund the environmental and emission control projects mandated by the Baldwin consent decree, approved by the Illinois federal district court, and the impact of those
payments on our financial condition;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the impact on our financial condition of payments and stock issuances required by the settlement agreement, approved July 2005, relating to the shareholder class action litigation;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | 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;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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 effects of our efforts to improve our internal control structure, particularly with respect to the remediation of the deficiencies discussed under Item 9AControls and
Procedures beginning on page 85 of our Form 10-K;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | other North American regulatory or legislative developments that affect the demand and pricing for energy generally, increase the environmental compliance cost for our facilities,
or 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.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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.



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 March 31, 2004.



CRITICAL ACCOUNTING POLICIES



Please read Critical Accounting Policies beginning on page 74 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 83 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 June 30, 2005.



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.



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Daily and Average VaR for Risk-Management Portfolio



|                                                             |  |               |   |                  |   |  
|------------------------------------------------------------ |  | ------------- | - | ---------------- | - | -
|                                                             |  | June 30,2005  |   | December 31,2004
|                                                             |  | (in millions)
|One Day VaR95% Confidence Level                             |  | $             | 1 |                  | $ | 5
|One Day VaR99% Confidence Level                             |  | $             | 1 |                  | $ | 7
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $             | 1 |                  | $ | 4

---

|(1) | VaR at June 30, 2005 is significantly lower than that reported for December 31, 2004 due to the acquisition and consolidation of ExRes, the parent company of Sithe Energies and
Independence, effective January 31, 2005, which essentially eliminated the risk of the Independence financial derivative instrument in our consolidated financial results.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Credit Risk. The following table represents our credit exposure at June 30, 2005 associated with the
mark-to-market portion of our risk-management portfolio, on a net basis.



Credit Exposure Summary



|                                |  |                         |     |                             |   |       |  |   |    
|------------------------------- |  | ----------------------- | --- | --------------------------- | - | ----- |  | - | ---
|                                |  | InvestmentGrade Quality |     | Non-InvestmentGrade Quality |   | Total
|                                |  | (in millions)          
|Type of Business:               |  |                         |     |                             |   |       |  |   |    
|Financial Institutions          |  | $                       | 163 |                             | $ |      |  | $ | 163
|Commercial/Industrial/End Users |  |                         | 55  |                             |   | 26    |  |   | 81 
|Utility and Power Generators    |  |                         | 5   |                             |   |      |  |   | 5  
|Oil and Gas Producers           |  |                         | 5   |                             |   |      |  |   | 5  
|                                |  |                         |     |                             |   |       |  |   |    
|Total                           |  | $                       | 228 |                             | $ | 26    |  | $ | 254
|                                |  |                         |     |                             |   |       |  |   |    



Of the $26 million in
credit exposure to non-investment grade counterparties, approximately 85% 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 June 30, 2005, our
fixed rate debt instruments as a percentage of total debt instruments was approximately 76%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of June 30, 2005, 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 June 30, 2006 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 reduce the percentage of fixed rate financial obligations in our debt portfolio through the use of swaps or other financial instruments.



Derivative Contracts. The notional financial contract amounts
associated with our commodity risk-management, interest rate and foreign currency exchange contracts were as follows at June 30, 2005 and December 31, 2004, respectively:



Notional Contract Amounts



|                                                                         |  |              |        |                  |   |       
|------------------------------------------------------------------------ |  | ------------ | ------ | ---------------- | - | ------
|                                                                         |  | June 30,2005 |        | December 31,2004
|Natural Gas (Trillion Cubic Feet)                                        |  |              | 0.724  |                  |   | 1.084 
|Electricity (Million Megawatt Hours)                                     |  |              | 25.452 |                  |   | 11.652
|Net Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)   |  | $            | 525    |                  | $ | 525   
|Fixed Interest Rate Received on Swaps (Percent)                          |  |              | 4.331  |                  |   | 4.331 
|Net Interest Rate Risk-Management Contract (In Millions of U.S. Dollars) |  | $            | 25     |                  | $ | 25    
|Fixed Interest Rate Paid (Percent)                                       |  |              | 5.998  |                  |   | 5.998 



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##### Table of Contents

Item 4CONTROLS AND PROCEDURES



Evaluation of Disclosure Controls and Procedures. Effective as of the end of the second quarter 2005, 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 second quarter 2005 relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002.



Based on this evaluation, our CEO and CFO concluded that, as of June 30,
2005, as a result of the material weakness identified as of December 31, 2004 and discussed below, our disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our SEC reports is recorded,
processed, summarized and reported within the requisite time periods. As we will be unable to confirm whether we have remediated this material weakness until preparation of our 2005 annual tax provision, we anticipate that such material weakness
will continue to exist through the end of 2005. Due to the material weakness related to our tax accounting and tax reconciliation process, procedures and controls, in preparing our financial statements at and for the three- and six-month periods
ended June 30, 2005, we performed additional procedures relating to the tax provision designed to ensure that such financial statements were fairly presented in all material respects in accordance with generally accepted accounting principles.



Status of Remediation of Material Weakness.As
discussed in Item 9A. Controls and ProceduresManagements Report on Internal Control over Financial Reporting beginning on page 86 of our Form 10-K, as of December 31, 2004, there was a material weakness in our internal control over
financial reporting related to our tax accounting and tax reconciliation processes, procedures and controls. In 2004, and through the date of this filing, we have taken the following steps to improve our internal controls around our tax accounting
and tax reconciliation processes, procedures and controls:



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



| |  |  | Formalized processes, procedures and documentation standards relating to income tax provisions; and
| | - |  | ---------------------------------------------------------------------------------------------------



| |  |  | Restructured our Tax Department to ensure appropriate segregation of duties regarding preparation and review of the quarterly and annual tax provision.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------



We believe we have taken steps necessary to remediate this material weakness
relating to our tax accounting and tax reconciliation processes, procedures and controls, however, certain of the corrective processes, procedures and controls relate to annual controls that cannot be tested until the preparation of our 2005 annual
tax provision. Accordingly, we will continue to monitor vigorously the effectiveness of these processes, procedures and controls and will make any further changes management determines appropriate.



Changes in Internal Control Over Financial Reporting. Other
than as noted above in this Item 4, there were no changes in our internal control 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 last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.





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DYNEGY INC.



PART II. OTHER INFORMATION



Item 1LEGAL PROCEEDINGS



See Note 10 to the accompanying unaudited condensed consolidated financial statements for discussion of the material legal proceedings to which we are a party.



Item 4SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS



Our 2005 annual meeting of the shareholders was held on May 19, 2005. The purpose of the annual meeting was to consider and vote upon the following proposals:



| | 1. | To elect eleven Class A common stock directors and two Class B common stock directors to serve until the 2006 annual meeting of shareholders;
| | -- | ---------------------------------------------------------------------------------------------------------------------------------------------



| | 2. | To act upon a proposal to change our state of incorporation from Illinois to Delaware by merging Dynegy with and into Dynegy Inc., a Delaware corporation and wholly owned subsidiary
of Dynegy which we refer to as Merger Sub, pursuant to the Agreement and Plan of Merger between Dynegy and Merger Sub;
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 3. | To act upon a proposal to ratify the appointment of PricewaterhouseCoopers LLP as our independent auditors for the fiscal year ending December 31, 2005; and
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 4. | To consider and act upon the one shareholder proposal described below.
| | -- | ----------------------------------------------------------------------



Our Board of Directors is comprised of thirteen members. At the annual meeting, each of the following individuals was elected to serve as one of our
directors: Charles E. Bayless, David W. Biegler, Linda Walker Bynoe, Thomas D. Clark, Jr., Barry J. Galt, Patricia A. Hammick, George L. Mazanec, Robert C. Oelkers, Howard B. Sheppard, Joe J. Stewart, William L. Trubeck, Raymond I. Wilcox and Bruce
A. Williamson. The votes cast for each nominee and the votes withheld were as follows:



Class A Directors



|    |  |                      |  |             |  |           
|--- |  | -------------------- |  | ----------- |  | ----------
|    |  |                      |  | FOR         |  | WITHHELD  
|1.  |  | Charles E. Bayless   |  | 238,108,632 |  | 22,060,869
|2.  |  | David W. Biegler     |  | 241,168,483 |  | 18,791,634
|3.  |  | Linda Walker Bynoe   |  | 238,243,195 |  | 21,717,078
|4.  |  | Thomas D. Clark, Jr. |  | 248,756,152 |  | 11,206,745
|5.  |  | Barry J. Galt        |  | 195,961,775 |  | 63,995,247
|6.  |  | Patricia A. Hammick  |  | 238,406,091 |  | 21,559,296
|7.  |  | George L. Mazanec    |  | 240,932,970 |  | 19,046,451
|8.  |  | Robert C. Oelkers    |  | 238,395,155 |  | 21,566,135
|9.  |  | Joe J. Stewart       |  | 248,753,108 |  | 11,206,890
|10. |  | William L. Trubeck   |  | 238,469,612 |  | 21,488,895
|11. |  | Bruce A. Williamson  |  | 248,757,471 |  | 11,870,466



Class B Directors



|   |  |                    |  |            |  |         
|-- |  | ------------------ |  | ---------- |  | --------
|   |  |                    |  | FOR        |  | WITHHELD
|1. |  | Howard B. Sheppard |  | 96,891,014 |  | 0       
|2. |  | Raymond I. Wilcox  |  | 96,891,014 |  | 0       



80



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##### Table of Contents

The following votes were cast with respect to the proposal to change our state of incorporation from
Illinois to Delaware by merging Dynegy with and into Dynegy Inc., a Delaware corporation and wholly owned subsidiary of Dynegy, which we refer to as Merger Sub, pursuant to the Agreement and Plan of Merger between Dynegy and Merger Sub.
There were 97,483,358 broker non-votes. This proposal failed to pass even though more than 90% of the votes were cast in favor of the proposal, as the proposal failed to receive a sufficient number of total votes by the holders of Class A common
stock to satisfy the two-thirds super-majority required under Illinois law.



Class A Common Stock



|            |  |            |  |          
|----------- |  | ---------- |  | ---------
|FOR         |  | AGAINST    |  | ABSTAIN  
|149,091,630 |  | 10,239,755 |  | 3,227,290



Class B Common
Stock



|           |  |         |  |        
|---------- |  | ------- |  | -------
|FOR        |  | AGAINST |  | ABSTAIN
|96,891,014 |  | 0       |  | 0      



Series C
Convertible Preferred Stock



|          |  |         |  |        
|--------- |  | ------- |  | -------
|FOR       |  | AGAINST |  | ABSTAIN
|8,000,000 |  | 0       |  | 0      



The following votes
were cast with respect to the ratification of the selection of PricewaterhouseCoopers LLP as our independent auditors for the fiscal year ended December 31, 2005. There were no broker non-votes. This proposal was approved by the shareholders.



|            |  |           |  |          
|----------- |  | --------- |  | ---------
|FOR         |  | AGAINST   |  | ABSTAIN  
|351,009,510 |  | 2,921,200 |  | 3,002,337



The following votes
were cast with respect to the shareholder proposal requesting that the Board of Directors adopt a policy that, in the event of a restatement of financial results, we would recoup compensation received by senior executives for achieving performance
targets to the extent such performance targets were not achieved. There were 98,483,358 broker non-votes. This shareholder proposal failed to pass.



|           |  |             |  |          
|---------- |  | ----------- |  | ---------
|FOR        |  | AGAINST     |  | ABSTAIN  
|80,785,022 |  | 173,493,467 |  | 5,171,200



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##### Table of Contents

Item 6EXHIBITS



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



|      |  |                                                                                                                                                                                                                                                    
|----- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1  |  | Dynegy Inc. Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on
June 28, 2005, File No. 1-15659).                     
|      | 
|10.2  |  | First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28,
2005, File No. 1-15659).                           
|      | 
|10.3  |  | Dynegy Inc. Executive Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc.
filed on June 28, 2005, File No. 1-15659).           
|      | 
|10.4  |  | Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated November 20, 2003 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Dynegy Inc. filed on
June 28, 2005, File No. 1-15659).                   
|      | 
|10.5  |  | First Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.5 to the Current Report on Form 8-K of
Dynegy Inc. filed on June 28, 2005, File No. 1-15659).
|      | 
|10.6  |  | Baldwin Consent Decree approved May 27, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2005, File No.
1-15659).                                                                 
|      | 
|10.7  |  | Director Compensation Summary (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 24, 2005, File No. 1-15659).                                                                                
|      | 
|10.8  |  | Stipulation of Settlement dated May 2, 2005 (Shareholder Class Action Litigation) (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31,
2005 of Dynegy Inc., File No. 1-15659).          
|      | 
|10.9  |  | Stipulation of Settlement dated April 29, 2005 (Shareholder Derivative Litigation) (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31,
2005 of Dynegy Inc., File No. 1-15659).         
|      | 
|+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.
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



82



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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: August 9, 2005 |  | By:         |  | /s/ NICK J. CARUSO                                                                                                           
|                     |  |             |  | Nick J. Caruso Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal
Financial Officer)



83



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##### Table of Contents

EXHIBIT INDEX



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



|      |  |                                                                                                                                                                                                                                                    
|----- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.1  |  | Dynegy Inc. Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on
June 28, 2005, File No. 1-15659).                     
|      | 
|10.2  |  | First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28,
2005, File No. 1-15659).                           
|      | 
|10.3  |  | Dynegy Inc. Executive Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc.
filed on June 28, 2005, File No. 1-15659).           
|      | 
|10.4  |  | Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated November 20, 2003 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Dynegy Inc. filed on
June 28, 2005, File No. 1-15659).                   
|      | 
|10.5  |  | First Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.5 to the Current Report on Form 8-K of
Dynegy Inc. filed on June 28, 2005, File No. 1-15659).
|      | 
|10.6  |  | Baldwin Consent Decree approved May 27, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2005, File No.
1-15659).                                                                 
|      | 
|10.7  |  | Director Compensation Summary (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 24, 2005, File No. 1-15659).                                                                                
|      | 
|10.8  |  | Stipulation of Settlement dated May 2, 2005 (Shareholder Class Action Litigation) (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31,
2005 of Dynegy Inc., File No. 1-15659).          
|      | 
|10.9  |  | Stipulation of Settlement dated April 29, 2005 (Shareholder Derivative Litigation) (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31,
2005 of Dynegy Inc., File No. 1-15659).         
|      | 
|+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.
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------