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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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

For the quarterly period ended September 30, 2006



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

For the transition period from  to

Commission file number: 1-15659



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DYNEGY INC.

(Exact name of registrant as specified in its charter)



|                         |  |                                     
|------------------------ |  | ------------------------------------
|Illinois                 |  | 74-2928353                          
|(State of incorporation) |  | (I.R.S. Employer Identification No.)

1000 Louisiana, Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 507-6400

(Registrants telephone number, including area code)

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

Indicate by check mark
whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ         Accelerated filer ̈Non-accelerated filer ̈

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

Indicate the 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, 401,197,702 shares outstanding as
of November 3, 2006; Class B common stock, no par value per share, 96,891,014 shares outstanding as of November 3, 2006.



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DYNEGY INC.

TABLE OF CONTENTS



|                                                                                              |  |     
|--------------------------------------------------------------------------------------------- |  | ----
|                                                                                              |  | Page
|PART I. FINANCIAL INFORMATION                                                                 |  |     
|                                                                                              | 
|Item 1. FINANCIAL STATEMENTS:                                                                 |  |     
|                                                                                              | 
|Condensed Consolidated Balance Sheets:                                                        |  |     
|September 30, 2006 and December 31, 2005                                                      |  | 4   
|Condensed Consolidated Statements of Operations:                                              |  |     
|For the three and nine months ended September 30, 2006 and 2005                               |  | 5   
|Condensed Consolidated Statements of Cash Flows:                                              |  |     
|For the nine months ended September 30, 2006 and 2005                                         |  | 6   
|Condensed Consolidated Statements of Comprehensive Income (Loss):                             |  |     
|For the three and nine months ended September 30, 2006 and 2005                               |  | 7   
|Notes to Condensed Consolidated Financial Statements                                          |  | 8   
|                                                                                              | 
|Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |  | 45  
|Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                            |  | 71  
|Item 4. CONTROLS AND PROCEDURES                                                               |  | 72  
|                                                                                              | 
|PART II. OTHER INFORMATION                                                                    |  |     
|                                                                                              | 
|Item 1. LEGAL PROCEEDINGS                                                                     |  | 75  
|Item 1A. RISK FACTORS                                                                         |  | 75  
|Item 6. EXHIBITS                                                                              |  | 78  



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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, our and the Company
refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.



|       |  |                                                                         
|------ |  | ------------------------------------------------------------------------
|APB    |  | Accounting Principles Board                                             
|APIC   |  | Additional paid-in-capital                                              
|ARO    |  | Asset retirement obligation                                             
|CDWR   |  | California Department of Water Resources                                
|CEO    |  | Chief Executive Officer                                                 
|CFO    |  | Chief Financial Officer                                                 
|CFTC   |  | Commodity Futures Trading 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.                                         
|DMSLP  |  | Dynegy Midstream Services Limited Partnership                           
|DMT    |  | Dynegy Marketing and Trade                                              
|DNE    |  | Dynegy Northeast Generation, Inc.                                       
|DPM    |  | Dynegy Power Marketing, Inc.                                            
|EBITDA |  | Earnings Before Interest, Taxes, Depreciation and Amortization          
|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                                                     
|FSP    |  | FASB Staff Position                                                     
|GAAP   |  | Generally Accepted Accounting Principles of the United States of America
|GEN    |  | Our power generation business                                           
|GEN-MW |  | Our power generation business  Midwest segment                         
|GEN-NE |  | Our power generation business  Northeast segment                       
|GEN-SO |  | Our power generation business  South segment                           
|HSR    |  | Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended        
|ICC    |  | Illinois Commerce Commission                                            
|IGC    |  | Illinova Generating Company                                             
|ISO    |  | Independent System Operator                                             
|LNG    |  | Liquefied natural gas                                                   
|LSP    |  | LS Power                                                                
|LTIP   |  | Long-term incentive plan                                                
|MISO   |  | Midwest Independent Transmission System Operator, Inc.                  
|MMBtu  |  | Millions of British thermal units                                       
|MW     |  | Megawatts                                                               
|MWh    |  | Megawatt hour                                                           
|NGL    |  | Our former natural gas liquids business segment                         
|NNG    |  | Northern Natural Gas Company                                            
|NOL    |  | Net operating loss                                                      
|NRG    |  | NRG Energy, Inc.                                                        
|NYSDEC |  | New York State Department of Environmental Conservation                 
|PRB    |  | Powder River Basin coal                                                 
|PUHCA  |  | Public Utility Holding Company Act of 1935, as amended                  
|SAB    |  | SEC Staff Accounting Bulletin                                           
|SEC    |  | U.S. Securities and Exchange Commission                                 
|SFAS   |  | Statement of Financial Accounting Standards                             
|SPDES  |  | State Pollutant Discharge Elimination System                            
|SPN    |  | Second Priority Senior Secured Notes                                    
|VaR    |  | Value at Risk                                                           
|VIE    |  | Variable Interest Entity                                                



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DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)



|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------- | ------ | - | ---------------- | - | ------ | -
|                                                                                                                                                                                                                                   |  | September 30,2006 |        |   | December 31,2005 |  
|ASSETS                                                                                                                                                                                                                             |  |                   |        |   |                  |   |        |  
|Current Assets                                                                                                                                                                                                                     |  |                   |        |   |                  |   |        |  
|Cash and cash equivalents                                                                                                                                                                                                          |  | $                 | 388    |   |                  | $ | 1,549  |  
|Restricted cash                                                                                                                                                                                                                    |  |                   | 277    |   |                  |   | 397    |  
|Accounts receivable, net of allowance for doubtful accounts of $70 and $103, respectively                                                                                                                                          |  |                   | 284    |   |                  |   | 611    |  
|Accounts receivable, affiliates                                                                                                                                                                                                    |  |                   | 1      |   |                  |   | 29     |  
|Inventory                                                                                                                                                                                                                          |  |                   | 197    |   |                  |   | 214    |  
|Assets from risk-management activities                                                                                                                                                                                             |  |                   | 343    |   |                  |   | 665    |  
|Deferred income taxes                                                                                                                                                                                                              |  |                   | 26     |   |                  |   | 14     |  
|Prepayments and other current assets                                                                                                                                                                                               |  |                   | 99     |   |                  |   | 227    |  
|Assets held for sale (Note 3)                                                                                                                                                                                                      |  |                   | 1      |   |                  |   |       |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Current Assets                                                                                                                                                                                                               |  |                   | 1,616  |   |                  |   | 3,706  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment                                                                                                                                                                                                      |  |                   | 6,422  |   |                  |   | 6,515  |  
|Accumulated depreciation                                                                                                                                                                                                           |  |                   | (1,417 | ) |                  |   | (1,192 | )
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                                                                                                                                                                 |  |                   | 5,005  |   |                  |   | 5,323  |  
|Other Assets                                                                                                                                                                                                                       |  |                   |        |   |                  |   |        |  
|Unconsolidated investments                                                                                                                                                                                                         |  |                   | 7      |   |                  |   | 270    |  
|Restricted investments                                                                                                                                                                                                             |  |                   | 82     |   |                  |   | 85     |  
|Assets from risk-management activities                                                                                                                                                                                             |  |                   | 103    |   |                  |   | 165    |  
|Intangible assets                                                                                                                                                                                                                  |  |                   | 362    |   |                  |   | 392    |  
|Deferred income taxes                                                                                                                                                                                                              |  |                   | 3      |   |                  |   | 3      |  
|Other long-term assets                                                                                                                                                                                                             |  |                   | 135    |   |                  |   | 182    |  
|Assets held for sale (Note 3)                                                                                                                                                                                                      |  |                   | 194    |   |                  |   |       |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Assets                                                                                                                                                                                                                       |  | $                 | 7,507  |   |                  | $ | 10,126 |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                                                                               |  |                   |        |   |                  |   |        |  
|Current Liabilities                                                                                                                                                                                                                |  |                   |        |   |                  |   |        |  
|Accounts payable                                                                                                                                                                                                                   |  | $                 | 215    |   |                  | $ | 504    |  
|Accounts payable, affiliates                                                                                                                                                                                                       |  |                   |       |   |                  |   | 46     |  
|Accrued interest                                                                                                                                                                                                                   |  |                   | 91     |   |                  |   | 159    |  
|Accrued liabilities and other current liabilities                                                                                                                                                                                  |  |                   | 194    |   |                  |   | 649    |  
|Liabilities from risk-management activities                                                                                                                                                                                        |  |                   | 339    |   |                  |   | 687    |  
|Liabilities held for sale (Note 3)                                                                                                                                                                                                 |  |                   | 1      |   |                  |   |       |  
|Notes payable and current portion of long-term debt                                                                                                                                                                                |  |                   | 48     |   |                  |   | 71     |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Current Liabilities                                                                                                                                                                                                          |  |                   | 888    |   |                  |   | 2,116  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Long-term debt                                                                                                                                                                                                                     |  |                   | 3,162  |   |                  |   | 4,028  |  
|Long-term debt, affiliates                                                                                                                                                                                                         |  |                   | 200    |   |                  |   | 200    |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Long-Term Debt                                                                                                                                                                                                                     |  |                   | 3,362  |   |                  |   | 4,228  |  
|Other Liabilities                                                                                                                                                                                                                  |  |                   |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                                                                                                                                                        |  |                   | 112    |   |                  |   | 255    |  
|Deferred income taxes                                                                                                                                                                                                              |  |                   | 440    |   |                  |   | 558    |  
|Other long-term liabilities                                                                                                                                                                                                        |  |                   | 391    |   |                  |   | 429    |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Liabilities                                                                                                                                                                                                                  |  |                   | 5,193  |   |                  |   | 7,586  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Commitments and Contingencies (Note 10)                                                                                                                                                                                            |  |                   |        |   |                  |   |        |  
|Redeemable Preferred Securities, redemption value of $400 at December 31, 2005                                                                                                                                                     |  |                   |       |   |                  |   | 400    |  
|Stockholders Equity                                                                                                                                                                                                               |  |                   |        |   |                  |   |        |  
|Class A Common Stock, no par value, 900,000,000 shares authorized at September 30, 2006 and December 31, 2005; 402,895,968 and
305,129,052 shares issued and outstanding at September 30, 2006 and December 31, 2005, respectively |  |                   | 3,366  |   |                  |   | 2,949  |  
|Class B Common Stock, no par value, 360,000,000 shares authorized at September 30, 2006 and December 31, 2005; 96,891,014 shares
issued and outstanding at September 30, 2006 and December 31, 2005                                |  |                   | 1,006  |   |                  |   | 1,006  |  
|Additional paid-in capital                                                                                                                                                                                                         |  |                   | 37     |   |                  |   | 51     |  
|Subscriptions receivable                                                                                                                                                                                                           |  |                   | (8     | ) |                  |   | (8     | )
|Accumulated other comprehensive income, net of tax                                                                                                                                                                                 |  |                   | 59     |   |                  |   | 4      |  
|Accumulated deficit                                                                                                                                                                                                                |  |                   | (2,077 | ) |                  |   | (1,793 | )
|Treasury stock, at cost, 1,786,224 shares at September 30, 2006 and 1,714,026 shares at December 31, 2005                                                                                                                          |  |                   | (69    | ) |                  |   | (69    | )
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Stockholders Equity                                                                                                                                                                                                         |  |                   | 2,314  |   |                  |   | 2,140  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                                                                                                                                                         |  | $                 | 7,507  |   |                  | $ | 10,126 |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |   |        |  

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 EndedSeptember 30, |       |   | Nine Months EndedSeptember 30, |  
|                                                                                                                              |  | 2006                            |       |   | 2005                           |   |       | 2006 |  |   | 2005   |  
|Revenues                                                                                                                      |  | $                               | 581   |   |                                | $ | 770   |      |  | $ | 1,620  |   |  | $ | 1,691  |  
|Cost of sales, exclusive of depreciation shown separately below                                                               |  |                                 | (387  | ) |                                |   | (572  | )    |  |   | (1,103 | ) |  |   | (1,482 | )
|Depreciation and amortization expense                                                                                         |  |                                 | (57   | ) |                                |   | (56   | )    |  |   | (174   | ) |  |   | (165   | )
|Impairment and other charges                                                                                                  |  |                                 | (96   | ) |                                |   |      |      |  |   | (107   | ) |  |   | (6     | )
|Gain (loss) on sale of assets, net                                                                                            |  |                                 |      |   |                                |   | (1    | )    |  |   | 3      |   |  |   | (1     | )
|General and administrative expenses                                                                                           |  |                                 | (59   | ) |                                |   | (76   | )    |  |   | (160   | ) |  |   | (421   | )
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Operating income (loss)                                                                                                       |  |                                 | (18   | ) |                                |   | 65    |      |  |   | 79     |   |  |   | (384   | )
|Earnings from unconsolidated investments                                                                                      |  |                                 | 4     |   |                                |   | 7     |      |  |   | 6      |   |  |   | 14     |  
|Interest expense                                                                                                              |  |                                 | (105  | ) |                                |   | (99   | )    |  |   | (310   | ) |  |   | (284   | )
|Debt conversion costs                                                                                                         |  |                                 | (2    | ) |                                |   |      |      |  |   | (249   | ) |  |   |       |  
|Other income and expense, net                                                                                                 |  |                                 | 11    |   |                                |   |      |      |  |   | 41     |   |  |   | 9      |  
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Loss from continuing operations before income taxes                                                                           |  |                                 | (110  | ) |                                |   | (27   | )    |  |   | (433   | ) |  |   | (645   | )
|Income tax benefit (Note 13)                                                                                                  |  |                                 | 39    |   |                                |   | 13    |      |  |   | 154    |   |  |   | 228    |  
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Loss from continuing operations                                                                                               |  |                                 | (71   | ) |                                |   | (14   | )    |  |   | (279   | ) |  |   | (417   | )
|Income from discontinued operations, net of tax benefit (expense) of $(6), $(26), $(5) and $54, respectively (Notes 3 and 13) |  |                                 | 2     |   |                                |   | 43    |      |  |   | 3      |   |  |   | 209    |  
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Income (loss) before cumulative effect of change in accounting principle                                                      |  |                                 | (69   | ) |                                |   | 29    |      |  |   | (276   | ) |  |   | (208   | )
|Cumulative effect of change in accounting principle, net of tax expense of zero                                               |  |                                 |      |   |                                |   |      |      |  |   | 1      |   |  |   |       |  
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Net income (loss)                                                                                                             |  |                                 | (69   | ) |                                |   | 29    |      |  |   | (275   | ) |  |   | (208   | )
|Less: preferred stock dividends                                                                                               |  |                                 |      |   |                                |   | 6     |      |  |   | 9      |   |  |   | 17     |  
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Net income (loss) applicable to common stockholders                                                                           |  | $                               | (69   | ) |                                | $ | 23    |      |  | $ | (284   | ) |  | $ | (225   | )
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Earnings (Loss) Per Share (Note 9):                                                                                           |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Basic earnings (loss) per share:                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Loss from continuing operations                                                                                               |  | $                               | (0.14 | ) |                                | $ | (0.05 | )    |  | $ | (0.65  | ) |  | $ | (1.13  | )
|Income from discontinued operations                                                                                           |  |                                 |      |   |                                |   | 0.11  |      |  |   | 0.01   |   |  |   | 0.54   |  
|Cumulative effect of change in accounting principle                                                                           |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |       |  
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Basic earnings (loss) per share                                                                                               |  | $                               | (0.14 | ) |                                | $ | 0.06  |      |  | $ | (0.64  | ) |  | $ | (0.59  | )
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Diluted earnings (loss) per share:                                                                                            |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Loss from continuing operations                                                                                               |  | $                               | (0.14 | ) |                                | $ | (0.05 | )    |  | $ | (0.65  | ) |  | $ | (1.13  | )
|Income from discontinued operations                                                                                           |  |                                 |      |   |                                |   | 0.11  |      |  |   | 0.01   |   |  |   | 0.54   |  
|Cumulative effect of change in accounting principle                                                                           |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |       |  
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Diluted earnings (loss) per share                                                                                             |  | $                               | (0.14 | ) |                                | $ | 0.06  |      |  | $ | (0.64  | ) |  | $ | (0.59  | )
|                                                                                                                              |  |                                 |       |   |                                |   |       |      |  |   |        |   |  |   |        |  
|Basic shares outstanding                                                                                                      |  |                                 | 495   |   |                                |   | 390   |      |  |   | 446    |   |  |   | 383    |  
|Diluted shares outstanding                                                                                                    |  |                                 | 497   |   |                                |   | 516   |      |  |   | 512    |   |  |   | 509    |  

See the notes to condensed consolidated financial statements.



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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



|                                                                                               |  |                                |        |   |      |   |      |  
|---------------------------------------------------------------------------------------------- |  | ------------------------------ | ------ | - | ---- | - | ---- | -
|                                                                                               |  | Nine Months EndedSeptember 30, |       
|                                                                                               |  | 2006                           |        |   | 2005 |  
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                          |  |                                |        |   |      |   |      |  
|Net loss                                                                                       |  | $                              | (275   | ) |      | $ | (208 | )
|Adjustments to reconcile net loss to net cash flows from operating activities:                 |  |                                |        |   |      |   |      |  
|Depreciation and amortization                                                                  |  |                                | 206    |   |      |   | 207  |  
|Impairment and other charges                                                                   |  |                                | 107    |   |      |   | (1   | )
|(Earnings) losses from unconsolidated investments, net of cash distributions                   |  |                                | (6     | ) |      |   | 47   |  
|Risk-management activities                                                                     |  |                                | (70    | ) |      |   | (11  | )
|Gain on sale of assets, net                                                                    |  |                                | (3     | ) |      |   | (9   | )
|Deferred income taxes                                                                          |  |                                | (147   | ) |      |   | (284 | )
|Cumulative effect of change in accounting principle, net of tax (Note 1)                       |  |                                | (1     | ) |      |   |     |  
|Legal and settlement charges                                                                   |  |                                | 14     |   |      |   | 110  |  
|Independence toll settlement costs                                                             |  |                                |       |   |      |   | 169  |  
|Sithe Subordinated Debt exchange charge                                                        |  |                                | 36     |   |      |   |     |  
|Debt conversion costs                                                                          |  |                                | 249    |   |      |   |     |  
|Other                                                                                          |  |                                | 39     |   |      |   | 11   |  
|Changes in working capital:                                                                    |  |                                |        |   |      |   |      |  
|Accounts receivable                                                                            |  |                                | 353    |   |      |   | (199 | )
|Inventory                                                                                      |  |                                | 12     |   |      |   | (9   | )
|Prepayments and other assets                                                                   |  |                                | 119    |   |      |   | 101  |  
|Accounts payable and accrued liabilities                                                       |  |                                | (817   | ) |      |   | (113 | )
|Changes in non-current assets                                                                  |  |                                | 11     |   |      |   | (4   | )
|Changes in non-current liabilities                                                             |  |                                | (7     | ) |      |   | 15   |  
|                                                                                               |  |                                |        |   |      |   |      |  
|Net cash used in operating activities                                                          |  |                                | (180   | ) |      |   | (178 | )
|                                                                                               |  |                                |        |   |      |   |      |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                          |  |                                |        |   |      |   |      |  
|Capital expenditures                                                                           |  |                                | (92    | ) |      |   | (132 | )
|Proceeds from asset sales, net                                                                 |  |                                | 18     |   |      |   | 106  |  
|Business acquisitions, net of cash acquired                                                    |  |                                |       |   |      |   | (120 | )
|Proceeds from exchange of unconsolidated investments, net of cash acquired (Note 2 and Note 3) |  |                                | 165    |   |      |   |     |  
|Decrease (increase) in restricted cash and restricted investments                              |  |                                | 125    |   |      |   | (26  | )
|Other investing                                                                                |  |                                | (3     | ) |      |   |     |  
|                                                                                               |  |                                |        |   |      |   |      |  
|Net cash provided by (used in) investing activities                                            |  |                                | 213    |   |      |   | (172 | )
|                                                                                               |  |                                |        |   |      |   |      |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                          |  |                                |        |   |      |   |      |  
|Proceeds from long-term borrowings, net                                                        |  |                                | 1,071  |   |      |   |     |  
|Repayments of long-term borrowings                                                             |  |                                | (1,780 | ) |      |   | (40  | )
|Debt conversion costs                                                                          |  |                                | (249   | ) |      |   |     |  
|Redemption of Series C Preferred (Note 8)                                                      |  |                                | (400   | ) |      |   |     |  
|Proceeds from issuance of capital stock                                                        |  |                                | 183    |   |      |   | 2    |  
|Dividends and other distributions, net                                                         |  |                                | (17    | ) |      |   | (22  | )
|Other financing, net                                                                           |  |                                | (2     | ) |      |   | (13  | )
|                                                                                               |  |                                |        |   |      |   |      |  
|Net cash used in financing activities                                                          |  |                                | (1,194 | ) |      |   | (73  | )
|                                                                                               |  |                                |        |   |      |   |      |  
|Net decrease in cash and cash equivalents                                                      |  |                                | (1,161 | ) |      |   | (423 | )
|Cash and cash equivalents, beginning of period                                                 |  |                                | 1,549  |   |      |   | 628  |  
|Less: Cash classified as held for sale at end of period (Note 3)                               |  |                                |       |   |      |   | (18  | )
|                                                                                               |  |                                |        |   |      |   |      |  
|Cash and cash equivalents, end of period                                                       |  | $                              | 388    |   |      | $ | 187  |  
|                                                                                               |  |                                |        |   |      |   |      |  
|Other non-cash financing activity:                                                             |  |                                |        |   |      |   |      |  
|Conversion of Convertible Subordinated Debentures due 2023 (Note 7)                            |  | $                              | 225    |   |      | $ |     |  
|Sithe Subordinated Debt exchange, net (Note 7)                                                 |  |                                | 122    |   |      |   |     |  

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 EndedSeptember 30, |     
|                                                                                                           |  | 2006                            |      |   | 2005 |  
|Net income (loss)                                                                                          |  | $                               | (69  | ) |      | $ | 29   |  
|Cash flow hedging activities, net:                                                                         |  |                                 |      |   |      |   |      |  
|Unrealized mark-to-market gains (losses) arising during period, net                                        |  |                                 | 38   |   |      |   | (60  | )
|Reclassification of mark-to-market losses to earnings, net                                                 |  |                                 | 2    |   |      |   | 50   |  
|                                                                                                           |  |                                 |      |   |      |   |      |  
|Changes in cash flow hedging activities, net (net of tax benefit (expense) of ($23) and $5, respectively)  |  |                                 | 40   |   |      |   | (10  | )
|Foreign currency translation adjustments                                                                   |  |                                 | (1   | ) |      |   | 5    |  
|                                                                                                           |  |                                 |      |   |      |   |      |  
|Other comprehensive income (loss), net of tax                                                              |  |                                 | 39   |   |      |   | (5   | )
|                                                                                                           |  |                                 |      |   |      |   |      |  
|Comprehensive income (loss)                                                                                |  | $                               | (30  | ) |      | $ | 24   |  
|                                                                                                           |  |                                 |      |   |      |   |      |  
|                                                                                                           | 
|                                                                                                           |  | Nine Months EndedSeptember 30,  |     
|                                                                                                           |  | 2006                            |      |   | 2005 |  
|Net loss                                                                                                   |  | $                               | (275 | ) |      | $ | (208 | )
|Cash flow hedging activities, net:                                                                         |  |                                 |      |   |      |   |      |  
|Unrealized mark-to-market gains (losses) arising during period, net                                        |  |                                 | 63   |   |      |   | (81  | )
|Reclassification of mark-to-market (gains) losses to earnings, net                                         |  |                                 | (10  | ) |      |   | 61   |  
|                                                                                                           |  |                                 |      |   |      |   |      |  
|Changes in cash flow hedging activities, net (net of tax benefit (expense) of ($31) and $12, respectively) |  |                                 | 53   |   |      |   | (20  | )
|Foreign currency translation adjustments                                                                   |  |                                 | 2    |   |      |   | 5    |  
|                                                                                                           |  |                                 |      |   |      |   |      |  
|Other comprehensive income (loss), net of tax                                                              |  |                                 | 55   |   |      |   | (15  | )
|                                                                                                           |  |                                 |      |   |      |   |      |  
|Comprehensive loss                                                                                         |  | $                               | (220 | ) |      | $ | (223 | )
|                                                                                                           |  |                                 |      |   |      |   |      |  

See the notes to condensed consolidated financial statements.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods
Ended September 30, 2006 and 2005

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 consolidated 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, 2005, which we refer to as our Form 10-K, and our Form 10-K for the year ended December 31, 2005,
as amended on May 1, 2006, which we refer to as our Form 10-K/A.

The unaudited condensed consolidated financial
statements contained in this report include all material adjustments of a normal and recurring nature 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 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 their publication. 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, 2005, our ARO liabilities were $48 million for our GEN-MW segment and $8 million for our
GEN-NE segment. These AROs related to activities such as ash pond and landfill capping, dismantlement of power generation facilities, 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 nine months ended September 30, 2006, we recorded additional
AROs of zero and $5 million, respectively, no material AROs were settled, and revisions to estimated cash flows were not material. During the three and nine months ended September 30, 2006, our accretion expenses were approximately $2 million
and $5 million, respectively, which are included in cost of sales on our unaudited condensed consolidated statements of operations. During the three and nine months ended September 30, 2005, there were no material additional AROs recorded or
settled, and our accretion expenses and revisions to estimated cash flows were not material. At September 30, 2006, our ARO liabilities were $52 million for our GEN-MW segment and $14 million for our GEN-NE segment.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Accounting Principles Adopted

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

In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which revises
SFAS No. 123. SFAS No. 123(R) requires all companies to expense the fair value of employee stock options and other forms of stock-based compensation. We adopted SFAS No. 123(R) effective January 1, 2006, using the modified
prospective transition method permitted under this pronouncement. Our cumulative effect of implementing this standard, which consists entirely of a forfeiture adjustment recorded in the first quarter 2006, was less than $1 million after tax. The
application of SFAS 123(R) had no material impact on the unaudited condensed consolidated statements of cash flows and basic and diluted loss per share for the three and nine months ended September 30, 2006, compared to amounts that would have
been reported pursuant to our previous accounting.

In November 2005, the FASB issued FSP No. 123(R)-3, Transition Election
Related to Accounting for the Tax Effects of Share-Based Payment Awards. We have adopted the short-cut method to calculate the beginning balance of the APIC pool of the excess tax benefit, and to determine the subsequent impact on the APIC
pool and unaudited condensed consolidated statements of cash flows of the tax effects of employee stock-based compensation awards that were outstanding upon our adoption of FAS 123(R). Utilizing the short-cut method, we have determined that we have
a Pool of Windfall tax benefits that can be utilized to offset future shortfalls that may be incurred.

Under SFAS
No. 148s 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 2003 been determined on a fair value basis consistent with SFAS No. 123(R), our net loss and basic and diluted loss per share amounts would not have
been impacted for the three and nine months ended September 30, 2006 and 2005, respectively.

Please read Note 12Employee
Compensation, Savings and Pension Plans for further discussion of our share-based compensation.

SFAS No. 154. In May
2005, the FASB issued SFAS No. 154, Accounting Changes and Error CorrectionsA Replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 changes the requirements for the accounting for and
reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific
transition provisions. SFAS No. 154 requires retrospective



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific
effects or the cumulative effect of the change. The provisions of SFAS No. 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The adoption of this standard on
January 1, 2006 did not have a material effect on our results of operations, financial position or cash flows.

Accounting
Principles Not Yet Adopted

FIN No. 48. On July 12, 2006, the FASB issued FIN No. 48, Accounting for
Uncertainty in Income Taxes. FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in a companys financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN
No. 48 prescribes a recognition threshold and measurement attributes for the financial statement recognition and measurement of an income tax position taken or expected to be taken in an income tax return. FIN No. 48 is effective for
fiscal years beginning after December 15, 2006. We are currently evaluating the impact of this statement on our financial statements.

SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in GAAP and expands
disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, SFAS No. 157 does not require any new fair value measurements; however for
some entities the application of SFAS No. 157 will change current practice. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial
statements.

SFAS No. 158. On September 29, 2006, the FASB issued SFAS No. 158, Employers
Accounting for Defined Benefit Pension and Other Postretirement Plansan amendment of FASB Statements No. 87, 88, 106 and 132 (R). SFAS No. 158 requires employers to recognize the overfunded or underfunded status of a defined
benefit or other postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position, and to recognize changes in that funded status in the year in which the changes occur through comprehensive
income. In addition, SFAS No. 158 requires employers to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The provisions of SFAS 158 are effective for fiscal years
ending after December 15, 2006 for employers with publicly traded equity securities and retrospective application is not permitted. The disclosure and recognition provisions are required to be adopted as of December 31, 2006. We are
currently evaluating the impact of this statement on our financial statements. We estimate our pre-tax cumulative effect of implementing this standard, which will be reflected as a reduction to the ending balance of accumulated other comprehensive
income, will be approximately $65 million upon adoption at December 31, 2006.

SAB 108. On September 13, 2006, the SEC
released SAB 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. SAB 108 states that a registrants materiality evaluation of an identified unadjusted error
should quantify the effects of the identified unadjusted error on each financial statement and related financial statement disclosure. SAB 108 also states that registrants electing not to restate prior periods should reflect the effects of initially
applying SAB 108 in their annual financial statements covering the first fiscal year ending after November 15, 2006. We do not believe the impact of this SAB will have a material effect on our results of operations, financial position or cash
flows.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Note 2Business Combinations

LS Power.On September 14, 2006, we entered into a Plan of Merger, Contribution and Sale Agreement (the Merger Agreement)
by and among Dynegy Inc., Dynegy Acquisition, Inc., a Delaware corporation (New Dynegy), Falcon Merger Sub Co., an Illinois corporation and a wholly owned subsidiary of New Dynegy (Merger Sub), LSP Gen Investors, L.P., LS
Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Associates, L.P., and LS Power Equity Partners, L.P. (collectively, the LS Entities), pursuant to which Merger Sub will be merged with and into us, as a result of which
we and DHI will become wholly-owned subsidiaries of New Dynegy.

We will combine our current assets and operations with the LS
Entities generation portfolio, and will acquire a 50 percent ownership interest in a development company that is currently controlled by the LS Entities. In the merger, each share of our Class A Common Stock and our Class B Common Stock
will be converted into the right to receive one share of New Dynegy Class A Common Stock, par value $0.01 per share (New Dynegy Class A Common Stock).

In the transaction, the LS Entities will contribute certain interests in power generation assets to New Dynegy in exchange for (i) 340 million
shares of New Dynegy Class B Common Stock, par value $0.01 per share (New Dynegy Class B Common Stock and, together with New Dynegy Class A Common Stock, the New Dynegy Common Stock), (ii) $100 million in cash and
(iii) $275 million in aggregate principal amount of notes to be issued by New Dynegy.

Under the terms of the Merger Agreement, we and
the LS Entities agreed not to (i) solicit proposals relating to alternative business combination transactions or (ii) subject to certain exceptions, enter into discussions or an agreement concerning or provide confidential information in
connection with any proposals for alternative business combination transactions. The Merger Agreement provides certain termination rights to both us and the LS Entities, and further provides that, upon termination of the Merger Agreement under
certain circumstances, (i) we may be required to pay the LS Entities or (ii) the LS Entities may be required to pay us, an aggregate termination fee of $100 million, as described in the Merger Agreement. The affirmative vote of two-thirds
of the (i) issued and outstanding shares of our Class A Common Stock voting as a class, (ii) issued and outstanding shares of our Class B Common Stock voting as a class and (iii) issued and outstanding shares of our Common Stock
voting together as a class is required to approve the merger. The consummation of the merger is subject to various other conditions, including: (i) the expiration or termination of applicable waiting periods under the HSR, (ii) approval
from the FERC, (iii) registration of the shares of New Dynegy Class A Common Stock to be issued to our shareholders in the merger under the Securities Act of 1933, as amended (the Securities Act), (iv) approval from the
New York State Public Service Commission and (v) satisfaction of certain other conditions. Assuming all necessary conditions are satisfied, which cannot be guaranteed, the transaction is expected to close in early 2007.

On September 14, 2006, the LS Entities and Kendall Power LLC (Kendall Power), a newly formed wholly owned subsidiary of Dynegy, entered
into a Limited Liability Company Membership Interests and Stock Purchase Agreement (the Kendall Agreement) pursuant to which Kendall Power agreed to acquire all of the outstanding interests in LSP Kendall Holdings, LLC for $200 million
in cash, as adjusted for certain changes in working capital. The closing of the Kendall Agreement will occur only if closing does not occur with respect to the transactions contemplated by the Merger Agreement. We have agreed to guarantee certain of
Kendall Powers obligations under the Kendall Agreement. The consummation of the Kendall Agreement is subject to various conditions, including: (i) the termination of the Merger Agreement; (ii) the expiration or termination of
applicable waiting periods under



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



the HSR; and (iii) satisfaction of certain other conditions. Please read Note 10Commitments and ContingenciesGuarantees and
IndemnificationsKendall Guarantee for further discussion.

Rocky Road.On March 31, 2006, contemporaneous with our
sale of our interest in WCP (Generation) Holdings LLC (West Coast Power) (please read Note 3 Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsWest Coast Power), we
completed our acquisition of NRGs 50% ownership interest in Rocky Road Power, LLC (Rocky Road), the entity that owns the Rocky Road power plant, a 364-megawatt natural gas-fired peaking facility near Chicago (of which we already
owned 50%), for net proceeds of $165 million, net of cash acquired. As a result of the transaction, we became the primary beneficiary of the entity as provided under the guidance in FIN No. 46(R), Consolidation of Variable Interest
Entities an interpretation of ARB No. 51 and thus consolidated the assets and liabilities of the entity at March 31, 2006. Please read Note 6Unconsolidated InvestmentsVariable Interest Entities for further discussion.

Note 3Dispositions, Contract Terminations and Discontinued Operations

Dispositions and Contract Terminations

Rockingham. On May 21, 2006, we entered into an agreement with Duke Energy Carolinas, LLC (a subsidiary of Duke Energy) for the sale of our Rockingham facility, a peaking facility in North Carolina, which is included in
our GEN-SO segment, for $195 million in cash. The transaction is expected to close in the fourth quarter 2006, subject to obtaining certain regulatory approvals and satisfaction of customary closing conditions. A portion of the proceeds from the
sale will be used to repay our borrowings under the $150 million Term Loan, with the remaining proceeds used as an additional source of liquidity. Please read Note 7DebtSenior Secured Credit Facility for further discussion of the Term
Loan.

Beginning in the second quarter 2006, Rockingham 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 and
liabilities held for sale at September 30, 2006 are $194 million of Property, Plant and Equipment, Net, $1 million of Inventory and $1 million of Accrued liabilities and other current liabilities.

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 Rockingham's property, plant and equipment during the second quarter 2006. Depreciation and amortization expense related to Rockingham totaled zero and $2 million in the three- and nine-month periods
ended September 30, 2006, compared to $1 million and $4 million in the three- and nine-month periods ended September 30, 2005. 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. Accordingly, we recorded pre-tax impairments of zero and $9 million in the three and nine months ended September 30, 2006, respectively, which are included in Impairment and other charges
on our unaudited condensed consolidated statements of operations.

West Coast Power. On March 31, 2006, contemporaneous
with our purchase of Rocky Road (please read Note 2Business CombinationsRocky Road), we completed our sale to NRG of our 50% ownership interest in West Coast Power, a joint venture between us and NRG which has ownership in the West Coast
Power power plants in southern California totaling approximately 1,800 megawatts, for net proceeds of approximately $165 million, net of cash acquired. We did not recognize a material gain or loss on the sale. Pursuant to our divestiture of West



12



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Coast Power, we no longer maintain a significant variable interest in the entity as provided by the guidance in FIN
No. 46(R). Please read Note 6Unconsolidated InvestmentsVariable Interest Entities for further discussion.

Sterlington Contract Termination. In December 2005, we entered into an agreement to terminate the Sterlington long-term wholesale power tolling contract with Quachita Power LLC (Quachita), a joint venture of GE
Energy Financial Services and Cogentrix Energy, Inc. Under the terms of the agreement, we paid Quachita approximately $370 million in March 2006 to eliminate approximately $449 million in capacity payment obligations through 2012 and avoid
approximately $295 million in additional capacity payment obligations that would arise if Quachita exercised its option to extend the contract through 2017. We recognized a pre-tax charge of approximately $364 million ($229 million after-tax) in the
fourth quarter 2005 related to this transaction.

Discontinued Operations

Natural Gas Liquids. On October 31, 2005, we completed the sale of DMSLP, which comprised substantially all remaining operations of our
NGL segment, to Targa Resources Inc. (Targa) and two of its subsidiaries for $2.44 billion in cash. At closing, we received $2.35 billion in cash proceeds. As of September 30, 2006, we received a substantial majority of the balance
of the sales proceeds from Targa, which represented our cash collateral related to DMSLP. Targa assumed responsibility for approximately $47 million in letters of credit provided by us for the benefit of DMSLP, and those letters of credit were all
replaced by December 31, 2005.

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 was required to be repaid upon the sale of DMSLP should be reclassified to discontinued operations. Therefore, interest expense on our former term loan and our former generation facility debt was allocated to discontinued
operations, as the respective debt instruments were paid upon the sale of DMSLP. Such interest expense, inclusive of amortization of debt issuance costs, totaled zero and $15 million for the three months ended September 30, 2006 and 2005,
respectively, and zero and $40 million for the nine months ended September 30, 2006 and 2005, respectively.

Additionally, results
from NGLs operations include revenues and cost of sales arising from intersegment transactions, which ceased after the sale of DMSLP. NGL processed natural gas and sold this natural gas to CRM for resale to third parties. NGL also purchased
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, were also reclassified to discontinued operations.



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##### Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Other. We sold or liquidated some of our operations during 2003, including DGC (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 September 30, 2006      |  |               |    |   |     |   |    |     |  |       |       |  |   |      
|Income from operations before taxes        |  | $             | 6  |   |     | $ |   |     |  | $     | 2     |  | $ | 8    
|Income (loss) from operations after taxes  |  |               | (2 | ) |     |   |   |     |  |       | 4     |  |   | 2    
|                                           |  |               |    |  
|Three Months Ended September 30, 2005      |  |               |    |   |     |   |    |     |  |       |       |  |   |      
|Revenues                                   |  | $             |   |   |     | $ |   |     |  | $     | 1,193 |  | $ | 1,193
|Income (loss) from operations before taxes |  |               | (2 | ) |     |   |   |     |  |       | 71    |  |   | 69   
|Income (loss) from operations after taxes  |  |               | (4 | ) |     |   | (2 | )   |  |       | 49    |  |   | 43   
|                                           |  |               |    |  
|                                           |  | U.K. CRM      |    |   | DGC |   |    | NGL |  | Total
|                                           |  | (in millions)
|Nine Months Ended September 30, 2006       |  |               |    |   |     |   |    |     |  |       |       |  |   |      
|Income from operations before taxes        |  | $             | 5  |   |     | $ |   |     |  | $     | 3     |  | $ | 8    
|Income (loss) from operations after taxes  |  |               | (1 | ) |     |   |   |     |  |       | 4     |  |   | 3    
|                                           |  |               |    |  
|Nine Months Ended September 30, 2005       |  |               |    |   |     |   |    |     |  |       |       |  |   |      
|Revenues                                   |  | $             |   |   |     | $ |   |     |  | $     | 3,172 |  | $ | 3,172
|Income from operations before taxes        |  |               | 3  |   |     |   |   |     |  |       | 152   |  |   | 155  
|Income (loss) from operations after taxes  |  |               | (1 | ) |     |   |   |     |  |       | 210   |  |   | 209  

In the three and nine months ended September 30, 2006, we recognized approximately $6 million
of pre-tax income associated with a receivable previously reserved that is now expected to be collected. In the nine months ended September 30, 2005, we recognized $3 million of pre-tax income primarily associated with U.K. CRMs receipt
of a third party bankruptcy settlement.

Note 4Restructuring and Impairment Charges

Asset Impairment. At September 30, 2006, we tested the Bluegrass generation facility for impairment based on the FERC's recent approval
and Louisville Gas and Electrics (LG&E) completion of various compliance steps to allow it to withdraw from participation in the MISO market as of September 1, 2006. The Bluegrass facility has historically sold power into
the MISO market through transmission provided by LG&E. This change will limit our ability or increase the cost to deliver power to the MISO market. After testing, we recorded a pre-tax impairment charge of $96 million ($61 million after-tax) in
the GEN-MW segment. This charge is included in impairment and other charges in our unaudited condensed consolidated statement of operations. We determined the fair value of the facility using the expected present value technique.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



2005 Restructuring. In December 2005, in order to better align our corporate cost
structure with a single line of business and as part of a comprehensive effort to reduce on-going operating expenses, we implemented a restructuring plan (the 2005 Restructuring Plan). The 2005 Restructuring Plan resulted in a reduction
of approximately 40 positions and was complete by June 30, 2006. We recognized a pre-tax charge, primarily in our Other segment, of $11 million in the fourth quarter 2005. We recognized approximately zero and $2 million of charges in the three
and nine months ended September 30, 2006, respectively, when transitional services were completed by certain affected employees. These charges related entirely to severance costs.

The following is a schedule of 2006 activity for the severance liabilities recorded in connection with this restructuring (in millions):



|                              |  |   |     |  
|----------------------------- |  | - | --- | -
|Balance at December 31, 2005  |  | $ | 9   |  
|2006 adjustments to liability |  |   | 2   |  
|Cash payments                 |  |   | (11 | )
|                              |  |   |     |  
|Balance at September 30, 2006 |  | $ |    |  
|                              |  |   |     |  

2002 Restructuring. 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 2006
activity for the liabilities recorded in connection with this restructuring:



|                              |  |               |   |                                     |   |    |       |  |   |    |  
|----------------------------- |  | ------------- | - | ----------------------------------- | - | -- | ----- |  | - | -- | -
|                              |  | Severance     |   | CancellationFees andOperatingLeases |   |    | Total | 
|                              |  | (in millions) |  
|Balance at December 31, 2005  |  | $             | 3 |                                     | $ | 16 |       |  | $ | 19 |  
|Cash payments                 |  |               |  |                                     |   | (7 | )     |  |   | (7 | )
|                              |  |               |   |                                     |   |    |       |  |   |    |  
|Balance at September 30, 2006 |  | $             | 3 |                                     | $ | 9  |       |  | $ | 12 |  
|                              |  |               |   |                                     |   |    |       |  |   |    |  

Including the $2 million accrual for operating leases made in connection with the sale of DMSLP
(for further information, please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDiscontinued Operations Natural Gas Liquids), we have an aggregate accrual of $11 million as of September 30, 2006,
associated with operating leases. We expect this amount to be paid by the end of 2007, when the leases expire.

Note 5Risk Management Activities
and Accumulated Other Comprehensive Income

The nature of our business 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 6Risk Management Activities and Financial Instruments beginning on page F-32 of
our Form 10-K/A.

Cash Flow Hedges. We enter into financial derivative instruments that qualify and are designated as cash
flow hedges. Instruments related to our GEN business are entered into for purposes of hedging future fuel requirements and sales commitments and locking in commodity prices we consider favorable under the circumstances. Interest rate swaps have been
used to convert floating interest-rate obligations to fixed-rate obligations.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



During the three and nine months ended September 30, 2006, we recorded $3 million and $7
million, respectively, of income related to ineffectiveness from changes in fair value of cash flow hedge positions, and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three
and nine months ended September 30, 2005, we recorded $10 million and $4 million of income, 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 nine months ended September 30, 2006 and 2005, no amounts were reclassified to earnings in connection with forecasted transactions that were probable of not
occurring.

The balance in cash flow hedging activities, net at September 30, 2006, is expected to be reclassified to future earnings,
contemporaneously with the related purchases of fuel, sales of electricity and payments of interest, as applicable to each type of hedge. Of this amount, after-tax gains of approximately $34 million are currently estimated to be reclassified into
earnings over the 12-month period ending September 30, 2007. 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 and are designated 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 nine months ended September 30, 2006 and 2005, there was no ineffectiveness from changes in the fair
value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and nine months ended September 30, 2006 and 2005, 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 have remaining investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. As of September 30, 2006, we had no net investment hedges in place.

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



|                                                   |  |                   |     |   |                  |   |     |  
|-------------------------------------------------- |  | ----------------- | --- | - | ---------------- | - | --- | -
|                                                   |  | September 30,2006 |     |   | December 31,2005 |  
|                                                   |  | (in millions)     |    
|Cash flow hedging activities, net                  |  | $                 | 51  |   |                  | $ | (2  | )
|Foreign currency translation adjustment            |  |                   | 26  |   |                  |   | 24  |  
|Minimum pension liability                          |  |                   | (18 | ) |                  |   | (18 | )
|                                                   |  |                   |     |   |                  |   |     |  
|Accumulated other comprehensive income, net of tax |  | $                 | 59  |   |                  | $ | 4   |  
|                                                   |  |                   |     |   |                  |   |     |  



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Note 6Unconsolidated Investments

A summary of our unconsolidated investments is as follows:



|                                 |  |                   |   |                  |   |    
|-------------------------------- |  | ----------------- | - | ---------------- | - | ---
|                                 |  | September 30,2006 |   | December 31,2005
|                                 |  | (in millions)    
|Equity affiliates:               |  |                   |   |                  |   |    
|GEN  MW                         |  | $                 |  |                  | $ | 60 
|GEN  SO                         |  |                   | 7 |                  |   | 210
|                                 |  |                   |   |                  |   |    
|Total unconsolidated investments |  | $                 | 7 |                  | $ | 270
|                                 |  |                   |   |                  |   |    

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



|                 |  |                                  |    |              |   |       |  |              |     |  |   |    
|---------------- |  | -------------------------------- | -- | ------------ | - | ----- |  | ------------ | --- |  | - | ---
|                 |  | Three Months Ended September 30,
|                 |  | 2006                             |    | 2005        
|                 |  | Total                            |    | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)                   
|Revenues         |  | $                                | 16 |              | $ | 8     |  | $            | 162 |  | $ | 70 
|Operating income |  |                                  | 6  |              |   | 3     |  |              | 36  |  |   | 16 
|Net income       |  |                                  | 6  |              |   | 3     |  |              | 34  |  |   | 16 
|                 | 
|                 |  | Nine Months Ended September 30, 
|                 |  | 2006                             |    | 2005        
|                 |  | Total                            |    | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)                   
|Revenues         |  | $                                | 76 |              | $ | 38    |  | $            | 510 |  | $ | 212
|Operating income |  |                                  | 16 |              |   | 8     |  |              | 64  |  |   | 27 
|Net income       |  |                                  | 13 |              |   | 6     |  |              | 63  |  |   | 27 

Earnings from unconsolidated investments for the three months ended September 30, 2006 were
$3 million. Earnings from unconsolidated investments of $16 million for the three months ended September 30, 2005 includes $1 million of earnings from NGL investments, which are included in income from discontinued operations on our unaudited
condensed consolidated statements of operations. Earnings in 2005 were offset by an impairment of $8 million in our investment in West Coast Power.

Earnings from unconsolidated investments of $6 million for the nine months ended September 30, 2006, were offset by a $1 million impairment of our investment in Panama. Earnings from unconsolidated investments of $27 million for the
nine months ended September 30, 2005, includes $5 million of earnings from NGL investments which are included in income from discontinued operations on our unaudited condensed consolidated statements of operations. Earnings in 2005 were offset
by an impairment of $8 million in our investment in West Coast Power.

On May 15, 2006, we sold our interests in our power generating
facility located in Panama. Net proceeds associated with the sale were approximately $3 million, and we did not recognize a gain or loss on the sale.

On March 31, 2006, we completed the sale to NRG of our 50% ownership interest in our unconsolidated investment in West Coast Power as well as our acquisition of NRGs ownership interest in Rocky Road. As a
result



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



of the transactions, we received cash proceeds of approximately $165 million, net of cash acquired, from NRG. Under the terms of this agreement, we did not
recognize a material gain or loss on the sale of West Coast Power. For further discussion, please read Note 2Business CombinationsRocky Road and Note 3Dispositions, Contract Terminations and Discontinued
OperationsDispositions and Contract TerminationsWest Coast Power.

Variable Interest Entities. In conjunction
with our prior adoption of FIN No. 46(R), Rocky Road LLC was identified as a variable interest entity. At the time of adoption, we were not the primary beneficiary of, and therefore did not consolidate Rocky Road. We did not absorb a majority
of the entitys expected losses, nor receive a majority of the expected residual returns.

On March 31, 2006, we completed our
acquisition of NRGs 50% ownership interest in Rocky Road and the sale to NRG of our 50% ownership interest in West Coast Power. We paid approximately $45 million for NRGs ownership interest in Rocky Road, including $5 million of cash on
hand, and received approximately $205 million for our ownership interest in West Coast Power, resulting in the receipt of proceeds of approximately $165 million, net of cash acquired, from NRG. As we now own 100% of the outstanding equity interests
in Rocky Road, we are subjected to a majority of the entitys expected losses and expected residual returns, and are therefore considered the primary beneficiary of the entity. Thus, we consolidated the assets and liabilities of the entity at
March 31, 2006, in accordance with the guidance provided in FIN No. 46(R), which requires that the assets and liabilities of the newly consolidated entity be measured and recorded at their fair values on the date we became the primary
beneficiary. Those assets and liabilities primarily consisted of $9 million of working capital, a $29 million intangible asset related to a contract to provide capacity and energy, and $50 million of property, plant, and equipment at the
facilitys location.

In conjunction with acquiring the remaining outstanding equity interest in Rocky Road, we divested our interest
in West Coast Power. Based on that transaction, we no longer maintain a variable interest in West Coast Power. For further discussion, please read Note 2 Business CombinationsRocky Road and Note 3Dispositions, Contract Terminations
and Discontinued OperationsDispositions and Contract TerminationsWest Coast Power.

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 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, or otherwise dispose of the hydroelectric facilities owned through the VIEs. Exelon is obligated to reimburse ExRes for certain costs,
liabilities, and obligations of the entities owning these facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities. Exelon is not required to reimburse ExRes and the entities owning these
facilities for lease payments or other costs not incurred in the ordinary course of business. 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. 46(R).

These 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 September 30, 2006, the equipment leases have remaining terms from one to fifteen years and involve a maximum aggregate obligation of $120
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 a
Tracking Account, was established to quantify the



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



difference between (i) the facilitys fixed price revenues under the power purchase agreement and (ii) a percentage of 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 pricing under the respective power purchase agreement. If the decreased pricing does not reduce the tracking account to zero, a lump sum payment for the remainder
of the balance will be due. 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. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of September 30, 2006, was
approximately $309 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. 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.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Note 7Debt

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



|                                                                                        |  |                   |       |                  |   |       |  
|--------------------------------------------------------------------------------------- |  | ----------------- | ----- | ---------------- | - | ----- | -
|                                                                                        |  | September 30,2006 |       | December 31,2005 |  
|                                                                                        |  | (in millions)     |      
|Dynegy Holdings Inc.                                                                    |  |                   |       |                  |   |       |  
|Term Loan, floating rate due 2012                                                       |  | $                 | 150   |                  | $ |      |  
|Term Facility, floating rate due 2012                                                   |  |                   | 200   |                  |   |      |  
|Senior Notes, 7.45% due 2006                                                            |  |                   |      |                  |   | 22    |  
|Senior Notes, 6.875% due 2011                                                           |  |                   | 494   |                  |   | 499   |  
|Senior Notes, 8.75% due 2012                                                            |  |                   | 488   |                  |   | 491   |  
|Senior Unsecured Notes, 8.375% due 2016                                                 |  |                   | 1,047 |                  |   |      |  
|Senior Debentures, 7.125% due 2018                                                      |  |                   | 173   |                  |   | 175   |  
|Senior Debentures, 7.625% due 2026                                                      |  |                   | 173   |                  |   | 174   |  
|Second Priority Senior Secured Notes, floating rate due 2008                            |  |                   |      |                  |   | 225   |  
|Second Priority Senior Secured Notes, 9.875% due 2010                                   |  |                   | 11    |                  |   | 625   |  
|Second Priority Senior Secured Notes, 10.125% due 2013                                  |  |                   |      |                  |   | 900   |  
|Subordinated Debentures payable to affiliates, 8.316%, due 2027                         |  |                   | 200   |                  |   | 200   |  
|                                                                                        |  |                  
|Sithe Energies                                                                          |  |                   |       |                  |   |       |  
|Subordinated Debt, 7.0% due 2034                                                        |  |                   |      |                  |   | 419   |  
|Senior Notes, 8.5% due 2007                                                             |  |                   | 39    |                  |   | 57    |  
|Senior Notes, 9.0% due 2013                                                             |  |                   | 409   |                  |   | 409   |  
|                                                                                        |  |                  
|Dynegy Inc.                                                                             |  |                   |       |                  |   |       |  
|Convertible Subordinated Debentures, 4.75% due 2023                                     |  |                   |      |                  |   | 225   |  
|                                                                                        |  |                   |       |                  |   |       |  
|                                                                                        |  |                   | 3,384 |                  |   | 4,421 |  
|                                                                                        |  |                  
|Unamortized premium (discount) on debt, net                                             |  |                   | 26    |                  |   | (122  | )
|                                                                                        |  |                   |       |                  |   |       |  
|                                                                                        |  |                   | 3,410 |                  |   | 4,299 |  
|Less: Amounts due within one year, including non-cash amortization of basis adjustments |  |                   | 48    |                  |   | 71    |  
|                                                                                        |  |                   |       |                  |   |       |  
|Total Long-Term Debt                                                                    |  | $                 | 3,362 |                  | $ | 4,228 |  
|                                                                                        |  |                   |       |                  |   |       |  

Aggregate debt maturities for the remainder of 2006, the next four years and
thereafter of the principal amounts of all long-term indebtedness as of September 30, 2006 are as follows:



|                     |  |               |       |      |   |      |  |      |    |      |   |      |  |            |    |  |   |    |  |   |      
|-------------------- |  | ------------- | ----- | ---- | - | ---- |  | ---- | -- | ---- | - | ---- |  | ---------- | -- |  | - | -- |  | - | -----
|                     |  | Total         |       | 2006 |   | 2007 |  | 2008 |    | 2009 |   | 2010 |  | Thereafter
|                     |  | (in millions)
|Dynegy Holdings Inc. |  | $             | 2,929 |      | $ | 2    |  | $    |   |      | $ |     |  | $          |   |  | $ | 11 |  | $ | 2,916
|Sithe Energies       |  |               | 481   |      |   | 22   |  |      | 44 |      |   | 44   |  |            | 57 |  |   | 62 |  |   | 252  
|                     |  |               |       |      |   |      |  |      |    |      |   |      |  |            |    |  |   |    |  |   |      
|Total                |  | $             | 3,410 |      | $ | 24   |  | $    | 44 |      | $ | 44   |  | $          | 57 |  | $ | 73 |  | $ | 3,168
|                     |  |               |       |      |   |      |  |      |    |      |   |      |  |            |    |  |   |    |  |   |      



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Senior Secured Credit Facility.On April 19, 2006, we entered into a fourth
amended and restated credit agreement (the Fourth Senior Secured Credit Facility) with Citicorp USA, Inc. and JPMorgan Chase Bank, N.A., as co-administrative agents, JPMorgan Chase Bank, N.A., as collateral agent, Citicorp USA, Inc., as
payment agent, Citigroup Global Markets Inc. and JPMorgan Securities Inc., as joint lead arrangers, and the other financial institutions parties thereto as lenders. The Fourth Senior Secured Credit Facility amends our former credit facility (last
amended on March 6, 2006) by increasing the amount of the existing $400 million revolving credit facility to $470 million and adding a $200 million term letter of credit facility. The revolving facility, which is currently undrawn, is available
for general corporate purposes and for letters of credit. The term facility has been fully drawn and the proceeds placed in a collateral account to support the issuance of letters of credit. Letters of credit issued under the former credit facility
were continued under the Fourth Senior Secured Credit Facility.

The Fourth Senior Secured Credit Facility is secured by substantially all
of the assets of DHI, as borrower, and certain of its subsidiaries, as subsidiary guarantors, and certain of our assets, as parent guarantor. The revolving credit facility portion of the Fourth Senior Secured Credit Facility matures April 19,
2009 and the term letter of credit portion matures on January 31, 2012. Borrowings for both the revolving and term portions under the Fourth Senior Secured Credit Facility bear interest at the relevant Eurodollar rate plus a ratings-based
margin of 175 basis points or the relevant base rate plus a ratings-based margin of 75 basis points. Letters of credit can be issued under the revolving portion of the facility at a ratings-based rate of 175 basis points. An unused commitment fee of
50 basis points is payable on the unused portion of the revolving credit facility. The margin payable for borrowing, the rate payable for letters of credit and the unused commitment fee will decrease upon meeting specified improvements in Standard
and Poors and Moodys credit ratings for the facility.

The Fourth Senior Secured Credit Facility contains mandatory prepayment
provisions associated with specified asset sales and dispositions (including as a result of casualty or condemnation) and the receipt of proceeds by DHI and certain of its subsidiaries of any permitted additional non-recourse indebtedness.
Commencing in 2008 with respect to the fiscal year ending December 31, 2007, each year DHI will be required to apply toward the prepayment of the loans and the permanent reduction of the commitments under the revolving credit facility (or post
cash collateral in lieu thereof) a portion of its excess cash flow as calculated under the Fourth Senior Secured Credit Facility for the prior fiscal year. This portion will be 50% initially and will fall to 25% when and if DHIs leverage ratio
is less than or equal to 3.50:1.00.

The Fourth Senior Secured Credit Facility contains customary affirmative covenants and negative
covenants and events of default. Subject to certain exceptions, DHI and its subsidiaries are subject to restrictions on incurring additional indebtedness, limitations on capital expenditures and limitations on dividends and other payments in respect
of capital stock. The Fourth Senior Secured Credit Facility also contains certain financial covenants, including (1) a covenant (measured at the last day of the fiscal quarter as specified below) that requires DHI and certain of its
subsidiaries to maintain a ratio of secured debt to adjusted EBITDA no greater than 3.5:1 (September 30, 2006); 3.0:1 (December 31, 2006); 2.75:1 (March 31, 2007); 2.5:1 (June 30, 2007); 2.25:1 (September 30, 2007) and 2.0:1 (December 31, 2007 and
thereafter) and (2) a covenant that requires DHI and certain of its subsidiaries to maintain an interest coverage ratio as of the last day of the measurement periods ending September 30, 2006 of no less than 1.4:1; ending December 31,
2006 of no less than 1.50:1; ending March 31, June 30, September 30 and December 31, 2007 and March 31, 2008 of no less than 1.625:1, and ending June 30, 2008 and thereafter of no less than 1.75:1. We are in
compliance with these covenants as of September 30, 2006.

On May 26, 2006, we closed a $150 million term loan (the Term
Loan), of which $50 million was used to make a one-time cash dividend from DHI to Dynegy (the DHI Dividend) and the remainder used for working capital and general corporate purposes (please read Note 8Related Party
TransactionSeries C Convertible



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Preferred Stock). The Term Loan, which will be repaid with proceeds from the sale of Rockingham, was structured as a new tranche under the Fourth Senior
Secured Credit Facility. The Term Loan will mature on the earlier of five business days after the consummation of the pending sale of the Rockingham facility or January 31, 2012. Please read Note 3Dispositions, Contract Terminations and
Discontinued OperationsDispositions and Contract TerminationsRockingham for further discussion of the sale.

Second
Priority Senior Secured Notes. On April 12, 2006, we completed a cash tender offer and consent solicitation (the SPN Tender Offer), in which we purchased $151 million of our $225 million Second Priority Senior Secured
Floating Rate Notes due 2008 (the 2008 Notes), $614 million of our $625 million 9.875% Second Priority Senior Secured Notes due 2010 (the 2010 Notes) and all $900 million of our 10.125% Second Priority Senior Secured Notes
due 2013 (the 2013 Notes and collectively with the 2008 Notes and the 2010 Notes, the Second Priority Notes). In connection with the SPN Tender Offer, we amended the indenture under which the Second
Priority Notes were issued to eliminate or modify substantially all of the restrictive covenants, certain events of default and related provisions and release certain liens securing the obligations of DHI and the guarantors of the Second Priority
Notes.

Total cash paid to repurchase the $1,664 million of Second Priority Notes, including consent fees and accrued interest, was $1,904
million. We recorded a charge of approximately $228 million in the second quarter 2006 associated with this transaction, of which $202 million is included in debt conversion costs and $26 million of acceleration of amortization of financing costs
and write-offs of discounts and premiums is included in interest expense on our unaudited condensed consolidated statements of operations.

On July 15, 2006, we redeemed the remaining $74 million of our 2008 Notes, at a redemption price of 103% of the principal amount, plus accrued and unpaid interest to the redemption date. The interest rate on the 2008 Notes was based on
three-month LIBOR plus 650 basis points. We recorded a charge of approximately $2 million in the third quarter 2006 associated with this transaction, which is included in debt conversion costs on our unaudited condensed consolidated statements of
operations. The remaining outstanding 2010 Notes are redeemable at our option on or after July 15, 2007 in accordance with the terms of the indenture governing the Second Priority Notes.

Senior Unsecured Notes. On April 12, 2006, DHI issued $750 million aggregate principal amount of our 8.375% Senior Unsecured Notes due
2016 (the New Senior Notes) in a private offering (the Senior Notes Offering). The New Senior Notes are not redeemable at our option prior to maturity. The New Senior Notes are our senior unsecured obligations and rank equal
in right of payment to all of our existing and future senior unsecured indebtedness, and are senior to all of our existing and any of our future subordinated indebtedness. We have not guaranteed the New Senior Notes, and the assets and operations
that we own through subsidiaries other than DHI (principally our Independence plant) do not support the New Senior Notes. The proceeds from the Senior Notes Offering, together with cash on hand, were used to fund the SPN Tender Offer discussed
above. On September 14, 2006, DHI exchanged the New Senior Notes for a new issue of substantially identical notes registered under the Securities Act of 1933. Please read Senior Unsecured Notes Exchange Offer below for further
information.

Convertible Subordinated Debentures due 2023. On May 15, 2006, we converted all $225 million of our
outstanding 4.75% Convertible Subordinated Debentures due 2023 into shares of our Class A common stock (the Convertible Debenture Exchange). In this transaction, we issued an aggregate of 54,598,369 shares of our Class A common
stock and paid the debenture holders an aggregate of approximately $47 million in premiums and accrued and unpaid interest using cash on hand. We recorded a charge of approximately $44 million in the second quarter 2006 associated with this
transaction, which is included in debt conversion costs on our unaudited condensed consolidated statements of operations.



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Sithe Subordinated Debt Exchange. On July 21, 2006, DHI executed and consummated
an exchange agreement (the Exchange Agreement), by and among DHI and RCP Debt, LLC and RCMF Debt, LLC (together, the Reservoir Entities). Pursuant to the Exchange Agreement, the Reservoir Entities exchanged approximately $419
million principal amount of the subordinated debt of Independence, together with all claims for accrued and unpaid interest thereon and all other rights and all obligations of the Reservoir Entities under the agreement pursuant to which the
subordinated debt was issued (together, the Sithe Debt), for approximately $297 million principal amount of DHIs 8.375% Senior Unsecured Notes due 2016 (the Additional Notes). The Additional Notes have terms and
conditions identical to, and are fungible for trading and other purposes with, the $750 million aggregate principal amount of the New Senior Notes issued on April 12, 2006. On September 14, 2006, DHI exchanged the Additional Notes for a
new issue of substantially identical notes registered under the Securities Act of 1933. We recorded a charge of approximately $36 million in the third quarter of 2006 associated with this transaction, which is included in interest expense on our
unaudited condensed consolidated statements of operations. Please read Senior Unsecured Notes Exchange Offer below for further information.

Senior Unsecured Notes Exchange Offer. On September 14, 2006, pursuant to the registration rights agreements pertaining to the New Senior Notes and the Additional Notes, we completed an exchange
offer of $1,047 million aggregate principal amount of DHIs 8.375% Senior Unsecured Notes due 2016 registered under the Securities Act of 1933 for all $1,047 million aggregate principal amount of DHIs outstanding 8.375% Senior Unsecured
Notes due 2016.

Note 8Related Party Transaction

Series C Convertible Preferred Stock. As discussed in Note 15Redeemable Preferred Securities beginning on page F-55 of our Form 10-K/A, 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. We accrued dividends on our Series C Preferred at a rate of 5.5% of the liquidation value per annum. We made a semi-annual dividend payment
of $11 million in February 2006. On May 26, 2006, we redeemed all of the outstanding shares of our Series C Preferred, which were held by CUSA. In order to redeem the Series C Preferred, we paid CUSA $400 million in cash, plus accrued and
unpaid dividends totaling approximately $6.3 million. We used approximately $178 million in net proceeds from an equity offering of 40.25 million shares of our Class A common stock that closed on the same day (includes net proceeds of $23
million from the underwriters' exercise of their option to purchase an additional 5.25 million shares), with the balance funded from cash on hand and the DHI Dividend. The redemption of the Series C Preferred eliminated the associated $22
million annual preferred dividend and reduced the number of diluted shares of our common stock outstanding.

Note 9Loss Per Share

Basic loss per share represents the amount of losses for the period available to each share of common stock outstanding during the period. Diluted loss
per share represents the amount of 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.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



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 EndedSeptember 30,         |       |   | Nine Months EndedSeptember 30, |  
|                                                           |  | 2006                                    |       |   | 2005                           |   |       | 2006 |  |   | 2005  |  
|                                                           |  | (in millions, except per share amounts) |      
|Loss from continuing operations                            |  | $                                       | (71   | ) |                                | $ | (14   | )    |  | $ | (279  | ) |  | $ | (417  | )
|Preferred stock dividends                                  |  |                                         |      |   |                                |   | (6    | )    |  |   | (9    | ) |  |   | (17   | )
|                                                           |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Loss from continuing operations for basic loss per share   |  |                                         | (71   | ) |                                |   | (20   | )    |  |   | (288  | ) |  |   | (434  | )
|Effect of dilutive securities:                             |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Interest on convertible subordinated debentures            |  |                                         |      |   |                                |   | 2     |      |  |   | 3     |   |  |   | 5     |  
|Dividends on Series C Preferred                            |  |                                         |      |   |                                |   | 6     |      |  |   | 9     |   |  |   | 17    |  
|                                                           |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Loss from continuing operations for diluted loss per share |  | $                                       | (71   | ) |                                | $ | (12   | )    |  | $ | (276  | ) |  | $ | (412  | )
|                                                           |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Basic weighted-average shares                              |  |                                         | 495   |   |                                |   | 390   |      |  |   | 446   |   |  |   | 383   |  
|Effect of dilutive securities:                             |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Stock options                                              |  |                                         | 2     |   |                                |   | 2     |      |  |   | 2     |   |  |   | 2     |  
|Convertible subordinated debentures                        |  |                                         |      |   |                                |   | 55    |      |  |   | 27    |   |  |   | 55    |  
|Series C Preferred                                         |  |                                         |      |   |                                |   | 69    |      |  |   | 37    |   |  |   | 69    |  
|                                                           |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Diluted weighted-average shares                            |  |                                         | 497   |   |                                |   | 516   |      |  |   | 512   |   |  |   | 509   |  
|                                                           |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Loss per share from continuing operations:                 |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Basic                                                      |  | $                                       | (0.14 | ) |                                | $ | (0.05 | )    |  | $ | (0.65 | ) |  | $ | (1.13 | )
|                                                           |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  
|Diluted (1)                                                |  | $                                       | (0.14 | ) |                                | $ | (0.05 | )    |  | $ | (0.65 | ) |  | $ | (1.13 | )
|                                                           |  |                                         |       |   |                                |   |       |      |  |   |       |   |  |   |       |  

---

| | (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 amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2006 and 2005.
| | --- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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 have a material adverse effect on 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 read Note 2Accounting PoliciesContingencies, Commitments, Guarantees and Indemnifications beginning on page F-17 of our Form 10-K/A
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



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



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 second quarter:



| |  |  | In October 2006, we entered into a settlement agreement with Enron and certain of its subsidiaries to resolve claims arising from or relating to the entry of the Master Netting
Setoff Security Agreement in 2001. DHI paid Enron $44 million to resolve such claims and retained the right to pursue amounts owed by Enron Capital and Trade Resources Limited to Dynegy UK Limited.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In August 2006, we and our former affiliate, West Coast Power, entered into an agreement to settle class action claims by California purchasers and certain California natural gas
resellers and co-generators alleging price manipulation and false reporting of natural gas trades. We agreed to pay approximately $32 million in total to settle these claims; however, the settlement does not include similar cases filed by individual
plaintiffs, which we continue to defend vigorously. In September 2006, the San Diego state court granted preliminary approval of the settlement of claims by the California purchasers and we expect Plaintiffs to submit the settlement of claims by
California natural gas resellers and co-generators to the Nevada federal court in the fourth quarter 2006.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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.

Enron Trade Credit Litigation. On October 5, 2006, we, DHI and certain of our affiliates and subsidiaries (collectively the
Dynegy Parties) entered into a Settlement Agreement and Mutual General Release (the Settlement Agreement) with Enron Corp. and certain of its subsidiaries and affiliates (collectively the Enron Parties). The
Settlement Agreement provides for the settlement of all claims by either the Dynegy Parties or the Enron Parties against the others arising from or relating to the Master Netting Setoff and Security Agreement (the MNSSA) dated
November 8, 2001. The MNSSA allowed certain amounts owed from the Dynegy Parties to the Enron Parties to be set off against other amounts owed from the Enron Parties to the Dynegy Parties as a result of the termination of commercial
transactions between the parties.

On October 26, 2006 the settlement received final approval from the Bankruptcy Court. Under the
Settlement Agreement, the Dynegy Parties and the Enron Parties agreed to the following in exchange for the final resolution and mutual release of all claims asserted by any of the parties in the adversary and arbitration proceedings and an action in
Canada relating to an Enron Corp. Canadian subsidiary:



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



| |  |  | A settlement payment by DHI of $44 million, payable on the second business day after final Bankruptcy Court approval.
| | - |  | ---------------------------------------------------------------------------------------------------------------------



| |  |  | Through our subsidiary Dynegy UK Limited, we retain the right to pursue claims filed against Enron Capital and Trade Resources Limited (ECTRL) in ECTRLs
administration proceedings in the United Kingdom for amounts owed by ECTRL under or in connection with certain underlying commodities contracts.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In accordance with the payment terms, Dynegy funded the settlement on October 30, 2006. The Settlement Agreement further provides for a mutual release of any other claims that exist or could exist between the
Dynegy Parties and the Enron Parties through the date payment is made. Neither the Dynegy Parties nor the Enron Parties admit any liability in connection with the Settlement Agreement. We recorded approximately $20 million and $28 million in pre-tax
charges related to the settlement and associated legal expenses in the three and nine months ended September 30, 2006, respectively. We recognized approximately $4 million of pre-tax charges related to the settlement and associated legal
expenses in the three and nine months ended September 30, 2005. These charges are recorded as general and administrative expenses on our unaudited condensed consolidated statements of operations.

Gas Index Pricing Litigation. We are named defendants in numerous lawsuits in state and federal court claiming damages resulting from
alleged price manipulation and false reporting of natural gas prices. The cases are pending in California, Nevada, Alabama and Tennessee. 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 natural gas index publications. All of the complaints rely heavily on prior FERC and CFTC investigations into and reports concerning index-reporting manipulation in the energy industry.
Except as specifically mentioned below, the cases are actively engaged in discovery.

During the last year, several cases pending in Nevada
federal court were dismissed on defendants motions. Certain plaintiffs have appealed to the Court of Appeals for the Ninth Circuit, which coordinated the cases before the same appellate panel. A decision from the Court of Appeals is not
expected until 2007.

Pursuant to various motions, the cases pending in California state court have been coordinated before a single judge
in San Diego (Coordinated Gas Index Cases). In August 2006, we entered into an agreement to settle the class action claims in the Coordinated Gas Index Cases for $30 million. The settlement does not include similar claims filed by
individual plaintiffs in the Coordinated Gas Index Cases, which we continue to defend vigorously. Also in August 2006, we entered into an agreement to settle the class action claims by California natural gas re-sellers and co-generators (to the
extent they purchased natural gas to generate electricity for re-sale) pending in Nevada federal court for $2.4 million. In September 2006, the San Diego state court granted preliminary approval of the settlement of claims by the California
purchasers. A motion to approve the re-seller and co-generator settlement is expected in the fourth quarter 2006. The settlements are without admission of wrongdoing, and Dynegy and West Coast Power continue to deny class plaintiffs
allegations.

We are analyzing the remaining natural gas index cases and are vigorously defending against them. 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. We have recorded reserves that we consider reasonable in connection with these matters.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



In connection with the sale of our interest in West Coast Power to NRG (which closed on
March 31, 2006), we, NRG and NRG West Coast LLC entered into an agreement to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. Subject to conditions and limitations
specified in that agreement, the parties agreed that we would manage the natural gas index pricing litigation described above for which NRG could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses
resulting from such litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation.

California Market Litigation.We and various other power generators and marketers are defendants in lawsuits alleging rate and market manipulation in Californias wholesale electricity market during the California energy
crisis several years ago. The complaints generally allege unfair, unlawful and deceptive trade practices in violation of the California Unfair Business Practices Act and seek injunctive relief, restitution and unspecified actual and treble damages.
In addition, certain cases include allegations relating to the validity of the contracts between power generators, including West Coast Power, and the California Department of Water Resources (CDWR). A significant majority of these cases
were dismissed on grounds of federal preemption. A motion to dismiss one remaining action on similar grounds is pending in federal court. Certain actions, however, in which plaintiffs have not exhausted the appellate process remain pending in either
the California appellate court or the U.S. Court of Appeals for the Ninth Circuit.

In October 2004, an independent electric services
provider in California filed suit against us and several other defendants alleging claims similar to those above and that it was forced out of business by the defendants conduct. Plaintiff seeks $5 million in compensatory damages, as well as
treble damages. In June 2005, the case was removed to federal court where it remains pending.

Finally, there is a pending appeal in the
Ninth Circuit Court of Appeals challenging a FERC Order affirming the validity of the former West Coast Power  CDWR long term contract. We are currently awaiting a ruling on this appeal and cannot predict its outcome.

We believe that we have meritorious defenses to these claims and are vigorously defending against them. 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.

In connection with the sale of our interest in West Coast Power to NRG on March 31, 2006, we, NRG and NRG West Coast LLC entered into
an agreement to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. Subject to conditions and limitations specified in that agreement, the parties agreed that we would manage
the power litigation described above for which NRG could suffer a loss subsequent to the closing and that we and NRG would each be responsible for 50% of any costs or losses resulting from that power litigation, as well as from other proceedings
based on similar acts or omissions which formed the basis of such litigation. The agreement further provides that NRG will manage the CDWR appeal described above and indemnify us for any resulting losses, subject to certain conditions. Please read
Guarantees and IndemnificationsWCP Indemnities below.

ERISA/Illinois Power 401(k) Litigation. In
January 2005, three DMG union 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



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



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, 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 Dynegy Inc.
ERISA litigation we settled in December 2004, including claims that certain of our former officers (who are past members of our Benefit Plans Committee) breached their fiduciary duties to plan participants and beneficiaries in connection with the
plans investment in Dynegy common stockin particular with respect to our financial statements, Project Alpha, alleged round trip trades and natural gas price index reporting. The lawsuit seeks unspecified damages for the losses to the
plan, as well as attorneys fees and other costs. In March 2006, an amended complaint was filed naming additional former officers and employees as defendants and amending the fraud claims. In June 2006, the court granted our motion to dismiss
plaintiffs fraud claims for failing to plead those claims with particularity. The remaining counts in the March 2006 amended complaint remain pending.

Additionally, in September 2005, two former Illinois Power salaried employees who were participants in the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for salaried employees (formerly known as the Illinois
Power Incentive Savings Plan), which we refer to as the DMG Salaried Plan, purporting to represent all DMG Salaried Plan participants who held Dynegy common stock through the DMG Salaried Plan during the period from January 1, 2002,
through January 30, 2003, filed a lawsuit in federal court in the Southern District of Texas against us and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG Salaried Plan that are similar to
the claims made in the ERISA litigation referenced in the preceding paragraph. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorneys fees and other costs. In December 2005, we filed a motion to dismiss the
complaint, in response to which plaintiffs counsel filed a second putative class action on behalf of three alleged plan participants that is materially identical to the original action. In March 2006, the original action was dismissed by the
court with prejudice based on lack of standing and lack of subject matter jurisdiction, and the plaintiffs in that matter have appealed that dismissal. The second putative class action relating to the DMG Salaried Plan remains pending at the class
discovery stage.

We believe that we have meritorious defenses to plaintiffs claims in these lawsuits and are vigorously defending
against them. 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.

Roseton State Pollutant Discharge Elimination System
Permit.In April 2005, the NYSDEC issued to DNE a draft SPDES Permit renewal (the Draft SPDES Permit) for the Roseton plant. The Draft SPDES Permit requires the facility to actively manage its water intake to
substantially reduce mortality of aquatic organisms.

In July 2005, a public hearing was held to receive comments on the Draft SPDES
Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking 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 aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Acts requirement that the cooling water intake structures
reflect the best technology available for minimizing adverse environmental impacts. The requirements of the Draft SPDES Permit already exceed the best technology available requirements of the EPA regulations applicable to existing facilities. In
September 2006, the administrative law judge issued a ruling admitting the petitioners to full party status and setting forth the issues to be adjudicated in the permit renewal hearing. Various holdings in the ruling have been appealed to the
Commissioner of NYSDEC by DNE, NYSDEC staff, and the petitioners. We expect that the adjudicatory hearing on the Draft SPDES Permit will occur in 2007.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



We believe that the petitioners claims are without merit, and we plan to oppose those claims vigorously. Given the high 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 State Pollutant Discharge Elimination System Permit. In January 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Danskammer Plant and an adjudicatory hearing was scheduled for the
fall of 2005. Three environmental groups sought to impose a permit requirement that the Danskammer plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism
mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Acts requirement that the cooling water intake structures reflect best technology available for minimizing adverse environmental impacts. The
requirements of the Draft SPDES Permit already exceed the best technology available requirements of the EPA regulations applicable to existing facilities.

A formal evidentiary hearing was held in November and December 2005. The Deputy Commissioners decision directing that the NYSDEC staff issue the revised Draft SPDES Permit was issued in May 2006. In June 2006,
the NYSDEC issued the revised SPDES Permit with conditions generally favorable to us. While the revised SPDES Permit does not require installation of a closed cycle cooling system, it does require aquatic organism mortality reductions in excess of
those resulting from the best technology available requirements of the EPA regulations applicable to existing facilities. In July 2006, two of the petitioners filed suit in the Supreme Court of the State of New York, Westchester County seeking to
vacate the Deputy Commissioners decision and the revised Danskammer SPDES Permit. We believe that the decision of the Deputy Commissioner is well reasoned and will be affirmed. However, in the event the decision is not affirmed and we
ultimately are required to install a closed cycle cooling system, this could have a material adverse effect on our financial condition, results of operations and 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 closure of our former Austrian subsidiarys Vienna telecommunications office in the spring of 2001. The plaintiffs are seeking approximately $30 million in compensatory and unspecified punitive damages, alleging
breach of contract, tortious interference and other similar 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 these 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 approximately $30 million. In December 2004, the plaintiffs filed a motion for partial summary judgment on issues of liability which was denied by the trial court in December 2005. Plaintiffs
appealed the decision to the New York Appellate Division, which affirmed the trial courts ruling in August 2006. Shortly thereafter, Plaintiffs sought re-argument from the intermediate court or permission to appeal to the New York Court of
Appeals.

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. We have recorded a reserve that we consider reasonable relating to this matter.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



LS Power-Kendall Arbitration.In May 2005, DPM initiated an arbitration proceeding
against LS Power-Kendall Energy, LLC. Due to the pending transaction between us and the LS Entities, the parties have agreed to dismiss the arbitration proceeding without prejudice.

Stand Energy Litigation (formerly Atlantigas Corp. Litigation). In October 2004, we were named as a defendant in a West Virginia federal
court class action lawsuit alleging that interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliates in return for a percentage of the profits. Plaintiffs contend that such conduct
violated applicable FERC regulations and federal and state antitrust laws, and constituted common law tortious interference with contractual and business relations. In addition, the complaint claims the defendants conspired with the other market
participants to receive preferential natural gas storage and transportation services at off-tariff prices. The complaint seeks unspecified compensatory and punitive damages. The parties are actively engaged in discovery.

We continue to analyze plaintiffs claims and intend to vigorously defend against them. 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.

Severance Arbitration. Our former CFO, Rob Doty, filed for arbitration pursuant to the terms of his employment/severance agreement
following his departure from the Company in 2002. Mr. Doty seeks payment of up to approximately $3.4 million and additional amounts related to long-term incentive payments allegedly contemplated by his agreement. Mr. Dotys agreement
is subject to interpretation, and we maintain that any amount owed is lower than the amount sought. We have recorded a severance accrual that we consider reasonable relating to this proceeding.

U.S. AttorneyTexas. We are continuing to cooperate fully with the U.S. Attorneys office in Houston in its ongoing investigation
of the industrys natural gas trade reporting practices.

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. A second superseding indictment was returned in March 2006, recharging the original violations and
adding additional charges. Following a five-week trial, in August 2006 the jury returned a verdict finding the former employee guilty on seven counts of wire fraud and not guilty on two counts of wire fraud and three counts of false reporting. The
jury was unable to reach a verdict on the remaining counts, including one count of conspiracy and ten counts of false reporting. On November 3, 2006, the Court conducted a hearing on the Defendants motion for a new trial or acquittal and took
the parties arguments under advisement.

We do not believe this investigation will have a material adverse effect on our financial
condition, results of operations or cash flows.

U.S. AttorneyCalifornia. In November 2002, 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. 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.

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



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For the Interim Periods Ended September 30, 2006 and 2005



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 December 2004 settlement in the Dynegy Inc. 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 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, 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 losses related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such losses could be
significant, in most cases management considers the probability of loss to be extremely remote.

Kendall Guarantee. On
September 14, 2006, the LS Entities and Kendall Power entered into the Kendall Agreement pursuant to which Kendall Power agreed to acquire all of the outstanding interests in LSP Kendall Holdings, LLC for $200 million in cash, as adjusted for
certain changes in working capital. The closing of the Kendall Agreement will occur only if closing does not occur with respect to the transactions contemplated by the Merger Agreement. We have agreed to guarantee certain of Kendall Powers
obligations under the Kendall Agreement. The consummation of the Kendall Agreement is subject to various conditions, including: (i) the termination of the Merger Agreement; (ii) the expiration or termination of applicable waiting periods
under the HSR; and (iii) satisfaction of certain other conditions. Please read Note 2Business CombinationsLS Power for further discussion.

WCP Indemnities. In connection with our sale to NRG of our 50% ownership interest in West Coast Power (please read Note 3Dispositions, Contract Terminations and Discontinued
OperationsDispositions and Contract TerminationsWest Coast Power for further discussion), we entered into an agreement with NRG in which we agreed how certain litigation would be managed and allocated between the parties responsible for
any loss suffered by the parties as a result of such litigation. Please read California Market Litigation and Gas Index Pricing Litigation above for further discussion.

Targa Indemnities. During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa against losses it may incur under indemnifications DMSLP provided to purchasers of Hackberry and certain other
assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their value to be insignificant. We have also indemnified Targa for certain tax matters
arising from periods prior to our sale of DMSLP. While we have incurred no expense in connection with this indemnification, we have recorded an accrual, which we deem to be the fair value of this indemnification as of September 30, 2006.

Illinois Power 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



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For the Interim Periods Ended September 30, 2006 and 2005



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 natural gas and investments in specified items. Although there is no limitation on our liability under this
indemnity, the amount of 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 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 natural gas storage fields, resulting in a negative revenue requirement impact to Ameren. In July
2005, we made a payment of $8 million to Ameren in settlement of Amerens indemnification claims with respect to this ICC order. Although at that time the ICC had not issued an order in any other cases, there were other cases in which it was
then probable, based on this recent action by the ICC, that some loss would occur and a liability could 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 condensed consolidated statements of operations. In late June 2006, the Administrative Law Judge in one of the ongoing cases issued a Proposed Order adopting the disallowances recommended by the ICC Staff in that case.
In September 2006, the ICC issued an Order that adopted the findings set forth by the Administrative Law Judge in the Proposed Order. 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 considers the probability of an adverse outcome remote.

Constellation Guarantee. During 2004, as part of entering into a back-to-back power purchase agreement with Constellation Energy Commodities Group, Inc. (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 $4 million in reactive power revenues over the four-year
term of the power purchase agreement. Upon entering into this contract, we established a liability of less than $1 million reflecting the fair value of this guarantee. During the year ended December 31, 2005, we increased the liability by
approximately $1 million, as it became probable that we will be obligated to make a greater payment to Constellation under the guarantee. Based on our continued evaluation and events which have occurred to date, as of September 30, 2006, we
decreased the reserve to approximately $1 million.

Northern Natural and Other Indemnities. During 2003, as part of our sale
of NNG, the Rough and Hornsea natural 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 million, $857 million and $28 million for the NNG, Rough and Hornsea natural 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, various Canadian assets, 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.

Black Mountain Guarantee.Through one of our subsidiaries, we hold a 50% ownership interest in Black Mountain (Nevada Cogeneration) (Black Mountain), in which our partner is a Chevron subsidiary. Black
Mountain owns the Black Mountain power generation facility and has a power purchase agreement with a third party that extends through April 2023. In connection with the power purchase agreement, pursuant to which Black Mountain receives payments
which decrease in amount over time, we agreed to guarantee 50% of certain payments



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For the Interim Periods Ended September 30, 2006 and 2005



that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement. At September 30, 2006, if an
event of default had occurred under the terms of the mortgage on the facility entered into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $60 million under the guarantee. While
there is a question of interpretation regarding the existence of an obligation to make payments calculated under this mechanism upon the scheduled termination of the agreement, management does not expect that any such payments would be required.

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 United States Congress has before it a number of bills that could impact regulations or impose new regulations applicable to us and our subsidiaries. We cannot
predict the outcome of these bills or other regulatory developments or the effects that they might have on our business.

Energy
Policy Act of 2005. The Energy Policy Act of 2005 (EPACT) was signed into law on August 8, 2005. Title XII of EPACT (Electricity) deals with various matters impacting the power industry, including reliability of the bulk
power system; transmission congestion, and transmission structure siting and modernization; the repeal of PUHCA; and prohibition of energy market manipulation, with enhanced FERC authority to prohibit market manipulation, including enhanced penalty
authority. FERC has implemented and is considering a number of related regulations to implement EPACT that may impact, among other things, requirements for reliability, Qualified Facilities, transmission information availability, transmission
congestion, security constrained dispatch, energy market transparency, energy market manipulation and behavioral rules.

Illinois
Resource Procurement Auction. In January 2006, the ICC approved a resource procurement auction as the process by which utilities will procure power beginning in 2007. The auction occurred in September 2006 and we subsequently entered into
two supplier forward contracts with subsidiaries of Ameren Corporation to provide capacity, energy and related services. There continue to be challenges to the auction process. The ICC did initiate an investigation into the Hourly Auction segment
and we have intervened in that proceeding.

Further, there is a possibility of political, legislative, judicial and/or regulatory actions
over the next several months that could substantially alter the parties rights and obligations under or relating to the Supplier Forward Contracts. Numerous parties have appealed various aspects of the ICC Orders approving the auctions to the
state intermediate appellate courts. The Illinois Attorney General has also filed for direct review by the state Supreme Court and a stay of the ICC Orders pending that review, which was denied. The appellate court cases have been consolidated and
are in the briefing stage; we anticipate a ruling sometime next year, with the possibility of further review by the Illinois Supreme Court. There is also the possibility that the Illinois General Assembly will consider legislation in the fourth
quarter 2006 either in its veto session or via a special session if called by the Governor.

Clean Air Mercury Rule. In March
2005, the Administrator of the EPA signed a final Clean Air Mercury Rule (CAMR) that will require mercury emission reductions to be achieved from existing coal-fired electric generating units. This rule requires all states to adopt
either the EPA rule, or a state rule meeting the minimum requirements as outlined in CAMR. The Illinois EPA has proposed a state-specific rule (the Illinois Mercury Rule) that would require larger percentage reductions in mercury emissions on a
significantly shorter timeframe than the



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For the Interim Periods Ended September 30, 2006 and 2005



CAMR would require. We, along with most other owners of Illinois coal-fired electric generating units, opposed the Illinois Mercury Rule in proceedings
before the Illinois Pollution Control Board (IPCB). The first hearing was held in June 2006 and the second hearing began on August 14, 2006. The Illinois EPA and Ameren filed a Joint Statement with the IPCB in late July supporting a
Multi-Pollutant Alternative to the Illinois Mercury Rule that significantly extends the schedule for compliance with the proposed new mercury standard while adding new requirements for the control of sulfur dioxide and nitrogen oxides emissions. DMG
filed a Joint Statement with the Illinois EPA on August 21, 2006 supporting a Multi-Pollutant alternative to the Illinois Mercury Rule. On November 2, 2006 the IPCB adopted the Illinois Mercury Rule including the Multi-Pollutant
Alternative and transmitted it to the Joint Committee on Administrative Rules ("JCAR"), which will ensure the proposed rule is consistent with state law and the views of the legislature. The extended schedule for compliance will only become
effective if the JCAR approves the overall Illinois Mercury Rule, including the Multi-Pollutant Alternative, which we believe will be within the next 90 days. Other industry participants are actively opposing this proposal. It is possible that the
rule could pass without the Multi-Pollutant Alternative, in which case we would be subject to the schedule and mercury reductions in the original Illinois Mercury Rule.

In May 2006, the Governor of New York announced plans to regulate mercury emissions from coal-fired power plants by reducing emissions by approximately 50% by 2010 and 90% by 2015. NYSDEC issued a proposed rule in
July 2006. The proposed rule would establish a 72 lb/yr mercury emission limit for the Danskammer generating units beginning in January 2010. Beginning in January 2015, the rule would impose an emission rate limit of 0.6 pounds of mercury per
trillion Btu for all affected generating units. The proposed rule would not allow trading of mercury emission allowances.

Various state
legislative and regulatory bodies may be considering other legislation or rules that could impact current regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these legislative and other
regulatory developments, or the effects that they might have on our business.

FERC Market-Based Rate Authority.
FERC-approved market-based rate authority allows those granted such authority to sell power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic re-review. In June 2005, FERC issued an order
accepting the updated market power analyses submitted by Sithe Energies and Dynegy. Accordingly, these entities have continuously had market-based rate authority. Our next triennial market power analysis is currently due in June 2008. However, FERC
is considering adoption of a regional approach for the submission of triennial reviews that could alter this due date.

We are also subject
to FERCs new regulations prohibiting market manipulation implemented pursuant to the EPACT. In 2003, FERC promulgated market behavior rules prohibiting manipulation in the wholesale electricity and natural gas markets subject to FERCs
jurisdiction. The market behavior rules, which emerged from FERCs consideration of market manipulation in the Western markets, are incorporated in the tariffs of the various Dynegy entities with market based rates for wholesale power. FERC
rescinded the other two market behavior rules. The new regulations apply to sales in organized and bilateral markets and spot markets, as well as long-term sales (as well as to the wholesale sale of natural gas under a blanket marketing
certificate). The remedies for violating the rules could include disgorgement of unjust profits or suspension or revocation of the authority to sell at market-based rates and penalties. The extent to which these regulations will affect us is
uncertain. However, we believe that we are currently in compliance.



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For the Interim Periods Ended September 30, 2006 and 2005



Note 12Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully
described in Note 20Employee Compensation, Savings and Pension Plans beginning on page F-73 of our Form 10-K/A.

Share-Based
Compensation. Our share-based payments primarily consist of stock options and restricted stock awards. For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model, with the following
weighted-average assumptions used for grants for the nine months ended September 30, 2006 and 2005:



|                                 |  |                                |  |         
|-------------------------------- |  | ------------------------------ |  | --------
|                                 |  | Nine Months EndedSeptember 30,
|                                 |  | 2006                           |  | 2005    
|Dividends                        |  |                               |  |        
|Expected volatility (historical) |  | 48.8%                          |  | 84.1%   
|Risk-free interest rate          |  | 5.1%                           |  | 4.2%    
|Expected option life             |  | 6 Years                        |  | 10 Years

The expected volatility was calculated based on a ten-year historical volatility of our stock
price in 2005 and beginning in first quarter 2006, we used a three-year historical volatility. The risk-free interest rate was calculated based upon observed interest rates appropriate for the term of our employee stock options. Currently, we
calculate the expected option life using the simplified methodology suggested by SAB 107, Share-Based Payment. For restricted stock awards, we consider the fair value to be the closing price of the stock on the grant date. We recognize
the fair value of our share-based payments over the vesting periods of the awards, which is typically a three-year service period.

We have
nine stock option plans, all of which contain authorized shares of our Class A common stock. Each option granted is exercisable at a strike price, which ranges from $1.47 per share to $56.98 per share for options currently outstanding. A brief
description of each plan is provided below:



| |  |  | NGC Plan.Created early in our history and revised prior to Dynegy becoming a publicly traded company in 1996, this plan contains 13,651,802 authorized shares,
had a 10-year term, and expired in May 2006. All option grants are vested.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Employee Equity Plan.This plan expired in May 2002 and is the only plan in which we granted options below the fair market value of Class A common stock on
the date of grant. This plan had 20,358,802 authorized shares. All option grants are vested.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Illinova Plan.Adopted by Illinova prior to the merger with Dynegy, this plan expired upon the merger date in February 2000 and had 3,000,000 authorized shares.
All option grants are vested.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Extant Plan.Adopted by Extant prior to its acquisition by Dynegy, this plan expired in September 2000 and had 202,577 authorized shares. All option grants are
vested.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | UK Plan. This plan had 276,000 authorized shares and has been terminated. All option grants are vested.
| | - |  | -------------------------------------------------------------------------------------------------------



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



| |  |  | Dynegy 1999 LTIP. This annual compensation plan has 6,900,000 authorized shares, has a 10-year term and expires in 2009. All option grants are vested.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Dynegy 2000 LTIP.This annual compensation plan, created for all employees upon the merger of Illinova and Dynegy, has 10,000,000 authorized shares, has a
10-year term and expires in February 2010. Grants from this plan vest in equal annual installments over a three-year period.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Dynegy 2001 Non-Executive LTIP.This plan is a broad-based plan and has 10,000,000 authorized shares, has a 10-year term and expires in September 2011. Grants
from this plan vest in equal annual installments over a three-year period.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Dynegy 2002 LTIP.This annual compensation plan has 10,000,000 authorized shares, has a 10-year term and expires in May 2012. Grants from this plan vest in
equal annual installments over a three-year period.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

All of our option plans cease vesting for employees who are terminated
for cause. For voluntary and involuntary termination, disability, retirement or death, continued vesting and/or an extended period in which to exercise vested options may apply, depending on the terms of the grant agreement in which a specific grant
was awarded. It has been our practice to issue shares of common stock upon exercise of stock options generally from previously unissued shares.

The Merger Agreement with LS Power will result in a change in control as defined in our Severance Pay Plans, as well as the various grant agreements. Please read Note 2Business CombinationsLS Power for further discussion of the
transaction. As a result, all options previously granted to employees will fully vest immediately upon the close of the LS Power transaction. This occurrence will not have a material effect on our financial condition, results of operations or cash
flows.

During the first quarter 2006, we entered into an exchange transaction with our Chairman and CEO. Under the terms of the
transaction, the purpose of which was to address uncertainties created by proposed regulations issued in late 2005 pursuant to Section 409A of the Internal Revenue Code, we cancelled all of the 2,378,605 stock options then held by our Chairman
and CEO. As consideration for canceling these stock options, we granted our Chairman and CEO 967,707 stock options at an exercise price of $4.88, which equaled the closing price of our Class A common stock on the date of grant, and agreed to
make a cash payment of approximately $5.6 million based on the in-the-money value of the vested stock options that were cancelled. This cash payment, which accrues interest at 7.5% annually, will be made on January 15, 2007. The newly granted
stock options have a term of 10 years, vest in three equal annual installments beginning on the first anniversary of the grant date and are subject to earlier vesting upon a constructive termination, a termination without cause or a termination
resulting from a change in control. We recorded a liability to reflect the agreed upon cash payment. We were not required to record any incremental compensation expense in connection with the transaction.



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Options outstanding as of September 30, 2006 are summarized below:



|                                                           |  |                       |   |  |                              |       |                                                   |      |                                      |   |    
|---------------------------------------------------------- |  | --------------------- | - |  | ---------------------------- | ----- | ------------------------------------------------- | ---- | ------------------------------------ | - | ---
|                                                           |  | Options(in thousands) |   |  | WeightedAverageExercisePrice |       | WeightedAverageRemainingContractualLife (inyears) |      | AggregateIntrinsicValue (inmillions)
|Outstanding at December 31, 2005                           |  | 9,314                 |   |  | $                            | 12.66 |                                                   |      |                                      |   |    
|Granted                                                    |  | 3,268                 |   |  | $                            | 4.88  |                                                   |      |                                      |   |    
|Exercised                                                  |  | (1,423                | ) |  | $                            | 3.46  |                                                   |      |                                      |   |    
|Forfeited or expired                                       |  | (2,829                | ) |  | $                            | 4.93  |                                                   |      |                                      |   |    
|                                                           |  |                       |   |  |                              |       |                                                   |      |                                      |   |    
|Outstanding at September 30, 2006                          |  | 8,330                 |   |  | $                            | 13.80 |                                                   | 6.13 |                                      | $ | 5.0
|                                                           |  |                       |   |  |                              |       |                                                   |      |                                      |   |    
|Vested and unvested expected to vest at September 30, 2006 |  | 7,642                 |   |  | $                            | 14.63 |                                                   | 5.8  |                                      | $ | 4.6
|Exercisable at September 30, 2006                          |  | 4,701                 |   |  | $                            | 20.78 |                                                   | 3.7  |                                      | $ | 2.4

The weighted average grant-date fair value of options granted during the nine months ended
September 30, 2006 and 2005 was $2.61 and $3.66, respectively. The total intrinsic value of options exercised for the nine-month periods ended September 30, 2006 and 2005 was $4 million and $1 million, respectively.

Restricted stock activity for the nine months ended September 30, 2006 was as follows:



|                                |  |                               |   |  |                                     |     
|------------------------------- |  | ----------------------------- | - |  | ----------------------------------- | ----
|                                |  | Number ofShares(in thousands) |   |  | WeightedAverageGrant DateFair Value
|Nonvested at December 31, 2005  |  | 1,239                         |   |  | $                                   | 4.40
|Granted                         |  | 1,311                         |   |  | $                                   | 4.88
|Vested                          |  | (251                          | ) |  | $                                   | 4.40
|Forfeited                       |  | (154                          | ) |  | $                                   | 4.76
|                                |  |                               |   |  |                                     |     
|Nonvested at September 30, 2006 |  | 2,145                         |   |  | $                                   | 4.67
|                                |  |                               |   |  |                                     |     

All restricted stock awards to employees vest immediately upon the occurrence of a change in
control in accordance with the terms of the applicable Severance Pay Plan. The Merger Agreement with the LS Entities will result in a change in control as defined in our restricted stock agreements. Please read Note 2Business
CombinationsLS Power for further discussion.

Compensation expense related to options granted and restricted stock awarded totaled $2
million and $3 million for the quarters ended September 30, 2006 and 2005, respectively, and $6 million and $7 million for the nine month periods ended September 30, 2006 and 2005 respectively. Tax benefits for compensation expense related
to options granted and restricted stock awarded totaled $1 million for the quarters ended September 30, 2006 and 2005, and $2 million for both the nine months ended September 30, 2006 and 2005. We recognize compensation expense ratably
over the vesting period of the respective awards. As of September 30, 2006, $9 million of total unrecognized compensation expense related to options granted and restricted stock awarded is expected to be recognized over a weighted-average
period of 2.2 years. The total fair value of shares vested was zero for the quarters ended September 30, 2006 and 2005, and $4 million and $3 million for the nine months ended September 30, 2006 and 2005, respectively. We did not
capitalize or use cash to settle any share-based compensation in the nine months ended September 30, 2006.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Cash received from option exercises for the three and nine months ended September 30, 2006 was
$1 and $5 million, respectively. The tax benefit realized for the additional tax deduction from share-based payment awards totaled $1 million for the nine months ended September 30, 2006.

In the first quarter 2006, we granted stock-based compensation awards that cliff vest after three years based on our cumulative operating cash flows for
2006-2008, or sooner upon a change in control. Compensation expense recorded in the three and nine months ended September 30, 2006 related to these performance units was less than $1 million and was accrued in Other long-term
liabilities in our unaudited condensed consolidated balance sheets. The Merger Agreement with the LS Entities will result in a change in control as related to these awards.

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



|                                              |  |                                       |    |   |                |   |    |      |  |      |   |  |   |  
|--------------------------------------------- |  | ------------------------------------- | -- | - | -------------- | - | -- | ---- |  | ---- | - |  | - | -
|                                              |  | Pension Benefits                      |    |   | Other Benefits
|                                              |  | Three Months Ended September 30, 2006
|                                              |  | 2006                                  |    |   | 2005           |   |    | 2006 |  | 2005
|                                              |  | (in millions)                        
|Service cost benefits earned during period    |  | $                                     | 2  |   |                | $ | 2  |      |  | $    |  |  | $ | 1
|Interest cost on projected benefit obligation |  |                                       | 2  |   |                |   | 3  |      |  |      |  |  |   | 
|Expected return on plan assets                |  |                                       | (2 | ) |                |   | (2 | )    |  |      |  |  |   | 
|Recognized net actuarial loss                 |  |                                       | 1  |   |                |   |   |      |  |      | 1 |  |   | 1
|                                              |  |                                       |    |   |                |   |    |      |  |      |   |  |   |  
|Net periodic benefit cost                     |  |                                       | 3  |   |                |   | 3  |      |  |      | 1 |  |   | 2
|Additional costs due to curtailment           |  |                                       | 1  |   |                |   |   |      |  |      |  |  |   | 
|                                              |  |                                       |    |   |                |   |    |      |  |      |   |  |   |  
|Total net periodic benefit cost               |  | $                                     | 4  |   |                | $ | 3  |      |  | $    | 1 |  | $ | 2
|                                              |  |                                       |    |   |                |   |    |      |  |      |   |  |   |  
|                                              |  |                                      
|                                              |  | Pension Benefits                      |    |   | Other Benefits
|                                              |  | Nine Months Ended September 30,      
|                                              |  | 2006                                  |    |   | 2005           |   |    | 2006 |  | 2005
|                                              |  | (in millions)                        
|Service cost benefits earned during period    |  | $                                     | 7  |   |                | $ | 8  |      |  | $    | 2 |  | $ | 2
|Interest cost on projected benefit obligation |  |                                       | 7  |   |                |   | 7  |      |  |      | 2 |  |   | 2
|Expected return on plan assets                |  |                                       | (7 | ) |                |   | (6 | )    |  |      |  |  |   | 
|Recognized net actuarial loss                 |  |                                       | 2  |   |                |   | 2  |      |  |      | 1 |  |   | 1
|                                              |  |                                       |    |   |                |   |    |      |  |      |   |  |   |  
|Net periodic benefit cost                     |  |                                       | 9  |   |                |   | 11 |      |  |      | 5 |  |   | 5
|Additional cost due to curtailment            |  |                                       | 3  |   |                |   |   |      |  |      |  |  |   | 
|                                              |  |                                       |    |   |                |   |    |      |  |      |   |  |   |  
|Total net periodic benefit cost               |  | $                                     | 12 |   |                | $ | 11 |      |  | $    | 5 |  | $ | 5
|                                              |  |                                       |    |   |                |   |    |      |  |      |   |  |   |  

The curtailment charge was accrued at December 31, 2005 in other long-term liabilities on our
unaudited condensed consolidated balance sheets.

Contributions. In 2006, we contributed approximately $14 million to our
pension plans, $11 million of which we paid in August 2006. We expect to contribute less than $1 million to our other postretirement benefit plans in the fourth quarter 2006.



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Note 13Income Taxes

Effective Tax Rate. The income taxes included in continuing operations were as follows:



|                   |  |                                 |    |   |                                |   |    |      |  |   |      |   |  |   |     |  
|------------------ |  | ------------------------------- | -- | - | ------------------------------ | - | -- | ---- |  | - | ---- | - |  | - | --- | -
|                   |  | Three Months EndedSeptember 30, |    |   | Nine Months EndedSeptember 30, |  
|                   |  | 2006                            |    |   | 2005                           |   |    | 2006 |  |   | 2005 |  
|                   |  | (in millions, except rates)     |   
|Income tax benefit |  | $                               | 39 |   |                                | $ | 13 |      |  | $ | 154  |   |  | $ | 228 |  
|Effective tax rate |  |                                 | 35 | % |                                |   | 48 | %    |  |   | 35   | % |  |   | 35  | %

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. In general, differences between our effective rate 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.
For the nine months ended September 30, 2005, additional differences in our overall effective tax rate on continuing operations included the non deductible portion of the charge associated with the shareholder litigation settlement, off set by
changes in the valuation allowances and adjustments to the effective state tax rate. For the three months ended September 30, 2005, our effective tax rate on continuing operations included an increase in the reserve for future tax liabilities.

Texas Margin Tax. In May 2006, Texas enacted a new law that substantially changes the states tax system. The law
replaces the taxable-capital and earned-surplus components of its franchise tax with a new franchise tax that is based on modified gross revenue. This new franchise tax is referred to as the Margin Tax and will significantly affect the
financial reporting of a wide range of enterprises that have operations in Texas. As a result of the new law, which becomes effective January 1, 2007, we established a deferred tax liability of $2 million related to our Texas operations. The
effect of the change in Texas law produced a total charge of $2 million.

Note 14Segment Information

We report the results of our power generation business as three separate geographical segments in our consolidated financial statements: (1) the
Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the South segment (GEN-SO). We also separately report the results of our former NGL and CRM business segments because of the diversity among their respective operations.
Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Certain general and administrative expenses were allocated to our reporting segments prior to
January 1, 2006. Beginning January 1, 2006, all direct general and administrative expenses are included in Other and Eliminations, unless they are specifically identified with the respective segment.

Our former natural gas liquids operations comprise the NGL segment and are included in discontinued operations. Results associated with the former DGC
segment are included in discontinued operations in Other and Eliminations due to the sale of our communications businesses. Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three
and nine months ended September 30, 2006 and 2005 is presented below:



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Segment Data for the Three Months Ended September 30, 2006

(in millions)



|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|--------------------------------------------------- |  | ---------------- | ----- | - | ------ | - | ----- | ------ |  | --------------------- | --- | - | ----- | - | --- | - |  | - | -- |  | - | --- | - |  | - | ----- | -
|                                                    |  | Power Generation |       |   | CRM    |   |       | NGL    |  | Other andEliminations |     |   | Total |  
|                                                    |  | GEN-MW           |       |   | GEN-NE |   |       | GEN-SO |  |                       |     |   |      
|Unaffiliated revenues:                              |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Domestic                                            |  | $                | 260   |   |        | $ | 182   |        |  | $                     | 97  |   |       | $ | 20  |   |  | $ |   |  | $ |    |   |  | $ | 559   |  
|Other                                               |  |                  |      |   |        |   | 18    |        |  |                       |    |   |       |   | 4   |   |  |   |   |  |   |    |   |  |   | 22    |  
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|                                                    |  |                  | 260   |   |        |   | 200   |        |  |                       | 97  |   |       |   | 24  |   |  |   |   |  |   |    |   |  |   | 581   |  
|Intersegment revenues                               |  |                  |      |   |        |   | (1    | )      |  |                       |    |   |       |   | 1   |   |  |   |   |  |   |    |   |  |   |      |  
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Total revenues                                      |  | $                | 260   |   |        | $ | 199   |        |  | $                     | 97  |   |       | $ | 25  |   |  | $ |   |  | $ |    |   |  | $ | 581   |  
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Depreciation and amortization                       |  | $                | (43   | ) |        | $ | (6    | )      |  | $                     | (5  | ) |       | $ |    |   |  | $ |   |  | $ | (3  | ) |  | $ | (57   | )
|Impairment and other charges                        |  |                  | (96   | ) |        |   |      |        |  |                       |    |   |       |   |    |   |  |   |   |  |   |    |   |  |   | (96   | )
|Operating income (loss)                             |  | $                | (10   | ) |        | $ | 33    |        |  | $                     | 8   |   |       | $ | (9  | ) |  | $ |   |  | $ | (40 | ) |  | $ | (18   | )
|Earnings from unconsolidated investments            |  |                  |      |   |        |   |      |        |  |                       | 4   |   |       |   |    |   |  |   |   |  |   |    |   |  |   | 4     |  
|Other items, net                                    |  |                  | 1     |   |        |   | 2     |        |  |                       |    |   |       |   | 2   |   |  |   |   |  |   | 6   |   |  |   | 11    |  
|Interest expense and debt conversion costs          |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   | (107  | )
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Loss from continuing operations before income taxes |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   | (110  | )
|Income tax benefit                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   | 39    |  
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Loss from continuing operations                     |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   | (71   | )
|Income from discontinued operations, net of taxes   |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   | 2     |  
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Net loss                                            |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  | $ | (69   | )
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|                                                    |  |                  |       |   |        |   |      
|Identifiable assets:                                |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Domestic                                            |  | $                | 4,599 |   |        | $ | 1,371 |        |  | $                     | 867 |   |       | $ | 364 |   |  | $ | 30 |  | $ | 169 |   |  | $ | 7,400 |  
|Other                                               |  |                  |      |   |        |   | 10    |        |  |                       | 2   |   |       |   | 95  |   |  |   |   |  |   |    |   |  |   | 107   |  
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Total                                               |  | $                | 4,599 |   |        | $ | 1,381 |        |  | $                     | 869 |   |       | $ | 459 |   |  | $ | 30 |  | $ | 169 |   |  | $ | 7,507 |  
|                                                    |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |     |   |  |   |       |  
|Unconsolidated investments                          |  | $                |      |   |        | $ |      |        |  | $                     | 7   |   |       | $ |    |   |  | $ |   |  | $ |    |   |  | $ | 7     |  
|Capital expenditures                                |  | $                | (22   | ) |        | $ | (5    | )      |  | $                     | (4  | ) |       | $ |    |   |  | $ |   |  | $ | (2  | ) |  | $ | (33   | )



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Segment Data for the Three Months Ended September 30, 2005

(in millions)



|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|--------------------------------------------------- |  | ---------------- | ----- | - | ------ | - | ----- | ------ |  | - | --------------------- | - |  | ----- | ----- | - |  | - | ----- | - |  | - | --- | - |  | - | ------ | -
|                                                    |  | Power Generation |       |   | CRM    |   |       | NGL    |  |   | Other andEliminations |   |  | Total |      
|                                                    |  | GEN-MW           |       |   | GEN-NE |   |       | GEN-SO |  |   |                       |   | 
|Unaffiliated revenues:                              |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Domestic                                            |  | $                | 256   |   |        | $ | 329   |        |  | $ | 134                   |   |  | $     | 39    |   |  | $ |      |   |  | $ |    |   |  | $ | 758    |  
|Other                                               |  |                  |      |   |        |   | 16    |        |  |   |                      |   |  |       | (4    | ) |  |   |      |   |  |   |    |   |  |   | 12     |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|                                                    |  |                  | 256   |   |        |   | 345   |        |  |   | 134                   |   |  |       | 35    |   |  |   |      |   |  |   |    |   |  |   | 770    |  
|Intersegment revenues                               |  |                  | (1    | ) |        |   | 2     |        |  |   | (3                    | ) |  |       | 2     |   |  |   |      |   |  |   |    |   |  |   |       |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Total revenues                                      |  | $                | 255   |   |        | $ | 347   |        |  | $ | 131                   |   |  | $     | 37    |   |  | $ |      |   |  | $ |    |   |  | $ | 770    |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Depreciation and amortization                       |  | $                | (40   | ) |        | $ | (6    | )      |  | $ | (7                    | ) |  | $     |      |   |  | $ |      |   |  | $ | (3  | ) |  | $ | (56    | )
|Operating income (loss)                             |  | $                | 55    |   |        | $ | 49    |        |  | $ | 11                    |   |  | $     | (18   | ) |  | $ |      |   |  | $ | (32 | ) |  | $ | 65     |  
|Earnings from unconsolidated investments            |  |                  | 6     |   |        |   |      |        |  |   | 1                     |   |  |       |      |   |  |   |      |   |  |   |    |   |  |   | 7      |  
|Other items, net                                    |  |                  | 3     |   |        |   | 1     |        |  |   | (2                    | ) |  |       | (5    | ) |  |   |      |   |  |   | 3   |   |  |   |       |  
|Interest expense                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   | (99    | )
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Loss from continuing operations before income taxes |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   | (27    | )
|Income tax benefit                                  |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   | 13     |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Loss from continuing operations                     |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   | (14    | )
|Income from discontinued operations, net of taxes   |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   | 43     |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Net income                                          |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  | $ | 29     |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|                                                    |  |                  |       |   |        |   |      
|Identifiable assets:                                |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Domestic                                            |  | $                | 5,165 |   |        | $ | 1,621 |        |  | $ | 1,041                 |   |  | $     | 1,394 |   |  | $ | 1,705 |   |  | $ | 576 |   |  | $ | 11,502 |  
|Other                                               |  |                  |      |   |        |   | 18    |        |  |   | 7                     |   |  |       | 124   |   |  |   |      |   |  |   |    |   |  |   | 149    |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Total                                               |  | $                | 5,165 |   |        | $ | 1,639 |        |  | $ | 1,048                 |   |  | $     | 1,518 |   |  | $ | 1,705 |   |  | $ | 576 |   |  | $ | 11,651 |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |     |   |  |   |        |  
|Unconsolidated investments                          |  | $                | 65    |   |        | $ |      |        |  | $ | 226                   |   |  | $     |      |   |  | $ | 77    |   |  | $ |    |   |  | $ | 368    |  
|Capital expenditures                                |  | $                | (17   | ) |        | $ | (4    | )      |  | $ | (1                    | ) |  | $     |      |   |  | $ | (16   | ) |  | $ | (1  | ) |  | $ | (39    | )



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Segment Data for the Nine Months Ended September 30, 2006

(in millions)



|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|----------------------------------------------------------------- |  | ---------------- | ----- | - | ------ | - | ----- | ------ |  | --------------------- | --- | - | ----- | - | --- | - |  | - | -- |  | - | ---- | - |  | - | ----- | -
|                                                                  |  | Power Generation |       |   | CRM    |   |       | NGL    |  | Other andEliminations |     |   | Total |  
|                                                                  |  | GEN-MW           |       |   | GEN-NE |   |       | GEN-SO |  |                       |     |   |      
|Unaffiliated revenues:                                            |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Domestic                                                          |  | $                | 744   |   |        | $ | 410   |        |  | $                     | 276 |   |       | $ | 69  |   |  | $ |   |  | $ |     |   |  | $ | 1,499 |  
|Other                                                             |  |                  |      |   |        |   | 109   |        |  |                       |    |   |       |   | 12  |   |  |   |   |  |   |     |   |  |   | 121   |  
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|                                                                  |  |                  | 744   |   |        |   | 519   |        |  |                       | 276 |   |       |   | 81  |   |  |   |   |  |   |     |   |  |   | 1,620 |  
|Intersegment revenues                                             |  |                  |      |   |        |   | (3    | )      |  |                       |    |   |       |   | 3   |   |  |   |   |  |   |     |   |  |   |      |  
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Total revenues                                                    |  | $                | 744   |   |        | $ | 516   |        |  | $                     | 276 |   |       | $ | 84  |   |  | $ |   |  | $ |     |   |  | $ | 1,620 |  
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Depreciation and amortization                                     |  | $                | (126  | ) |        | $ | (18   | )      |  | $                     | (16 | ) |       | $ |    |   |  | $ |   |  | $ | (14  | ) |  | $ | (174  | )
|Impairment and other charges                                      |  |                  | (96   | ) |        |   |      |        |  |                       | (9  | ) |       |   |    |   |  |   |   |  |   | (2   | ) |  |   | (107  | )
|Operating income (loss)                                           |  | $                | 159   |   |        | $ | 59    |        |  | $                     | (15 | ) |       | $ | (3  | ) |  | $ |   |  | $ | (121 | ) |  | $ | 79    |  
|Earnings from unconsolidated investments                          |  |                  |      |   |        |   |      |        |  |                       | 6   |   |       |   |    |   |  |   |   |  |   |     |   |  |   | 6     |  
|Other items, net                                                  |  |                  | 1     |   |        |   | 6     |        |  |                       | 1   |   |       |   | 1   |   |  |   |   |  |   | 32   |   |  |   | 41    |  
|Interest expense and debt conversion costs                        |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   | (559  | )
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Loss from continuing operations before income taxes               |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   | (433  | )
|Income tax benefit                                                |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   | 154   |  
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Loss from continuing operations                                   |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   | (279  | )
|Income from discontinued operations, net of taxes                 |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   | 3     |  
|Cumulative effect of change in accounting principle, net of taxes |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   | 1     |  
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Net loss                                                          |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  | $ | (275  | )
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|                                                                  |  |                  |       |   |        |   |      
|Identifiable assets:                                              |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Domestic                                                          |  | $                | 4,599 |   |        | $ | 1,371 |        |  | $                     | 867 |   |       | $ | 364 |   |  | $ | 30 |  | $ | 169  |   |  | $ | 7,400 |  
|Other                                                             |  |                  |      |   |        |   | 10    |        |  |                       | 2   |   |       |   | 95  |   |  |   |   |  |   |     |   |  |   | 107   |  
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Total                                                             |  | $                | 4,599 |   |        | $ | 1,381 |        |  | $                     | 869 |   |       | $ | 459 |   |  | $ | 30 |  | $ | 169  |   |  | $ | 7,507 |  
|                                                                  |  |                  |       |   |        |   |       |        |  |                       |     |   |       |   |     |   |  |   |    |  |   |      |   |  |   |       |  
|Unconsolidated investments                                        |  | $                |      |   |        | $ |      |        |  | $                     | 7   |   |       | $ |    |   |  | $ |   |  | $ |     |   |  | $ | 7     |  
|Capital expenditures                                              |  | $                | (58   | ) |        | $ | (12   | )      |  | $                     | (16 | ) |       | $ |    |   |  | $ |   |  | $ | (6   | ) |  | $ | (92   | )



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Segment Data for the Nine Months Ended September 30, 2005

(in millions)



|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|--------------------------------------------------- |  | ---------------- | ----- | - | ------ | - | ----- | ------ |  | - | --------------------- | - |  | ----- | ----- | - |  | - | ----- | - |  | - | ---- | - |  | - | ------ | -
|                                                    |  | Power Generation |       |   | CRM    |   |       | NGL    |  |   | Other andEliminations |   |  | Total |      
|                                                    |  | GEN-MW           |       |   | GEN-NE |   |       | GEN-SO |  |   |                       |   | 
|Unaffiliated revenues:                              |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Domestic                                            |  | $                | 688   |   |        | $ | 613   |        |  | $ | 291                   |   |  | $     | 99    |   |  | $ |      |   |  | $ |     |   |  | $ | 1,691  |  
|Other                                               |  |                  |      |   |        |   | 46    |        |  |   |                      |   |  |       | (46   | ) |  |   |      |   |  |   |     |   |  |   |       |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|                                                    |  |                  | 688   |   |        |   | 659   |        |  |   | 291                   |   |  |       | 53    |   |  |   |      |   |  |   |     |   |  |   | 1,691  |  
|Intersegment revenues                               |  |                  |      |   |        |   |      |        |  |   | (28                   | ) |  |       | 28    |   |  |   |      |   |  |   |     |   |  |   |       |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Total revenues                                      |  | $                | 688   |   |        | $ | 659   |        |  | $ | 263                   |   |  | $     | 81    |   |  | $ |      |   |  | $ |     |   |  | $ | 1,691  |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Depreciation and amortization                       |  | $                | (117  | ) |        | $ | (16   | )      |  | $ | (17                   | ) |  | $     | (1    | ) |  | $ |      |   |  | $ | (14  | ) |  | $ | (165   | )
|Operating income (loss)                             |  | $                | 154   |   |        | $ | 45    |        |  | $ | (5                    | ) |  | $     | (225  | ) |  | $ |      |   |  | $ | (353 | ) |  | $ | (384   | )
|Earnings from unconsolidated investments            |  |                  | 7     |   |        |   |      |        |  |   | 7                     |   |  |       |      |   |  |   |      |   |  |   |     |   |  |   | 14     |  
|Other items, net                                    |  |                  | 2     |   |        |   | 3     |        |  |   | (1                    | ) |  |       | (5    | ) |  |   |      |   |  |   | 10   |   |  |   | 9      |  
|Interest expense                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | (284   | )
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Loss from continuing operations before income taxes |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | (645   | )
|Income tax benefit                                  |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | 228    |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Loss from continuing operations                     |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | (417   | )
|Income from discontinued operations, net of taxes   |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | 209    |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Net loss                                            |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  | $ | (208   | )
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|                                                    |  |                  |       |   |        |   |      
|Identifiable assets:                                |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Domestic                                            |  | $                | 5,165 |   |        | $ | 1,621 |        |  | $ | 1,041                 |   |  | $     | 1,394 |   |  | $ | 1,705 |   |  | $ | 576  |   |  | $ | 11,502 |  
|Other                                               |  |                  |      |   |        |   | 18    |        |  |   | 7                     |   |  |       | 124   |   |  |   |      |   |  |   |     |   |  |   | 149    |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Total                                               |  | $                | 5,165 |   |        | $ | 1,639 |        |  | $ | 1,048                 |   |  | $     | 1,518 |   |  | $ | 1,705 |   |  | $ | 576  |   |  | $ | 11,651 |  
|                                                    |  |                  |       |   |        |   |       |        |  |   |                       |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Unconsolidated investments                          |  | $                | 65    |   |        | $ |      |        |  | $ | 226                   |   |  | $     |      |   |  | $ | 77    |   |  | $ |     |   |  | $ | 368    |  
|Capital expenditures                                |  | $                | (74   | ) |        | $ | (11   | )      |  | $ | (2                    | ) |  | $     |      |   |  | $ | (39   | ) |  | $ | (6   | ) |  | $ | (132   | )



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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



Note 15Subsequent Events

On October 5, 2006, we entered into a settlement agreement with Enron and certain of its subsidiaries to resolve claims arising from or relating to the entry of the Master Netting Setoff Security Agreement in
2001. Please read Note 10Commitments and ContingenciesEnron Trade Credit Litigation for a discussion of the settlement.



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DYNEGY INC.

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended September 30, 2006 and 2005

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/A.

GENERAL

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results
of our power generation business as three separate segments in our consolidated financial statements: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the South segment (GEN-SO). We also separately report
the results of our CRM business, which primarily consists of our remaining power tolling arrangement (excluding the Sithe toll which is in GEN-NE and is an intercompany agreement) as well as our legacy physical natural gas supply contracts and
natural gas transportation contracts and remaining legacy power and emission trading positions. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial
statements. Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

Recent Developments

LS Power Combination. On September 14, 2006, we entered into
a Plan of Merger, Contribution and Sale Agreement with the LS Entities, a privately held power plant investor, developer and manager, to combine the LS Entities generation portfolio with our current assets, and for us to acquire a 50 percent
ownership interest in a development company that is currently controlled by the LS Entities. The combined company (New Dynegy) will have more than 20,000 MW of commissioned generating capacity. Upon completion of the transaction, which
is subject to an affirmative vote by two-thirds of our stockholders and various regulatory approvals, the combined company will own 31 operating power plants in 15 states employing a balanced mix of fuel sources with baseload, intermediate, and
peaking dispatch capabilities, enhanced cash flow-generating opportunities, and significant scale and scope in three key geographic regions. The expanded portfolio will also include a controlling interest in the Plum Point facility, a 665 MW
coal-fired plant currently under construction in Arkansas. Additionally, the development joint venture will provide us with a 50 percent ownership interest in an established growth vehicle. The LS Entities current development activities
include nine projects totaling more than 7,600 MW in various stages of development and approximately 2,300 MW of repowering opportunities.

Under the terms of the transaction, at closing the LS Entities will receive 340 million shares of New Dynegys Class B common stock, $100 million in cash and $275 million aggregate principal amount of notes to be issued by New
Dynegy. New Dynegy will also assume approximately $1.8 billion in net debt from the LS Entities. Please read Note 2Business CombinationsLS Power for further discussion of the terms of the Plan of Merger, Contribution and Sale Agreement.

Illinois Reverse Power Procurement Auction. On September 20, 2006, DPM entered into two Supplier Forward Contracts
(SFCs) with subsidiaries of Ameren Corporation (the Ameren Illinois Utilities) to provide the Ameren Illinois Utilities with capacity, energy and related services.



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Both of the SFCs are for services required by Ameren Illinois Utilities to serve their residential and
commercial electric customers starting January 1, 2007. The products to be provided by DPM under both SFCs include electric energy and certain ancillary and other services necessary to serve full-requirements load. The first SFC extends through
May 31, 2008 and is for 24 tranches of up to 50 MW per tranche. This amount translates to approximately 22.43% of the total Ameren Illinois Utilities relevant customers load during each hour of the contract period. The pricing for
the first SFC is $64.77 per MW. The second SFC extends through May 31, 2009 and is for 4 tranches of up to 50 MW per tranche. This amount translates to approximately 3.74% of the total Ameren Illinois Utilities relevant customers
load during each hour of the contract period. The pricing for the second SFC is $64.75 per MW.

At least one bill has been introduced in
the Illinois General Assembly to extend the rate freeze in effect beyond the end of this year, which may have an impact on the SFCs. There is a possibility of political, legislative, judicial and/or regulatory actions over the next several months
that could substantially alter the rights and obligations under the SFCs. There remains the possibility that the Illinois General Assembly will consider legislation in the fourth quarter 2006 either in a veto session or in a special session. We
cannot predict the outcome of these matters or their impact, if any, on the SFCs.

Enron Trade Credit Litigation. On
October 5, 2006, we entered into a settlement agreement with Enron and certain of its subsidiaries to resolve claims arising from or relating to the entry of the Master Netting Setoff Security Agreement in 2001. DHI paid Enron $44 million to
resolve such claims and retained the right to pursue amounts owed by Enron Capital and Trade Resources Limited to Dynegy UK Limited. Please read Note 10Commitments and ContingenciesEnron Trade Credit Litigation for further discussion of
the settlement.

Liability Management. Since the second quarter 2006, we completed several liability management transactions:



| |  |  | Redemption of Second Priority Notes Due 2008.On July 15, 2006, DHI redeemed all $74 million of its remaining 2008 Notes, at a redemption price of 103% of the
principal amount, plus accrued and unpaid interest to the redemption date. Please read Note 7DebtSecond Priority Senior Secured Notes for further discussion of the redemption.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Sithe Subordinated Debt Exchange. On July 21, 2006, DHI issued $297 million principal amount of additional 8.375% Senior Unsecured Notes due 2016 in exchange for
all $419 million of outstanding Independence subordinated debt. Please read Note 7DebtSithe Subordinated Debt Exchange for further discussion of the redemption.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Senior Unsecured Notes Exchange Offer. On September 14, 2006, we completed an exchange offer of $1,047 million aggregate principal amount of DHIs 8.375%
Senior Unsecured Notes due 2016. Please read Note 7DebtSenior Unsecured Notes Exchange Offer for further discussion of the exchange offer.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Operational Highlights

Scheduled Outages and Maintenance. In the Midwest, we completed
our planned Spring 2006 outages at our Havana and Hennepin facilities in a safe and efficient manner and ahead of schedule. Our scheduled outage at the Danskammer 3 facility to address routine boiler work and extensive turbine/generator work is
underway. Scheduled outages currently being conducted at our Independence facility are expected to be completed on schedule and without incident. In the South, we completed routine maintenance and the first of several scheduled environmental
upgrades at our CoGen Lyondell cogeneration facility. Planned outages during the latter half of 2006 continue on the Baldwin and Danskammer facilities and are expected to be completed by the end of November.

Safety Performance. Safety is a foremost priority for conducting our business. Safety permeates the way we act and work, all the way from
our Guiding Principles, to the training and briefings that we do on a daily basis, to



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the work plans created for each job that we do in the plants. We have a safety organization in place that is responsible for the training, managing, and
oversight of our safety efforts, but our principal tenet is that each and every employee is responsible for his/her own safety, and for that of others with whom they work, on a continual basis. We use standard industry measurements relating to
reportable and lost-time incident rates to evaluate our safety performance. Incidents were slightly higher for the nine months ended September 30, 2006 compared to the nine months ended September 30, 2005.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe 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, legal settlements and working capital needs.
Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas and coal, forward sales of power, 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 2006, we continued our efforts to reduce our outstanding debt obligations and extend our maturity profile. Please read Note 7Debt for further discussion.

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 November 3,
2006, September 30, 2006 and December 31, 2005:



|                         |  |                 |     |                   |   |                  |  |   |    
|------------------------ |  | --------------- | --- | ----------------- | - | ---------------- |  | - | ---
|                         |  | November 3,2006 |     | September 30,2006 |   | December 31,2005
|                         |  | (in millions)  
|By Business:             |  |                 |     |                   |   |                  |  |   |    
|Generation               |  | $               | 139 |                   | $ | 153              |  | $ | 280
|Customer risk management |  |                 | 52  |                   |   | 55               |  |   | 91 
|Other                    |  |                 | 7   |                   |   | 7                |  |   | 10 
|                         |  |                 |     |                   |   |                  |  |   |    
|Total                    |  | $               | 198 |                   | $ | 215              |  | $ | 381
|                         |  |                 |     |                   |   |                  |  |   |    
|By Type:                 |  |                 |     |                   |   |                  |  |   |    
|Cash (1)                 |  | $               | 29  |                   | $ | 27               |  | $ | 122
|Letters of Credit        |  |                 | 169 |                   |   | 188              |  |   | 259
|                         |  |                 |     |                   |   |                  |  |   |    
|Total                    |  | $               | 198 |                   | $ | 215              |  | $ | 381
|                         |  |                 |     |                   |   |                  |  |   |    

| | 
| | 

| | (1) | Cash collateral consists of either cash deposits to cover physical deliveries or liabilities on mark-to-market positions or prepayments for commodities or services that are in
advance of normal payment terms.
| | --- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The decrease in collateral postings from December 31, 2005 to September 30, 2006
is primarily due to a return of collateral postings of approximately $127 million in our generation business and $36 million in our customer risk management business. This decrease is primarily a result of decreases in commodity prices since the



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end of 2005 as well as the expiration of certain hedging positions. In addition, the $44 million of collateral posted on behalf of West Coast Power was
returned as a result of the sale of our 50% interest in West Coast Power to NRG, completed on March 31, 2006. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract
TerminationsWest Coast Power for further discussion. The decrease in collateral postings from September 30, 2006 to November 3, 2006 is primarily due to decreased prices as well as hedging activities.

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. In addition, the contemplated merger with the LS Entities and the effect of the Illinois Reverse Power auction will have a significant impact on our exposure to collateral
demands. We believe that we have sufficient capital resources to satisfy counterparties collateral demands, including those for which no collateral is currently posted, for the foreseeable future.

Tax Attributes

As of
December 31, 2005, we have NOL carry-forwards of approximately $565 million. These NOL carry-forwards will begin to expire in the year 2022. If substantial changes in our ownership should occur, there could be annual limitations on the
utilization of the NOL carry-forwards. While the contemplated merger with the LS Entities would constitute a substantial change in ownership, the transaction itself should not result in a limitation on the utilization of the NOL carry-forwards.
However, the calculation of the limitation is complex and future capital transactions executed by us or our significant shareholders could trigger such a limitation. Also, the ultimate realization of these NOL carry-forwards will be affected, in
part, by the tax law in effect at the time.

Disclosure of 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, 2005 as a result of the termination of the
Sterlington long-term wholesale power tolling contract with Quachita Power. Under that termination agreement, which closed on March 7, 2006, capacity payments of up to approximately $744 million have been eliminated. Please read Note
3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSterlington Contract Termination for further discussion.

On September 14, 2006, the LS Entities and Kendall Power LLC (Kendall Power), a newly formed wholly owned subsidiary of Dynegy, entered
into a Limited Liability Company Membership Interests and Stock Purchase Agreement (the Kendall Agreement) pursuant to which Kendall Power agreed to acquire all of the outstanding interests in LSP Kendall Holdings, LLC for $200 million
in cash, as adjusted for certain changes in working capital. The closing of the Kendall Agreement will occur only if closing does not occur with respect to the transactions contemplated by the Merger Agreement. We have agreed to guarantee certain of
Kendall Powers obligations under the Kendall Agreement. The consummation of the Kendall Agreement is subject to various conditions, including: (i) the termination of the Merger Agreement; (ii) the expiration or termination of
applicable waiting periods under the HSR; and (iii) satisfaction of certain other conditions.

Please also read Note 7Debt for a
discussion of changes in our debt obligations. As of September 30, 2006, there were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2005.



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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 our common stock for the
third quarter 2006 and do not foresee a declaration of dividends in the near-term due to the dividend restrictions contained in our financing agreements.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations,
cash on hand and available capacity under our Fourth Senior Secured Credit Facility, which is scheduled to mature in April 2009 and January 2012.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at November 3, 2006, September 30, 2006 and December 31, 2005:



|                                                                        |  |                 |      |        |                   |   |      |                  |  |   |       |    
|----------------------------------------------------------------------- |  | --------------- | ---- | ------ | ----------------- | - | ---- | ---------------- |  | - | ----- | ---
|                                                                        |  | November 3,2006 |      |        | September 30,2006 |   |      | December 31,2005 | 
|                                                                        |  | (in millions)   |     
|Total revolver capacity                                                 |  | $               | 470  | (1)    |                   | $ | 470  | (1)              |  | $ |      |    
|Total additional letter of credit capacity, plus 3% reserve requirement |  |                 | 194  |        |                   |   | 194  |                  |  |   | 325   |    
|Outstanding letters of credit                                           |  |                 | (169 | )      |                   |   | (188 | )                |  |   | (259  | )  
|                                                                        |  |                 |      |        |                   |   |      |                  |  |   |       |    
|Unused capacity                                                         |  |                 | 495  |        |                   |   | 476  |                  |  |   | 66    |    
|Cash                                                                    |  |                 | 282  | (2)(3) |                   |   | 388  | (2)(3)           |  |   | 1,549 | (2)
|                                                                        |  |                 |      |        |                   |   |      |                  |  |   |       |    
|Total available liquidity                                               |  | $               | 777  |        |                   | $ | 864  |                  |  | $ | 1,615 |    
|                                                                        |  |                 |      |        |                   |   |      |                  |  |   |       |    

| | 
| | 

| | (1) | In April 2006, we amended and restated the credit facility. Please read Note 7DebtSenior Secured Credit Facility for further discussion.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------

| | (2) | The November 3, 2006, September 30, 2006 and December 31, 2005 amounts include approximately $44 million, $44 million and $21 million, respectively, of cash that
remains in Europe and $7 million, $22 million and $19 million, respectively, of cash that remains in Canada.
| | --- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| | (3) | The decrease in cash balance since December 31, 2005 was primarily due to the debt repayments associated with our liability management activities. Please read Note 7Debt
for further discussion.
| | --- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Cash Flows from Operations. We had operating cash outflows of $180 million for the
nine months ended September 30, 2006. This consisted of $503 million in operating cash inflows from our power generation business, offset by $370 million of cash outflows relating to our customer risk management business and $313 million of
cash outflows relating to 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.

Our future operating cash flows will vary based on a number of factors, many of which are beyond our control,
including the price of natural gas and its correlation to power prices, the cost of coal and fuel oil and the value of ancillary services. Additionally, the availability of our plants during peak demand periods will be required to allow us to
capture attractive market prices when available. 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 maintenance costs. Our ability to achieve
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 for
further discussion.

Cash on Hand. At November 3, 2006 and September 30, 2006, we had cash on hand of $282 million
and $388 million, respectively, as compared to $1,549 million at the end of 2005. This decrease in cash on hand at September 30, 2006 as compared to the end of 2005 is primarily attributable to our liability management activities. Please read
Note 7Debt for further discussion. The decrease in cash balance on November 3, 2006 from September 30, 2006 was primarily due to the payment related to the settlement agreement with Enron.



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Revolver and Letter of Credit Capacity. In April 2006, we entered into the Fourth
Senior Secured Credit Facility. The Fourth Senior Secured Credit Facility replaces our former Third Senior Secured Credit Facility. Please read Note 23Subsequent Events beginning on page F-85 of our Form 10-K/A for further discussion of our
former Third Senior Secured Credit Facility. The revolving portion of the Fourth Senior Secured Credit Facility is scheduled to mature in April 2009 and the term letter of credit portion matures in January 2012. The $470 million revolving facility,
which is currently undrawn, is available for general corporate purposes and for letters of credit. The $200 million term facility has been fully drawn and the proceeds placed in a collateral account to support the issuance of letters of credit. As
of November 3, 2006, we had $169 million in letters of credit issued under these facilities. 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 7DebtFourth Senior Secured Credit Facility for further
discussion.

External Liquidity Sources

Our primary external liquidity sources are proceeds from asset sales and other types of capital-raising transactions.

Asset Sale Proceeds. In March 2006, we completed our ownership exchange transactions with NRG which comprised our acquisition of NRGs 50% ownership interest in the entity that owns the Rocky Road
power plant (of which we already owned 50%), and the sale to NRG of our 50% ownership interest in the West Coast Power plant, a joint venture between us and NRG, which has ownership in power plants in southern California. As a result of the two
transactions, we received cash proceeds of approximately $165 million, net of cash acquired, from NRG. Please read Note 2Business CombinationsRocky Road for further discussion. Please read Note 3Dispositions, Contract Terminations
and Discontinued OperationsDispositions and Contract TerminationsWest Coast Power for further discussion.

We will continue to
evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. This evaluation will consider the combined portfolio of Dynegy and LS Power in anticipation of the pending
transaction. Consistent with industry practice, we periodically consider divestitures of non-core generation assets where the balance of the factors described above suggests that such assets earnings potential is limited. Although we have not
executed definitive agreements regarding the divestitures of any non-core assets other than Rockingham, opportunities arise from time to time and, as a result, a divestiture could occur at any time.

Capital-Raising Transactions.As part of our ongoing efforts to maintain a capital structure that is closely aligned with the
cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we will continuously explore additional sources of external liquidity both in the near- and long-term. The timing of any transaction may
be impacted by events, such as strategic growth opportunities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near-term. In particular, in connection with the pending transaction with LS Power,
we will be evaluating various opportunities to provide additional liquidity and streamline the combined capital structure.



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RESULTS OF OPERATIONS

Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the
three- and nine-month periods ended September 30, 2006 and 2005. At the end of this section, we have included our outlook for each segment.

We report the results of our power generation business as three separate segments in our unaudited condensed consolidated financial statements: (1) the Midwest segment (GEN-MW); (2) the Northeast segment (GEN-NE); and (3) the
South segment (GEN-SO). We also separately report results of our CRM business, which primarily consists of our remaining power tolling arrangement as well as the legacy physical natural gas supply contracts and natural gas transportation contracts
and remaining legacy power and emission trading positions that remain from the third-party trading business that was substantially exited in 2002. The Sithe toll is reported in GEN-NE and is an intercompany agreement. Our unaudited condensed
consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Because of the diversity among their respective operations, we report the results of each business
as a separate segment in our unaudited condensed consolidated financial statements. Certain general and administrative expenses were allocated to our reporting segments prior to January 1, 2006. Beginning January 1, 2006, all direct
general and administrative expenses are included in Other and Eliminations, unless they are specifically identified with the respective segment. This change in allocation methodology is a result of our efforts to better align our corporate cost
structure with a single line of business.

Three Months Ended September 30, 2006 and 2005

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of
operations for the three-month periods ended September 30, 2006 and 2005, respectively:

Three Months Ended September 30, 2006



|                                                    |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   |      |  
|--------------------------------------------------- |  | ---------------- | --- | --- | ------ | - | --------------------- |  | - | ----- |  | - | -- | - |  | - | --- | - |  | - | ---- | -
|                                                    |  | Power Generation |     | CRM |        |   | Other andEliminations |  |   | Total | 
|                                                    |  | GEN-MW           |     |     | GEN-NE |   | GEN-SO                |  |   |      
|                                                    |  | (in millions)    |    
|Operating income (loss)                             |  | $                | (10 | )   |        | $ | 33                    |  | $ | 8     |  | $ | (9 | ) |  | $ | (40 | ) |  | $ | (18  | )
|Earnings from unconsolidated investments            |  |                  |    |     |        |   |                      |  |   | 4     |  |   |   |   |  |   |    |   |  |   | 4    |  
|Other items, net                                    |  |                  | 1   |     |        |   | 2                     |  |   |      |  |   | 2  |   |  |   | 6   |   |  |   | 11   |  
|Interest expense and debt conversion costs          |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   | (107 | )
|                                                    |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   |      |  
|                                                    |  |                  |     |     |        |  
|Loss from continuing operations before income taxes |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   | (110 | )
|Income tax benefit                                  |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   | 39   |  
|                                                    |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   |      |  
|Loss from continuing operations                     |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   | (71  | )
|Income from discontinued operations, net of taxes   |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   | 2    |  
|                                                    |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   |      |  
|Net loss                                            |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  | $ | (69  | )
|                                                    |  |                  |     |     |        |   |                       |  |   |       |  |   |    |   |  |   |     |   |  |   |      |  



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Three Months Ended September 30, 2005



|                                                    |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   |     |  
|--------------------------------------------------- |  | ---------------- | -- | ------ | - | ------ |  | - | --- | - |  | --------------------- | --- | - | ----- | - | --- | - |  | - | --- | -
|                                                    |  | Power Generation |    |        |   |        |  |   |     |   |  |                      
|                                                    |  | GEN-MW           |    | GEN-NE |   | GEN-SO |  |   | CRM |   |  | Other andEliminations |     |   | Total |  
|                                                    |  | (in millions)    |   
|Operating income (loss)                             |  | $                | 55 |        | $ | 49     |  | $ | 11  |   |  | $                     | (18 | ) |       | $ | (32 | ) |  | $ | 65  |  
|Earnings from unconsolidated investments            |  |                  | 6  |        |   |       |  |   | 1   |   |  |                       |    |   |       |   |    |   |  |   | 7   |  
|Other items, net                                    |  |                  | 3  |        |   | 1      |  |   | (2  | ) |  |                       | (5  | ) |       |   | 3   |   |  |   |    |  
|Interest expense                                    |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   | (99 | )
|                                                    |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   |     |  
|Loss from continuing operations before income taxes |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   | (27 | )
|Income tax benefit                                  |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   | 13  |  
|                                                    |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   |     |  
|Loss from continuing operations                     |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   | (14 | )
|Income from discontinued operations, net of taxes   |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   | 43  |  
|                                                    |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   |     |  
|Net income                                          |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  | $ | 29  |  
|                                                    |  |                  |    |        |   |        |  |   |     |   |  |                       |     |   |       |   |     |   |  |   |     |  

The following table provides summary segmented operating statistics for the three months ended
September 30, 2006 and 2005, respectively:



|                                                        |  |                                 |      |      |   |     
|------------------------------------------------------- |  | ------------------------------- | ---- | ---- | - | ----
|                                                        |  | Three Months EndedSeptember 30,
|                                                        |  | 2006                            |      | 2005
|GEN-MW                                                  |  |                                 |      |      |   |     
|Million Megawatt Hours GeneratedGross and Net          |  |                                 | 5.7  |      |   | 6.3 
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                 |      |      |   |     
|Cinergy (Cin Hub)                                       |  | $                               | 58   |      | $ | 80  
|Commonwealth Edison (NI Hub)                            |  | $                               | 58   |      | $ | 75  
|                                                        |  |                                
|GEN-NE                                                  |  |                                 |      |      |   |     
|Million Megawatt Hours GeneratedGross and Net          |  |                                 | 1.7  |      |   | 3.3 
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                 |      |      |   |     
|New York Zone G                                        |  | $                               | 84   |      | $ | 110 
|New York Zone A                                        |  | $                               | 62   |      | $ | 91  
|                                                        |  |                                
|GEN-SO                                                  |  |                                 |      |      |   |     
|Million Megawatt Hours GeneratedGross                  |  |                                 | 1.2  |      |   | 1.8 
|Million Megawatt Hours GeneratedNet                    |  |                                 | 1.1  |      |   | 1.3 
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                 |      |      |   |     
|Southern                                                |  | $                               | 61   |      | $ | 90  
|ERCOT                                                   |  | $                               | 72   |      | $ | 107 
|Average natural gas priceHenry Hub ($/MMBtu) (2)       |  | $                               | 6.08 |      | $ | 9.66

---

|(1) | Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the company.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Reflects the average of daily quoted prices for the periods presented and does not necessarily reflect prices realized by the company.
|--- | --------------------------------------------------------------------------------------------------------------------------------------



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The following tables summarize significant items on a pre-tax basis affecting net income (loss) for the
periods presented.



|                                        |  |                                       |     |   |        |   |     |        |  |     |   |  |     |     |       |  |       |   |  |   |   |  |   |      |  
|--------------------------------------- |  | ------------------------------------- | --- | - | ------ | - | --- | ------ |  | --- | - |  | --- | --- | ----- |  | ----- | - |  | - | - |  | - | ---- | -
|                                        |  | Three Months Ended September 30, 2006 |    
|                                        |  | Power Generation                      |     |   |        |   |     |        |  |     |   | 
|                                        |  | GEN-MW                                |     |   | GEN-NE |   |     | GEN-SO |  | CRM |   |  | NGL |     | Other |  | Total |  
|                                        |  | (in millions)                         |    
|Asset impairment                        |  | $                                     | (96 | ) |        | $ |    |        |  | $   |  |  | $   |    |       |  | $     |  |  | $ |  |  | $ | (96  | )
|Sithe Subordinated Debt Exchange charge |  |                                       |    |   |        |   | (36 | )      |  |     |  |  |     |    |       |  |       |  |  |   |  |  |   | (36  | )
|Legal and settlement charges            |  |                                       |    |   |        |   |    |        |  |     |  |  |     | (22 | )     |  |       |  |  |   |  |  |   | (22  | )
|                                        |  |                                       |     |   |        |   |     |        |  |     |   |  |     |     |       |  |       |   |  |   |   |  |   |      |  
|Total                                   |  | $                                     | (96 | ) |        | $ | (36 | )      |  | $   |  |  | $   | (22 | )     |  | $     |  |  | $ |  |  | $ | (154 | )
|                                        |  |                                       |     |   |        |   |     |        |  |     |   |  |     |     |       |  |       |   |  |   |   |  |   |      |  



|                             |  |                                       |   |        |   |        |  |     |   |  |     |     |       |  |       |    |  |   |   |  |   |     |  
|---------------------------- |  | ------------------------------------- | - | ------ | - | ------ |  | --- | - |  | --- | --- | ----- |  | ----- | -- |  | - | - |  | - | --- | -
|                             |  | Three Months Ended September 30, 2005 |  
|                             |  | Power Generation                      |   |        |   |        |  |     |   |  |     |    
|                             |  | GEN-MW                                |   | GEN-NE |   | GEN-SO |  | CRM |   |  | NGL |     | Other |  | Total |   
|                             |  | (in millions)                         |  
|Legal and settlement charges |  | $                                     |  |        | $ |       |  | $   |  |  | $   | (29 | )     |  | $     |   |  | $ | 4 |  | $ | (25 | )
|Discontinued operations      |  |                                       |  |        |   |       |  |     |  |  |     | (2  | )     |  |       | 71 |  |   |  |  |   | 69  |  
|                             |  |                                       |   |        |   |        |  |     |   |  |     |     |       |  |       |    |  |   |   |  |   |     |  
|Total                        |  | $                                     |  |        | $ |       |  | $   |  |  | $   | (31 | )     |  | $     | 71 |  | $ | 4 |  | $ | 44  |  
|                             |  |                                       |   |        |   |        |  |     |   |  |     |     |       |  |       |    |  |   |   |  |   |     |  

Operating Income (Loss)

Operating loss was $18 million for the three months ended September 30, 2006, compared to operating income of $65 million for the three months ended
September 30, 2005.

Power Generation Midwest Segment. Operating loss for GEN-MW was $10 million for the three
months ended September 30, 2006, compared to operating income of $55 million for the three months ended September 30, 2005. GEN-MW results for the three months ended September 30, 2005 included general and administrative expenses of
$9 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read Results of OperationsOperating Income (Loss)Other for a consolidated discussion of general and administrative
expenses.

Results from our coal-fired generating units increased to $116 million for the three months ended September 30, 2006 from
$99 million for the three months ended September 30, 2005. Average actual on-peak prices in the CinHub/Cinergy pricing region decreased from $80 per MWh in the third quarter 2005 to $58 per MWh in the third quarter 2006. Generated volumes
decreased from 6.3 million MWh in the third quarter 2005 to 5.7 million MWh in the same period in 2006. Despite the decrease in market prices and volumes, our results for 2006 increased due to higher realized prices. Results for 2005 were
negatively impacted by the AmerenIP contract which prevented us from recognizing the full benefit of market prices during the 2005 period. During certain peak periods in 2005, Ameren took higher volumes than we expected, resulting in a need to
purchase power at market prices in order to satisfy our obligations for forward sales previously made to other third parties. We did not experience a similar situation under the AmerenIP contract in 2006. In addition, results for the three months
ended September 30, 2006 include $11 million of mark-to-market income, compared with $12 million of mark-to-market losses for the three months ended September 30, 2005. These transactions are primarily related to options and other
financial transactions that economically hedged our generation assets but were not designated as cash flow hedges. The higher realized prices and mark-to market income were partially offset by higher operating costs of approximately $5 million due
to timing of scheduled maintenance.

Results from our natural gas-fired peaking facilities in GEN-MW improved by $4 million, from $8
million in the third quarter 2005 to $12 million for the same period in 2006. Results benefited from our increased ownership in the Rocky Road facility and the associated increase in capacity revenues but were negatively impacted by a
quarter-over-quarter increase in operating expenses of approximately $1 million. Generated volumes decreased from 0.3 million MWh for the third quarter of 2005 to 0.2 million MWh in the third quarter of 2006.



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Depreciation expense increased from $40 million in 2005 to $43 million in 2006 as a result of capital
projects placed into service in 2005. This was primarily the result of the conversion of the Havana facility to burn PRB coal. Additionally, 2006 results include a pre-tax impairment charge of $96 million in the third quarter 2006 related to the
Bluegrass generation facility, due to recent changes in the market that resulted in economic constraints on the facility. Please read Note 4Restructuring and Impairment ChargesAsset Impairment for further discussion.

Power Generation Northeast Segment. Operating income for GEN-NE was $33 million for the three months ended September 30, 2006,
compared to $49 million for the three months ended September 30, 2005. GEN-NE operating income for the three months ended September 30, 2005 included general and administrative expenses of $7 million. Beginning in 2006, general and
administrative expenses are reported in our Other segment. Please read Results of OperationsOperating Income (Loss)Other for a consolidated discussion of general and administrative expenses.

Results for our Roseton and Danskammer facilities decreased by $19 million from $41 million for the three months ended September 30, 2005 to $22
million for the three months ended September 30, 2006. Average on-peak prices for Zone G, the market served by these two facilities, decreased from $110 per MWh in 2005 to $84 per MWh in 2006. Generated volumes decreased from 2.2 million
MWh in the third quarter 2005 to 0.9 million MWh in the same period in 2006. Results decreased primarily due to lower spark spreads, lower coal margins and a fuel oil inventory write-down of approximately $6 million. Mark-to-market losses of $7
million and $5 million for the third quarters 2006 and 2005, respectively, were related to financial transactions not designated as cash flow hedges.

Results for our Independence facility decreased approximately $2 million from $19 million for the three months ended September 30, 2005 to $17 million for the three months ended September 30, 2006. Average
on-peak prices for Zone A decreased from $91 per MWh in 2005 to $62 per MWh in 2006. Generated volumes decreased from 1.1 million MWh in the third quarter 2005 to 0.8 million MWh in the same period in 2006.

Depreciation expense remained flat at $6 million in 2006 and 2005.

Power Generation South Segment.Operating income for GEN-SO was $8 million for three months ended September 30, 2006, compared to income of $11 million for the three months ended
September 30, 2005. GEN-SO for the three months ended September 30, 2005, included general and administrative expenses of $3 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read
Results of OperationsOperating Income (Loss)Other for a consolidated discussion of general and administrative expenses.

Results from our ERCOT facility were $5 million for the three months ended September 30, 2006, compared to $17 million for the three months ended September 30, 2005. Results for 2006 and 2005 include losses of $5 million and
income of $9 million, respectively, related to hedge ineffectiveness, caused by natural gas price volatility in the markets in which we hedge our Texas fuel purchases. In addition, results were lower for 2006 due to lower ancillary service revenue.

Results from our Southeast peaker assets increased from $3 million in 2005 to $8 million in 2006. These improved results are due to higher
volumes for the Rockingham, Heard and Calcasieu facilities and lower operating costs of approximately $1 million.

Depreciation expense
decreased to $5 million for the three months ended September 30, 2006 from $7 million for the three months ended September 30, 2005. We stopped depreciating the Rockingham facility as it has been classified as held for sale beginning in
the second quarter 2006. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsRockingham for further discussion.



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CRM.Operating loss for the CRM segment was $9 million for the three months ended
September 30, 2006, compared to an operating loss of $18 million for the three months ended September 30, 2005. Results for 2006 reflect a charge of approximately $22 million in legal reserves resulting from additional activities during
the period that negatively affected managements assessment of the probable and estimable losses associated with the applicable proceedings. This was offset by mark-to-market income on our legacy coal, natural gas, emissions, and power
positions. We continue to diligently work to eliminate or mitigate all CRM positions. CRM results are benefiting from our continued wind-down of the various positions that make up this segment.

In the third quarter of 2005, we recognized a $21 million gain related to the termination of a contract to sell emissions allowances. However, this gain
was more than offset by $14 million of fixed payments on our Sterlington power tolling arrangement in excess of realized margins on power generated and sold, a $29 million increase in legal reserves, as well as net mark-to-market gains of $3 million
on our legacy emissions, gas and power positions. 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.

Other. Operating loss for the Other segment was $40 million for the three months ended September 30, 2006,
compared to a loss of $32 million for the three months ended September 30, 2005. Results for third quarter 2006 include approximately $37 million of general and administrative expenses, including costs related to our business segments, which
prior to the first quarter 2006 were included in the individual segments. Results for the three months ended September 30, 2005 included general and administrative expenses of $28 million.

Consolidated general and administrative expenses decreased from $76 million for the three months ended September 30, 2005 to $59 million for the
three months ended September 30, 2006, primarily due to $25 million in legal and settlement charges recorded in 2005, largely associated with our CRM segment, as well as decreases in compensation and benefits costs and professional and legal
fees from 2005 to 2006, offset by $22 million in legal reserves recorded in 2006, which are reflected in our CRM segment.

Earnings
from Unconsolidated Investments

Earnings from unconsolidated investments for the three months ended September 30, 2006 of $4
million includes the GEN-SO investment in Black Mountain. Earnings from unconsolidated investments of $7 million for the three months ended September 30, 2005 includes results from GEN-SO investments in both Black Mountain and West Coast Power.

Other Items, Net

Other items, net totaled $11 million of income for the three months ended September 30, 2006, compared to no income for the three months ended September 30, 2005. The increase is due to higher interest income in 2006 resulting
from higher cash balances and higher interest rates. In addition, we recognized foreign exchange losses in 2005 which were not repeated in 2006.

Interest Expense

Interest expense and debt conversion costs totaled $107 million for the three months ended
September 30, 2006, compared to $99 million for the three months ended September 30, 2005. The increase is primarily due to the $36 million charge associated with the Sithe Subordinated Debt exchange, offset by reductions due to lower
principal amounts outstanding as a result of our liability management program executed in the second quarter. Please read Note 7DebtSithe Subordinated Debt Exchange for further discussion.



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Income Tax Benefit

We reported an income tax benefit from continuing operations of $39 million for the three months ended September 30, 2006, compared to an income tax
benefit from continuing operations of $13 million for the three months ended September 30, 2005. The 2006 effective tax rate was 35%, compared to 48% in 2005. 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. Additionally, our overall effective tax rate on continuing operations for the three months ended September 30,
2006 was different than the statutory rate of 35% due primarily to an increase in the reserve for future tax liabilities.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations
include DMSLP in our NGL segment and our U.K. CRM business and U.K. natural gas storage assets in the CRM segment.

The following
summarizes the activity included in income from discontinued operations:

Three Months Ended September 30, 2006



|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  
|---------------------------------------------------------------------------------------- |  | ------------- | -- | - | --- | - | -- | ----- |  | - | --- | -
|                                                                                         |  | U.K. CRM      |    |   | NGL |   |    | Total | 
|                                                                                         |  | (in millions) |   
|Operating income included in income from discontinued operations                         |  | $             | 6  |   |     | $ | 2  |       |  | $ | 8   |  
|Other items, net included in income from discontinued operations                         |  |               |   |   |     |   |   |       |  |   |    |  
|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |    |   |     |   |    |       |  |   | 8   |  
|Income tax expense                                                                       |  |               |    |   |     |   |    |       |  |   | (6  | )
|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  
|Income from discontinued operations                                                      |  |               |    |   |     |   |    |       |  | $ | 2   |  
|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  
|                                                                                         | 
|Three Months Ended September 30, 2005                                                    |  |               |    |   |    
|                                                                                         |  | U.K. CRM      |    |   | NGL |   |    | Total | 
|                                                                                         |  | (in millions) |   
|Operating income included in income from discontinued operations                         |  | $             |   |   |     | $ | 93 |       |  | $ | 93  |  
|Earnings from unconsolidated investments included in income from discontinued operations |  |               |   |   |     |   | 1  |       |  |   | 1   |  
|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  
|Other items, net included in income from discontinued operations                         |  |               | (2 | ) |     |   | (8 | )     |  |   | (10 | )
|Interest expense included in income from discontinued operations                         |  |               |    |   |     |   |    |       |  |   | (15 | )
|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |    |   |     |   |    |       |  |   | 69  |  
|Income tax expense                                                                       |  |               |    |   |     |   |    |       |  |   | (26 | )
|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  
|Income from discontinued operations                                                      |  |               |    |   |     |   |    |       |  | $ | 43  |  
|                                                                                         |  |               |    |   |     |   |    |       |  |   |     |  

We completed the sale of DMSLP on October 31, 2005 as further discussed in Note
3Dispositions, Contract Terminations and Discontinued Operations Discontinued OperationsNatural Gas Liquids. As a result of the sale, and as required by SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, we have reclassified the operations related to DMSLP, which comprised of the remaining operations of our NGL segment, from continuing operations to discontinued operations.



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During the three months ended September 30, 2006, the pre-tax income from discontinued operations
was $8 million ($2 million after-tax). Our U.K. CRM business includes a pre-tax gain of $6 million for the three months ended September 30, 2006, associated with a receivable previously reserved. During the three months ended September 30,
2005, pre-tax income from discontinued operations of $69 million ($43 million after-tax) included $71 million in pre-tax income attributable to our NGL business.

In accordance with EITF Issue 87-24, Allocation of Interest to Discontinued Operations, we have allocated interest expense to discontinued operations associated with debt instruments that were required to
be paid upon the sale of DMSLP. Interest expense included in income from discontinued operations, which includes interest incurred on our former term loan and our former Generation facility debt, totaled zero and $15 million during the three months
ended September 30, 2006 and 2005, respectively.

Income Tax Expense From Discontinued Operations. We recorded an income
tax expense from discontinued operations of $6 million during the three months ended September 30, 2006, compared to income tax expense from discontinued operations of $26 million during the three months ended September 30, 2005. The
effective rates for the three months ended September 30, 2006 and 2005, were 75% and 38%, respectively. FIN No. 18, Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28 proscribes a
detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%.

Nine Months Ended September 30, 2006 and 2005

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for the nine-month periods ended September 30, 2006 and 2005, respectively:

Nine Months Ended September 30, 2006



|                                                                  |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   |      |  
|----------------------------------------------------------------- |  | ---------------- | --- | ------ | - | ------ |  | - | --- | - |  | --------------------- | -- | - | ----- | - | ---- | - |  | - | ---- | -
|                                                                  |  | Power Generation |     |        |   |        |  |   |     |   |  |                      
|                                                                  |  | GEN-MW           |     | GEN-NE |   | GEN-SO |  |   | CRM |   |  | Other andEliminations |    |   | Total |  
|                                                                  |  | (in millions)    |    
|Operating income (loss)                                           |  | $                | 159 |        | $ | 59     |  | $ | (15 | ) |  | $                     | (3 | ) |       | $ | (121 | ) |  | $ | 79   |  
|Earnings from unconsolidated investments                          |  |                  |    |        |   |       |  |   | 6   |   |  |                       |   |   |       |   |     |   |  |   | 6    |  
|Other items, net                                                  |  |                  | 1   |        |   | 6      |  |   | 1   |   |  |                       | 1  |   |       |   | 32   |   |  |   | 41   |  
|Interest expense and debt conversion costs                        |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   | (559 | )
|                                                                  |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   |      |  
|Loss from continuing operations before income taxes               |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   | (433 | )
|Income tax benefit                                                |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   | 154  |  
|                                                                  |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   |      |  
|Loss from continuing operations                                   |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   | (279 | )
|Income from discontinued operations, net of taxes                 |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   | 3    |  
|Cumulative effect of change in accounting principle, net of taxes |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   | 1    |  
|                                                                  |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   |      |  
|Net loss                                                          |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  | $ | (275 | )
|                                                                  |  |                  |     |        |   |        |  |   |     |   |  |                       |    |   |       |   |      |   |  |   |      |  



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Nine Months Ended September 30, 2005



|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|--------------------------------------------------- |  | ---------------- | --- | -------- | - | ------ |  | - | --- | - |  | --------------------- | ---- | - | ----- | - | ---- | - |  | - | ---- | -
|                                                    |  | Power Generation |     |          |   |        |  |   |     |   |  |                      
|                                                    |  | GEN-MW           |     | GEN - NE |   | GEN-SO |  |   | CRM |   |  | Other andEliminations |      |   | Total |  
|                                                    |  | (in millions)    |    
|Operating income (loss)                             |  | $                | 154 |          | $ | 45     |  | $ | (5  | ) |  | $                     | (225 | ) |       | $ | (353 | ) |  | $ | (384 | )
|Earnings from unconsolidated investments            |  |                  | 7   |          |   |       |  |   | 7   |   |  |                       |     |   |       |   |     |   |  |   | 14   |  
|Other items, net                                    |  |                  | 2   |          |   | 3      |  |   | (1  | ) |  |                       | (5   | ) |       |   | 10   |   |  |   | 9    |  
|Interest expense                                    |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   | (284 | )
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|Loss from continuing operations before income taxes |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   | (645 | )
|Income tax benefit                                  |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   | 228  |  
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|Loss from continuing operations                     |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   | (417 | )
|Income from discontinued operations, net of taxes   |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   | 209  |  
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   |      |  
|Net loss                                            |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  | $ | (208 | )
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                       |      |   |       |   |      |   |  |   |      |  

The following table provides summary segmented operating statistics for the nine months ended
September 30, 2006 and 2005, respectively:



|                                                        |  |                                |      |      |   |     
|------------------------------------------------------- |  | ------------------------------ | ---- | ---- | - | ----
|                                                        |  | Nine Months EndedSeptember 30,
|                                                        |  | 2006                           |      | 2005
|GEN-MW                                                  |  |                                |      |      |   |     
|Million Megawatt Hours GeneratedGross and Net          |  |                                | 16.1 |      |   | 16.8
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                |      |      |   |     
|Cinergy (Cin Hub)                                       |  | $                              | 53   |      | $ | 61  
|Commonwealth Edison (NI Hub)                            |  | $                              | 54   |      | $ | 59  
|                                                        |  |                               
|GEN-NE                                                  |  |                                |      |      |   |     
|Million Megawatt Hours GeneratedGross and Net          |  |                                | 3.5  |      |   | 6.8 
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                |      |      |   |     
|New York Zone G                                        |  | $                              | 78   |      | $ | 86  
|New York Zone A                                        |  | $                              | 60   |      | $ | 70  
|                                                        |  |                               
|GEN-SO                                                  |  |                                |      |      |   |     
|Million Megawatt Hours GeneratedGross                  |  |                                | 3.8  |      |   | 5.6 
|Million Megawatt Hours GeneratedNet                    |  |                                | 3.1  |      |   | 4.1 
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                |      |      |   |     
|Southern                                                |  | $                              | 57   |      | $ | 65  
|ERCOT                                                   |  | $                              | 66   |      | $ | 76  
|Average natural gas priceHenry Hub ($/MMBtu) (2)       |  | $                              | 6.79 |      | $ | 7.66

---

|(1) | Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the company.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Reflects the average of daily quoted prices for the periods presented and does not necessarily reflect prices realized by the company.
|--- | --------------------------------------------------------------------------------------------------------------------------------------



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



|                                        |  |                                      |     |   |        |   |     |        |  |   |     |   |  |     |     |       |  |   |       |  |   |      |   |  |   |      |  
|--------------------------------------- |  | ------------------------------------ | --- | - | ------ | - | --- | ------ |  | - | --- | - |  | --- | --- | ----- |  | - | ----- |  | - | ---- | - |  | - | ---- | -
|                                        |  | Nine Months Ended September 30, 2006 |    
|                                        |  | Power Generation                     |     |   |        |   |     |        |  |   |     |   |  |    
|                                        |  | GEN-MW                               |     |   | GEN-NE |   |     | GEN-SO |  |   | CRM |   |  | NGL |     | Other |  |   | Total | 
|                                        |  | (in millions)                        |    
|Debt conversion costs                   |  | $                                    |    |   |        | $ |    |        |  | $ |    |   |  | $   |    |       |  | $ |      |  | $ | (249 | ) |  | $ | (249 | )
|Asset impairments                       |  |                                      | (96 | ) |        |   |    |        |  |   | (9  | ) |  |     |    |       |  |   |      |  |   |     |   |  |   | (105 | )
|Legal and settlement charges            |  |                                      |    |   |        |   |    |        |  |   |    |   |  |     | (53 | )     |  |   |      |  |   | (2   | ) |  |   | (55  | )
|Sithe Subordinated Debt exchange charge |  |                                      |    |   |        |   | (36 | )      |  |   |    |   |  |     |    |       |  |   |      |  |   |     |   |  |   | (36  | )
|Acceleration of financing costs         |  |                                      |    |   |        |   |    |        |  |   |    |   |  |     |    |       |  |   |      |  |   | (34  | ) |  |   | (34  | )
|                                        |  |                                      |     |   |        |   |     |        |  |   |     |   |  |     |     |       |  |   |       |  |   |      |   |  |   |      |  
|Total                                   |  | $                                    | (96 | ) |        | $ | (36 | )      |  | $ | (9  | ) |  | $   | (53 | )     |  | $ |      |  | $ | (285 | ) |  | $ | (479 | )
|                                        |  |                                      |     |   |        |   |     |        |  |   |     |   |  |     |     |       |  |   |       |  |   |      |   |  |   |      |  



|                                    |  |                                      |   |        |   |        |  |     |   |  |     |      |       |  |   |       |  |   |      |   |  |   |      |  
|----------------------------------- |  | ------------------------------------ | - | ------ | - | ------ |  | --- | - |  | --- | ---- | ----- |  | - | ----- |  | - | ---- | - |  | - | ---- | -
|                                    |  | Nine Months Ended September 30, 2005 |  
|                                    |  | Power Generation                     |   |        |   |        |  |     |   |  |     |      |      
|                                    |  | GEN-MW                               |   | GEN-NE |   | GEN-SO |  | CRM |   |  | NGL |      | Other |  |   | Total | 
|                                    |  | (in millions)                        |  
|Legal and settlement charges        |  | $                                    |  |        | $ |       |  | $   |  |  | $   | (29  | )     |  | $ |      |  | $ | (249 | ) |  | $ | (278 | )
|Independence toll settlement charge |  |                                      |  |        |   |       |  |     |  |  |     | (169 | )     |  |   |      |  |   |     |   |  |   | (169 | )
|Discontinued operations             |  |                                      |  |        |   |       |  |     |  |  |     | 3    |       |  |   | 152   |  |   |     |   |  |   | 155  |  
|Taxes                               |  |                                      |  |        |   |       |  |     |  |  |     |     |       |  |   |      |  |   | 112  |   |  |   | 112  |  
|                                    |  |                                      |   |        |   |        |  |     |   |  |     |      |       |  |   |       |  |   |      |   |  |   |      |  
|Total                               |  | $                                    |  |        | $ |       |  | $   |  |  | $   | (195 | )     |  | $ | 152   |  | $ | (137 | ) |  | $ | (180 | )
|                                    |  |                                      |   |        |   |        |  |     |   |  |     |      |       |  |   |       |  |   |      |   |  |   |      |  

Operating Income (Loss)

Operating income was $79 million for the nine months ended September 30, 2006, compared to an operating loss of $384 million for the nine months
ended September 30, 2005.

Power Generation Midwest Segment. Operating income for GEN-MW was $159 million for the
nine months ended September 30, 2006, compared to $154 million for the nine months ended September 30, 2005. GEN-MW results for the nine months ended September 30, 2005 included general and administrative expenses of $26 million.
Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read Results of OperationsOperating Income (Loss)Other for a consolidated discussion of general and administrative expenses.

Results from our coal-fired generating units increased to $360 million for the nine months ended September 30, 2006 from $300 million
for the nine months ended September 30, 2005. Average actual on-peak prices in the CinHub/Cinergy pricing region decreased from $61 per MWh in the nine months ended September 30, 2005 to $53 per MWh for the nine months ended
September 30, 2006. Generated volumes decreased from 16.8 million MWh in the nine months ended September 30, 2005 to 16.1 million MWh in the same period in 2006. Despite the decrease in market prices and the decrease in output,
the increase in results was primarily driven by higher realized power prices. We realized higher power prices in the first quarter 2006 as we settled forward power sales. Additionally, results from our coal-fired generating units were negatively
impacted by the AmerenIP contract during the second and third quarters of 2005, preventing us from recognizing the full benefit of market prices during the 2005 period. During certain peak periods in 2005, Ameren took higher volumes than we
expected, resulting in a need to purchase power at market prices in order to satisfy our obligations for forward sales previously made to other third-parties. We did not experience a similar situation under the AmerenIP contract in 2006. In
addition, results for the nine months ended September 30, 2006 include mark-to-market income of approximately $10 million, compared with losses of $2 million for the nine months ended September 30, 2005. These transactions are primarily
related to options and other financial transactions that economically hedged our generation assets but were not designated as cash flow hedges.The higher realized prices and mark-to-market income were partially offset by higher operating
costs of approximately $6 million due to the timing of scheduled maintenance.



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Results for our natural gas-fired peaking facilities in GEN-MW improved by $14 million, increasing from
$6 million for the first nine months of 2005 to $20 million for the same period in 2006. This improvement was the result of increased capacity fees particularly at our Renaissance facility. In addition, our acquisition of the remaining ownership
interest in the Rocky Road facility and the related increase in capacity fees also contributed to the increase.

Depreciation expense
increased from $117 million in 2005 to $126 million in 2006 as a result of capital projects placed into service in 2005. This was primarily related to the conversion of the Havana facility to burn PRB coal. In addition, we recorded a $96 million
pre-tax impairment charge in the third quarter of 2006 related to the Bluegrass generation facility due to recent changes in the market that resulted in economic constraints on the facility. Please read Note 4Restructuring and Impairment
ChargesAsset Impairment for further discussion. Additionally, our 2005 results include a $7 million charge associated with the write-off of an environmental project.

Power Generation Northeast Segment. Operating income for GEN-NE was $59 million for the nine months ended September 30, 2006,
compared to $45 million for the nine months ended September 30, 2005. GEN-NE for the nine months ended September 30, 2005 included general and administrative expenses of $18 million. Beginning in 2006, general and administrative expenses
are reported in our Other segment. Please read Results of OperationsOperating Income (Loss)Other for a consolidated discussion of general and administrative expenses.

Results for our Roseton and Danskammer facilities decreased from $53 million in 2005 to $41 million in 2006 primarily as a result of lower prices and
volumes. Average on-peak prices for Zone G, the market served by these two facilities, decreased from $86 per MWh in 2005 to $78 per MWh in 2006. Generated volumes decreased from 4.7 million MWh in the nine months ended September 30, 2005
compared to 2.2 million MWh in the nine months ended September 30, 2006. Additionally, the nine months ended September 30, 2006 included mark-to-market losses of $20 million related to financial transactions not designated as cash
flow hedges and a fuel oil inventory write-down of approximately $6 million. The nine months ended September 30, 2005 results included mark-to-market losses of $7 million.

Independence contributed results of $36 million for the nine months ended September 30, 2006, compared with $25 million for the period from February
through September 2005. Average on-peak prices for Zone A decreased from $70 per MWh in 2005 to $60 per MWh in 2006. Generated volumes decreased from 2.2 million MWh for the nine months ended September 30, 2005 to 1.3 million MWh for
the same period in 2006. Although market prices and generated volumes from our Independence facility decreased year over year, we received a benefit from the realization of higher power prices in the first half of 2006, as we settled forward power
sales. The increased results also related to merchant capacity payments.

Depreciation expense for GEN-NE increased from $16 million in
2005 to $18 million in 2006, as the result of acquiring the Independence facility in February 2005.

Power Generation South
Segment.Operating loss for GEN-SO was $15 million for the nine months ended September 30, 2006, compared to an operating loss of $5 million for the nine months ended September 30, 2005. GEN-SO for the nine months ended
September 30, 2005, included general and administrative expenses of $9 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please read Results of OperationsOperating Income
(Loss)Other for a consolidated discussion of general and administrative expenses.

Results from our ERCOT facility decreased by
$16 million from $15 million in 2005 to a loss of $1 million in 2006. Included in the 2006 results are $1 million of mark-to-market losses compared to mark-to-market income of $8 million in 2005, which relate to hedge ineffectiveness in the ERCOT
region. Decreases in ancillary services revenue caused by a depressed ancillary services market in the ERCOT region during 2006 added to these losses.



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Results from our other South assets increased from $6 million in the nine months ended September 30,
2005 to $12 million in the same period in 2006, primarily as a result of increased volumes in our peaking facilities.

Depreciation expense
was $16 million for the nine months ended September 30, 2006 compared to $17 million for the nine months ended September 30, 2005. In addition, during the second quarter 2006, we recorded a $9 million impairment of our Rockingham facility,
resulting from the pending sale. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsRockingham for further discussion.

CRM.Operating loss for the CRM segment was $3 million for the nine months ended September 30, 2006, compared to an operating loss of
$225 million for the nine months ended September 30, 2005.

Results for 2006 reflect charges of approximately $53 million in legal
reserves resulting from additional activities during the period that negatively affected managements assessment of probable and estimable losses associated with the applicable proceedings. These charges were partially offset by mark-to-market
income on our legacy coal, natural gas, emissions, and power positions.

Results for 2005 were negatively impacted by a $169 million charge
associated with the acquisition of Sithe Energies. Prior to the acquisition, Independence held a power tolling contract and a natural gas supply agreement with our CRM segment. Upon completion of the purchase, these contracts became intercompany
agreements reported under our GEN-NE segment, and were effectively eliminated on a consolidated basis, resulting in the $169 million charge upon completion of the acquisition. In addition, this segments 2005 results reflect $63 million of
fixed payments on our power tolling arrangements in excess of realized margins on power generated and a $29 million charge related to increased legal 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. These losses were partly offset by a $21 million gain related to the termination of a contract to sell emissions allowances, and a
net mark-to-market benefit of $14 million from our legacy gas, power and emissions positions.

Other. Other operating loss
was $121 million for the nine months ended September 30, 2006, compared to a loss of $353 million for the nine months ended September 30, 2005. Results for the nine months ended September 30, 2006 include approximately $107 million of
general and administrative expenses, including costs related to our business segments, which prior to first quarter 2006 were included in the individual segments. Results for the nine months ended September 30, 2005 included general and
administrative expenses of $339 million.

Consolidated general and administrative expenses decreased from $421 million for the nine months
ended September 30, 2005 to $160 million for the nine months ended September 30, 2006. General and administrative expenses for 2005 included a $236 million charge associated with settlement of our shareholder class action litigation and
other legal settlement charges totaling $42 million, while 2006 included $55 million in additional legal reserves. Additionally, compensation and benefits costs and professional and legal fees were lower in 2006 compared to 2005.

Earnings from Unconsolidated Investments

The $6 million earnings reported from unconsolidated investments for the nine months ended September 30, 2006 included the GEN-SO investment in Black Mountain. The $14 million earnings reported for the nine
months ended September 30, 2005 includes results from GEN-SO investments in both Black Mountain and West Coast Power.



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Other Items, Net

Other items, net totaled $41 million of income for the nine months ended September 30, 2006, compared to $9 million of income for the nine months
ended September 30, 2005. The increase is primarily associated with higher interest income in 2006 resulting from higher cash balances and higher interest rates.

Interest Expense

Interest expense and debt conversion costs totaled $559 million for the nine
months ended September 30, 2006, compared to $284 million for the nine months ended September 30, 2005. The increase is primarily due to debt conversion and acceleration of financing costs, as well as a $36 million charge associated with
the Sithe Subordinated Debt exchange. These charges are partially offset by reductions due to lower principal amounts outstanding as a result of our liability management program. Please read Note 7Debt for further discussion.

Income Tax Benefit

We
reported an income tax benefit from continuing operations of $154 million for the nine months ended September 30, 2006, compared to an income tax benefit from continuing operations of $228 million for the nine months ended September 30,
2005. The 2006 effective tax rate was 35%, as well as 35% in 2005.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include DMSLP in our NGL segment and our U.K. CRM business and
U.K. natural gas storage assets in the CRM segment.

The following summarizes the activity included in income from discontinued operations:

Nine Months Ended September 30, 2006



|                                                                 |  |               |   |     |   |       |  |   |    |  
|---------------------------------------------------------------- |  | ------------- | - | --- | - | ----- |  | - | -- | -
|                                                                 |  | U.K. CRM      |   | NGL |   | Total | 
|                                                                 |  | (in millions) |  
|Operating income included in income from discontinued operations |  | $             | 3 |     | $ | 3     |  | $ | 6  |  
|Other items, net included in income from discontinued operations |  |               | 2 |     |   |      |  |   | 2  |  
|                                                                 |  |               |   |     |   |       |  |   |    |  
|Income from discontinued operations before taxes                 |  |               |   |     |   |       |  |   | 8  |  
|Income tax expense                                               |  |               |   |     |   |       |  |   | (5 | )
|                                                                 |  |               |   |     |   |       |  |   |    |  
|Income from discontinued operations                              |  |               |   |     |   |       |  | $ | 3  |  
|                                                                 |  |               |   |     |   |       |  |   |    |  



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Nine Months Ended September 30, 2005



|                                                                                         |  |               |    |   |     |   |     |       |  |   |     |  
|---------------------------------------------------------------------------------------- |  | ------------- | -- | - | --- | - | --- | ----- |  | - | --- | -
|                                                                                         |  | U.K. CRM      |    |   | NGL |   |     | Total | 
|                                                                                         |  | (in millions) |   
|Operating income (loss) included in income from discontinued operations                  |  | $             | (1 | ) |     | $ | 205 |       |  | $ | 204 |  
|Earnings from unconsolidated investments included in income from discontinued operations |  |               |   |   |     |   | 5   |       |  |   | 5   |  
|Other items, net included in income from discontinued operations                         |  |               | 4  |   |     |   | (18 | )     |  |   | (14 | )
|Interest expense included in income from discontinued operations                         |  |               |    |   |     |   |     |       |  |   | (40 | )
|                                                                                         |  |               |    |   |     |   |     |       |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |    |   |     |   |     |       |  |   | 155 |  
|Income tax benefit                                                                       |  |               |    |   |     |   |     |       |  |   | 54  |  
|                                                                                         |  |               |    |   |     |   |     |       |  |   |     |  
|Income from discontinued operations                                                      |  |               |    |   |     |   |     |       |  | $ | 209 |  
|                                                                                         |  |               |    |   |     |   |     |       |  |   |     |  

We completed the sale of DMSLP on October 31, 2005 as further discussed in Note
3Dispositions, Contract Terminations and Discontinued Operations Discontinued OperationsNatural Gas Liquids. As a result of the sale, and as required by SFAS No. 144, we have reclassified the operations related to DMSLP, which
comprised of the remaining operations of our NGL segment, from continuing operations to discontinued operations.

During the nine months
ended September 30, 2006, pre-tax income from discontinued operations of $8 million ($3 million after-tax) included a pre-tax gain of $6 million associated a receivable previously reserved in our U.K. CRM business. During the nine months ended
September 30, 2005, pre-tax income from discontinued operations of $155 million ($209 million after-tax) included $152 million in pre-tax income attributable to NGL.

In accordance with EITF Issue 87-24, we have allocated interest expense to discontinued operations associated with debt instruments that were required to be paid upon the sale of DMSLP. Interest expense included in
income from discontinued operations, which includes interest incurred on our former term loan and our former Generation facility debt, totaled zero and $40 million during the nine months ended September 30, 2006 and 2005, respectively.

Income Tax Benefit From Discontinued Operations. We recorded an income tax expense from discontinued operations of $5
million during the nine months ended September 30, 2006, compared to an income tax benefit from discontinued operations of $54 million during the nine months ended September 30, 2005. The income tax benefit in 2005 includes a $112 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 sale of DMSLP. For further information regarding the sale, please see Note 3 Dispositions, Contract Terminations and Discontinued OperationsDiscontinued OperationsNatural Gas
Liquids. The effective rates for the nine months ended September 30, 2006 and 2005, adjusting for the reduction of the valuation allowance in 2005, are 63% and 37%, respectively. FIN No. 18 proscribes a detailed methodology of allocating
income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%.

Outlook

In September 2006, we and the LS
Entities announced an agreement to combine the operating assets of both entities into a diversified operating portfolio upon receipt of all required approvals. The combination will yield a more robust portfolio than either entity possesses
currently. Our current portfolio consists primarily of baseload coal assets in GEN-MW and GEN-NE and natural gas-fired peaking assets throughout GEN-MW and GEN-SO. In addition to the volumes committed under the contracts resulting from the Illinois
auction and power and steam delivery commitments from our Independence and Lyondell facilities, the output from our facilities is available for other forward sales opportunities to capture attractive market prices. To the extent that we choose not
to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas and power



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commodity markets. The only intermediate (combined cycle) assets in our current portfolio are the Independence and Lyondell natural gas-fired facilities. The
LS Entities portfolio consists primarily of natural gas fired intermediate (combined cycle) assets with a significant portion of the output committed under multi-year power purchase agreements or hedged through financial agreements. The LS
Entities portfolio includes significant generating capacity located in the Western Electricity Coordinating Council NERC region, a region that is expected to continue to experience demand growth but in which we currently own no generating
assets. The combination will result in a more balanced portfolio geographically and in terms of fuel type and dispatch characteristics.

The following summarizes our outlook for our current power generation business and our customer risk management business.

Power Generation Business. Generally, we expect that future financial results will continue to reflect sensitivity to fuel and emissions commodity prices, market structure and prices for energy, ancillary services and
capacity, transportation and transmission logistics, weather conditions and in-market asset availability (IMA). Our commercial team actively manages price risk associated with our power length by entering into forward sales in the prompt
one to three months. Decisions regarding longer term forward sales opportunities to capture attractive market prices are made by the executive management team. To the extent we do not choose to forward sell energy from our generation fleet, changes
in commodity prices will affect our earnings based on the direction of the commodity price movement.

GEN- MW. We
expect our results to continue to be impacted by (i) power prices, (ii) IMA of our assets and (iii) fuel availability and prices. A significant power sales agreement with AmerenIP will be expiring at the end of 2006. Although we
expect wholesale power prices to continue to remain higher than the price we receive under our existing agreement with AmerenIP for the remainder of 2006, we will not be able to fully realize these prices as a result of the options held by AmerenIP
in our fixed price power purchase agreement with them. We will continue to benefit from prevailing market prices for those volumes in excess of the maximum quantity Ameren can call under our current agreement. Additionally, any volumes below this
maximum for which Ameren does not exercise its right to require delivery will also be available for sale at prevailing market prices.

Beyond 2006, GEN-MW results will be affected by the expiration of this power purchase agreement and delivery obligations resulting from our participation in the Illinois Resource Procurement auction. We participated in the Illinois Resource
Procurement auction in September 2006 and were awarded contracts for delivery of up to 1,200 MW into the AmerenIP portion of the auction for the time period from January 1, 2007 through May 31, 2008 and up to an additional 200 MW for the
time period from January 1, 2007 through May 31, 2009. The volumes we expect to deliver under the resulting agreements are significantly less than the maximum volumes AmerenIP can call under our current agreement. AmerenIP will continue to
have similar volumetric options as they have under our current PPA. The power commodity price under the auction related agreements is higher than exists under our current contract as are Dynegys costs to manage deliveries. All other volumes
which we produce will be exposed to prevailing market pricing. We anticipate that the revenues generated by our Midwest facilities will improve significantly beginning in 2007 with the implementation of contracts resulting from the auction and the
sale of additional volumes into the MISO wholesale markets at prevailing market prices.

Another factor impacting our results in the
Midwest beyond 2006 will be the regulatory environment in Illinois. Within the Illinois political arena, there continues to be challenges to the auction process. There is a possibility of political, legislative, judicial and/or regulatory actions
over the next several months that could alter the auction results substantially. Please read Note 11Regulatory IssuesIllinois Resource Procurement Auction for further details.

Our IMA will also impact GEN-MWs results. We use IMA to monitor steam fleet performance over time. This measure quantifies the percentage of
generation for each unit that was available when market prices were favorable for participation. IMA is calculated on a unit specific basis as a ratio of dispatchable capacity actually available during periods when each unit is scheduled to be
available and the megawatt hours resulting from the capacity of each facility multiplied by the hours when the market pricing for electricity and fuel and the variable costs to operate indicate each unit can be profitably dispatched. Through our
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we seek to maximize our IMA and, as a result, our revenue generating opportunities. The IMA for our steam-driven fleet through September 2006 was
approximately 88%, compared to 90.4% for the comparable period of 2005. We attempt to schedule maintenance and repair work to minimize downtime during peak demand periods, but only to the extent doing so does not compromise a safe working
environment for our employees and contractors.

In 2005,DMG entered into a comprehensive, Midwest system-wide settlement
with the EPA and other parties, resolving the environmental litigation related to our Baldwin Energy Complex in Illinois. The settlement involves substantial emission reductions from our Illinois coal-fired power plants and the completion of several
supplemental environmental projects in the Midwest. Through September 30, 2006, DMG had achieved all of the scheduled emission reductions and was developing plans to install additional emission control equipment to meet future, more stringent
emission limits. DMG recently received a construction permit for the mercury control project at the Vermilion Power Station that is scheduled for operation by June 30, 2007. Our estimated costs associated with the Consent Decree projects, which
we expect to incur through 2013, have increased from a previously reported amount of $611 million to an estimated $674 million. Factors contributing to this growth are increased costs associated with the Vermilion Mercury Control Project and the
anticipated cost of adding additional particulate control equipment at the Hennepin Station. Another major component of the increase is large commodity cost-escalations for raw materials (steel, cement and copper) required for the scrubbers and
baghouses. These supply-side market pressures will continue to subject the final cost of Consent Decree compliance to cost volatility.

We
have diligently worked with our rail service provider to decrease our risk of delivery-related disruptions, including the re-deployment of existing rail assets and coal supplies in an opportunistic fashion to provide coal deliveries to our highest
margin plants to allow full economic dispatch during peak demand. At this time, we believe that the core issues which created the delivery uncertainty are resolved and our ability to maintain or build coal inventory at each of our coal-fired
facilities continues to be sufficient to meet forecast requirements.

Through 2010, 96% of our Midwest coal requirements are contracted.
Additionally, 100% of our coal requirements for 2006 and more than half of our coal requirements through 2008 are contracted at a fixed price. Our longer term results are sensitive to changes in coal prices to the extent that our current fixed price
arrangements expire or are adjusted through contract re-openers or related provisions.

During 2005, our results reflected increased demand
for capacity-related products from our peaking generation facilities. In addition, we benefited from operation of all of our peaking plants at certain times during the summer months of 2005. We experienced comparable dispatch opportunities this past
summer as each of our peaking facilities experienced some level of economic dispatch, as a result of weather driven market demand.

GEN-NE. We expect commodity fuel prices and market prices for energy and capacity to continue to be strong, although current forward prices are lower than forward market highs seen in the fall of 2005. Spreads are
expected to remain volatile as fuel prices change.

Our results are also dependent on our ability to maintain coal and oil deliveries to
the facilities. We have recently completed negotiations to continue coal deliveries through 2007 with existing suppliers for our Northeast coal requirements. With the completion of the agreements, we have now secured all of our expected 2007 coal
supply requirements and a portion of our 2008 coal supply requirements for our Danskammer facility.

Additionally, our results could be
affected by potential changes in environmental regulations in the State of New York, as well as our ability to obtain permits necessary for the operation of our facilities. For further discussion of these matters, Please read Note
10Commitments and ContingenciesRoseton State Pollutant Discharge Elimination System Permit and Note 10Commitments and Contingencies Danskammer State Pollutant Discharge Elimination System Permit.

GEN-SO. We entered into various agreements in September 2005 extending the steam and energy sales component of an ongoing
relationship to sell up to approximately 80 MW of energy and 1.5 million pounds per hour of steam from our CoGen Lyondell cogeneration facility to Lyondell Chemical Company (Lyondell) for an initial term from January 2007 through
December 2021 and subsequent automatic rollover terms of two years each



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thereafter through December 2046. Incremental annual operating income associated with this contract is expected to range between $40 million to $55 million.
The primary drivers of this improvement are the adjustment to the price of steam supplied to Lyondell and our ability to optimize power and steam generation for the entire Lyondell facility to capture maximum market potential from the CoGen Lyondell
cogeneration facility.

Our peaking facilities in the South continue to contribute revenue from sales of capacity mainly to local
load-serving entities or wholesale buyers. We currently have the majority of the portfolio capacity committed in the near-term, and a portion of our portfolio capacity committed on an annual basis through 2015. We continue to pursue opportunities to
sell additional capacity from these facilities as well as our Lyondell cogeneration facility. We expect opportunities for capacity sales will develop at times during the year. However, due to the regulated, non-liquid market in the southeast region,
our results will continue to be impacted by our ability to complete additional sales to a limited pool of buyers for these products and as a result, we anticipate capacity pricing in the South region will lag the remainder of the country.

CRM. Our CRM business segments future results of operations will be impacted by our ability to complete our exit from
this business. Our CRM business remains a party to certain legacy natural gas, power and emission transactions, most of which have been hedged. Although we continue to work diligently to minimize the financial impact of the CRM segment, we expect to
continue to incur cash outflows associated with these legacy transactions. We are proactively working with our customers to exit the remainder of our obligations on economically favorable terms.

Cash Flow Disclosures

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



|                                                                   |  |                                |      |   |      |   |      |  
|------------------------------------------------------------------ |  | ------------------------------ | ---- | - | ---- | - | ---- | -
|                                                                   |  | Nine Months EndedSeptember 30, |     
|                                                                   |  | 2006                           |      |   | 2005 |  
|                                                                   |  | (in millions)                  |     
|Operating cash flows from our generation businesses                |  | $                              | 503  |   |      | $ | 354  |  
|Operating cash flows used in our customer risk management business |  |                                | (370 | ) |      |   | (64  | )
|Operating cash flows from our natural gas liquids business         |  |                                |     |   |      |   | 241  |  
|Other operating cash flows                                         |  |                                | (313 | ) |      |   | (709 | )
|                                                                   |  |                                |      |   |      |   |      |  
|Net cash used in operating activities                              |  | $                              | (180 | ) |      | $ | (178 | )
|                                                                   |  |                                |      |   |      |   |      |  

Operating Cash Flow. Our cash flow used in operations totaled $180 million for the
nine months ended September 30, 2006. During the nine months ended September 30, 2006, our power generation business provided positive cash flow from operations of $503 million primarily due to positive earnings for the period. Our
customer risk management business used approximately $370 million in cash primarily due to a $370 million termination payment on our Sterlington tolling contract. Please read Note 3Dispositions, Contract Terminations and Discontinued
Operations Dispositions and Contract TerminationsSterlington Contract Termination for further information. Other and Eliminations includes a use of approximately $313 million in cash primarily due to interest payments to service debt and
general and administrative expenses, partially offset by interest income on cash balances and the receipt of approximately $20 million associated with the resolution of a legal dispute.

Our cash flow used in operations totaled $178 million for the nine months ended September 30, 2005. During the period, our GEN and NGL segments
provided positive cash flow from operations. GEN provided cash flow from operations of $354 million, and NGL provided cash flow from operations of $241 million primarily due to positive earnings for the period as well as the return of cash
collateral. Our CRM segment used approximately $64 million in cash primarily due to fixed payments associated with power tolling arrangements and our final payment of



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$26 million related to our exit from certain natural gas transportation contracts, offset by the return of cash collateral. Other and Eliminations includes a
use of approximately $709 million in cash primarily due to our payments of $255 million in 2005 in connection with the settlement of the shareholder class action litigation, interest payments to service debt, pension plan contributions, state tax
payments and general and administrative expenses.

Capital Expenditures and Investing Activities. Cash provided by investing
activities during the nine months ended September 30, 2006 totaled $213 million. Capital spending of $92 million was primarily comprised of $58 million, $12 million, and $16 million in the GEN-MW, GEN-NE, and GEN-SO segments, respectively. The
capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $6 million of capital expenditures in the Other segment.

Proceeds from the sale and acquisition of unconsolidated investments, net of cash acquired, totaled $165 million. This included net cash proceeds of $205
million from the sale of our 50% ownership interest in West Coast Power to NRG. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsWest Coast Power for further
information. This was partially offset by a payment of $45 million for our acquisition of NRGs 50% ownership interest in Rocky Road, which included $5 million of cash on hand. Please read Note 2Business CombinationsRocky Road for
more information.

Proceeds from assets sales, net totaled $18 million and primarily consisted of proceeds from the sale of a gas turbine
not in use.

The decrease in restricted cash of $125 million related primarily to the return of our $335 million deposit associated with
our former cash collateralized facility, offset by a $200 million deposit associated with our cash collateralized facility and a $10 million increase in the Independence restricted cash balance.

Cash used in investing activities during the nine months ended September 30, 2005 totaled $172 million. Capital spending of $132 million was
primarily comprised of $74 million, $11 million, $2 million and $39 million in the GEN-MW, GEN-NE, GEN-SO and NGL segments, respectively. The capital spending for the generation business segments primarily related to maintenance capital projects, as
well as $10 million in development capital associated with the completion of the Havana PRB conversion in GEN-MW. 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.

Financing Activities. Cash used in financing activities during the nine months ended September 30, 2006 totaled $1,094 million.
Repayments of long-term debt totaled $1,780 million for the nine months ended September 30, 2006 and consisted of the following payments:



| |  |  | $900 million in aggregate principal amount on our 10.125% Second Priority Senior Secured Notes due 2013;
| | - |  | --------------------------------------------------------------------------------------------------------



| |  |  | $614 million in aggregate principal amount on our 9.875% Second Priority Senior Secured Notes due 2010;
| | - |  | -------------------------------------------------------------------------------------------------------



| |  |  | $225 million in aggregate principal amount on our Second Priority Senior Secured Floating Rate Notes due 2008;
| | - |  | --------------------------------------------------------------------------------------------------------------



| |  |  | $23 million in aggregate principal amount on our 7.45% Senior Notes due 2006; and
| | - |  | ---------------------------------------------------------------------------------



| |  |  | $18 million in aggregate principal amount on our 8.50% secured bonds due 2007.
| | - |  | ------------------------------------------------------------------------------

In addition to the above repayments, we redeemed all of the outstanding shares of our Series C Preferred for $400 million.

Debt conversion costs of $249 million consisted of the following payments:



| |  |  | $204 million to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | $44 million aggregate premium to induce conversion of our $225 million 4.75% Convertible Subordinated Debentures due 2023; and
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



| |  |  | $1 million in transaction costs associated with the redemption of our Series C Preferred.
| | - |  | -----------------------------------------------------------------------------------------

The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:



| |  |  | $750 million aggregate principal amount from a private offering of our 8.375% Senior Unsecured Notes due 2016;
| | - |  | --------------------------------------------------------------------------------------------------------------



| |  |  | $200 million, LIBOR + 1.75% letter of credit facility due 2012; and
| | - |  | -------------------------------------------------------------------



| |  |  | $150 million, LIBOR + 1.75% term loan due 2012.
| | - |  | -----------------------------------------------

Proceeds
from the issuance of common stock consisted primarily of approximately $178 million in proceeds from a common stock offering of 40.25 million shares of our Class A common stock at $4.60 per share, net of underwriting fees. Dividend
payments totaling $17 million were also made on our Series C Preferred prior to its redemption.

Cash used in financing activities during
the nine months ended September 30, 2005 totaled $73 million. Repayments of long-term debt totaled $40 million for the nine months ended September 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 $5 million on DHIs Term Loan. Cash used in financing activities also includes a semi-annual dividend payments of
$22 million on our Series C Preferred.

RISK-MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance sheets:



|                                                                                 |  |                                                     |      |  
|-------------------------------------------------------------------------------- |  | --------------------------------------------------- | ---- | -
|                                                                                 |  | As of and for theNine MonthsEnded September30, 2006 |     
|                                                                                 |  | (in millions)                                       |     
|Balance Sheet Risk-Management Accounts                                           |  |                                                     |      |  
|Fair value of portfolio at January 1, 2006                                       |  | $                                                   | (112 | )
|Risk-management gains recognized through the income statement in the period, net |  |                                                     | 28   |  
|Cash received related to risk-management contracts settled in the period, net    |  |                                                     | (17  | )
|Changes in fair value as a result of a change in valuation technique (1)         |  |                                                     |     |  
|Non-cash adjustments and other (2)                                               |  |                                                     | 96   |  
|                                                                                 |  |                                                     |      |  
|Fair value of portfolio at September 30, 2006                                    |  | $                                                   | (5   | )
|                                                                                 |  |                                                     |      |  

---

|(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.
|--- | -------------------------------------------------------------------------------------------------------------------------------

The net risk management liability of $5 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 September 30, 2006 and December 31, 2005. 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         |     |   | 2006 (3) |   |    | 2007 |  |   | 2008 |   |  | 2009 |     |   | 2010 |   | Thereafter
|                       |  | (in millions)
|September 30, 2006 (2) |  | $             | (60 | ) |          | $ | 5  |      |  | $ | (65  | ) |  | $    | (4  | ) |      | $ |           |   |  | $ |  |  | $ | 4
|December 31, 2005 (2)  |  |               | (84 | ) |          |   | (5 | )    |  |   | (65  | ) |  |      | (19 | ) |      |   | 2          |   |  |   |  |  |   | 3
|                       |  |               |     |   |          |   |    |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |  
|Increase (decrease)    |  | $             | 24  |   |          | $ | 10 |      |  | $ |     |   |  | $    | 15  |   |      | $ | (2         | ) |  | $ |  |  | $ | 1
|                       |  |               |     |   |          |   |    |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |  

---

|(1) | The table reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These
amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management liabilities at September 30, 2006 of $5 million on the unaudited condensed consolidated balance sheets include the $60
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 September 30, 2006 and December 31, 2005 were derived solely from market quotations.
|--- | -----------------------------------------------------------------------------------------------------------------

|(3) | Amounts represent October 1 to December 31, 2006 values in the September 30, 2006 row and January 1 to December 31, 2006 values in the December 31,
2005 row.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------

Cash Flow Components of Net Risk-Management Asset



|                      |  |                                   |    |   |                                    |   |           |  |      |   |  |      |     |   |      |   |     |      |  |            |    |   |  |   |   |  |   |  
|--------------------- |  | --------------------------------- | -- | - | ---------------------------------- | - | --------- |  | ---- | - |  | ---- | --- | - | ---- | - | --- | ---- |  | ---------- | -- | - |  | - | - |  | - | -
|                      |  | Nine MonthsEndedSeptember 30,2006 |    |   | Three MonthsEndedDecember 31, 2006 |   | Total2006 |  | 2007 |   |  | 2008 |     |   | 2009 |   |     | 2010 |  | Thereafter
|                      |  | (in millions)                    
|September 30, 2006(1) |  | $                                 | (1 | ) |                                    | $ | 6         |  | $    | 5 |  | $    | (66 | ) |      | $ | (5  | )    |  | $          |   |   |  | $ |  |  | $ | 6
|December 31, 2005     |  |                                   |    |   |                                    |   |           |  |      | 1 |  |      | (64 | ) |      |   | (21 | )    |  |            | 2  |   |  |   |  |  |   | 4
|                      |  |                                   |    |   |                                    |   |           |  |      |   |  |      |     |   |      |   |     |      |  |            |    |   |  |   |   |  |   |  
|Increase (decrease)   |  |                                   |    |   |                                    |   |           |  | $    | 4 |  | $    | (2  | ) |      | $ | 16  |      |  | $          | (2 | ) |  | $ |  |  | $ | 2
|                      |  |                                   |    |   |                                    |   |           |  |      |   |  |      |     |   |      |   |     |      |  |            |    |   |  |   |   |  |   |  

---

|(1) | The cash flow values for 2006 reflect realized cash flows for the nine months ended September 30, 2006 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.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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:



| |  |  | expectations and beliefs related to the combination with LS Entities including satisfying closing conditions and obtaining shareholder and regulatory approvals;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | expected synergies resulting from the combination with the LS Entities and beliefs associated with the integration of operations of both companies;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | projected operating or financial results, including anticipated cash flows from operations;
| | - |  | -------------------------------------------------------------------------------------------



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



| |  |  | beliefs about commodity pricing and generation volumes;
| | - |  | -------------------------------------------------------



| |  |  | our focus on safety and our ability to efficiently operate our assets so as to maximize our revenue generating opportunities;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | strategies to capture opportunities presented by rising commodity prices and strategies to manage our exposure to energy price volatility while reducing our long-term hedging
activities;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | plans to achieve fuel-related, general and administrative, and other targeted cost savings;
| | - |  | -------------------------------------------------------------------------------------------



| |  |  | beliefs and assumptions relating to our liquidity position;
| | - |  | -----------------------------------------------------------



| |  |  | strategies to address our substantial leverage, to access the capital markets, or to obtain additional financing or more favorable financing terms;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | measures to compete effectively with industry participants;
| | - |  | -----------------------------------------------------------



| |  |  | beliefs and assumptions about market competition, fuel supply, power demand, generation capacity and regional recovery of the wholesale power generation market;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | sufficiency of coal and fuel oil inventories and transportation, including strategies to deploy coal supplies;
| | - |  | --------------------------------------------------------------------------------------------------------------



| |  |  | beliefs about the outcome of legal and administrative proceedings, including the matters involving the western power and natural gas markets, environmental matters and the
investigations primarily relating to our past trading practices;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | assumptions about prospective regulatory developments, including those associated with and resulting from the Illinois auction;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------



| |  |  | expectations regarding environmental matters, including costs of compliance and availability and adequacy of emission credits;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



| |  |  | strategies to remediate the material weaknesses existing in our accounting for income taxes and our risk management assets and liabilities;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | expectations and estimates regarding the Baldwin consent decree and the associated costs;
| | - |  | -----------------------------------------------------------------------------------------



| |  |  | positioning our power generation business for future growth and pursuing and executing acquisition or combination opportunities; and
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our ability to complete our exit from the customer risk management 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, many of which are beyond our control, including those set forth under Part IIOther Information, Item 1ARisk Factors.



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RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1Accounting Policies to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us.

CRITICAL ACCOUNTING POLICIES

Please read
Critical Accounting Policies beginning on page 40 of our Form 10-K/A 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/A.

Item 3QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A.
Quantitative and Qualitative Disclosures About Market Risk beginning on page 85 of our Form 10-K/A for a discussion of our exposure to commodity price variability and other market risks, including foreign currency exchange rate risk. Following is a
discussion of the more material of these risks and our relative exposures as of September 30, 2006.

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

Daily and Average VaR for Risk-Management Portfolios



|                                                             |  |                   |   |                  |   |  
|------------------------------------------------------------ |  | ----------------- | - | ---------------- | - | -
|                                                             |  | September 30,2006 |   | December 31,2005
|                                                             |  | (in millions)    
|One Day VaR95% Confidence Level                             |  | $                 | 2 |                  | $ | 5
|One Day VaR99% Confidence Level                             |  | $                 | 3 |                  | $ | 6
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $                 | 3 |                  | $ | 7

Credit Risk. The following table represents our credit exposure at
September 30, 2006 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              |  | $                       | 51 |                             | $ |      |  | $ | 51
|Commercial/Industrial/End Users     |  |                         |   |                             |   |      |  |   |  
|Utility and Power Generators        |  |                         | 42 |                             |   | 4     |  |   | 46
|Crude Oil and Natural Gas Producers |  |                         |   |                             |   |      |  |   |  
|                                    |  |                         |    |                             |   |       |  |   |   
|Total                               |  | $                       | 93 |                             | $ | 4     |  | $ | 97
|                                    |  |                         |    |                             |   |       |  |   |   

Of the $4 million in credit exposure to non-investment grade counterparties, 55% is collateralized
or subject to other credit exposure protection.

Interest Rate Risk. We are exposed to fluctuating interest rates related to
variable rate financial obligations. As of September 30, 2006, our fixed rate debt instruments as a percentage of total debt instruments was approximately 79%. Based on sensitivity analysis of the variable rate financial obligations in our debt
portfolio as of September 30, 2006, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended September 30, 2007 would either decrease or
increase income before taxes by approximately $9 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.



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Derivative Contracts. The notional financial contract amounts associated with our commodity
risk-management, interest rate and foreign currency exchange contracts were as follows at September 30, 2006 and December 31, 2005, respectively:

Absolute Notional Contract Amounts



|                                                                       |  |                   |        |                  |   |       
|---------------------------------------------------------------------- |  | ----------------- | ------ | ---------------- | - | ------
|                                                                       |  | September 30,2006 |        | December 31,2005
|Natural Gas (Trillion Cubic Feet)                                      |  |                   | 0.310  |                  |   | 0.374 
|Electricity (Million Megawatt Hours) (1)                               |  |                   | 94.567 |                  |   | 30.479
|Emission Credits (Million Tons) (2)                                    |  |                   | 0.031  |                  |   | 0.043 
|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 
|Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)   |  | $                 | 231    |                  | $ | 306   
|Fixed Interest Rate Paid (Percent)                                     |  |                   | 5.35   |                  |   | 5.29  
|Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)   |  | $                 | 206    |                  | $ | 281   
|Fixed Interest Rate Received (Percent)                                 |  |                   | 5.28   |                  |   | 5.23  

---

|(1) | This amount includes notional volumes related to additional Financial Transmission Rights (FTRs) that we acquired in various ISOs during 2006.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------

|(2) | These amounts represent emission credit contracts that we are required to account for as derivatives under SFAS No. 133. These amounts do not include the emission
credits that we have recorded in our inventory related to allowances that we utilize in running our power generation fleet.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Item 4CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, 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 15(d)-15(e) under the Exchange
Act). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized
and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the third quarter 2006 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 September 30, 2006, as a result of the material weaknesses identified 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.

Notwithstanding the material weaknesses that existed at September 30, 2006, management believes, based on its knowledge, that the financial
statements, and other financial information included in this report, fairly present in all material respects in accordance with GAAP our financial condition, results of operations and cash flows as of, and for, the periods presented in this report.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a
material misstatement of our annual or interim financial statements would not be prevented or detected. We have identified the following material weaknesses:



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Material Weakness Related to Income Taxes

As of December 31, 2005 and September 30, 2006, we did not maintain effective controls over the completeness and accuracy of the tax provision
and deferred income tax balances in accordance with GAAP. Specifically, our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision were not effective to ensure that the tax provision and
deferred tax balances were recorded in accordance with GAAP. This control deficiency resulted in the restatement of our 2004 and 2003 annual consolidated financial statements, as well as audit adjustments to the 2005 income tax provision. This
control deficiency also resulted in the restatement of the 2005 consolidated financial statements as reported in our Annual Report on Form 10-K/A. Further, this control deficiency could result in a misstatement of the income tax provision and
related deferred tax accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Therefore, as of December 31, 2005 and
September 30, 2006, we concluded that this control deficiency constitutes a material weakness.

Status of Remediation of
Material Weakness Related to Income Taxes. During 2005, the following steps were taken to improve our internal controls around our tax accounting and tax reconciliation processes, procedures and controls: (i) increased levels of review
in the preparation of the quarterly and annual tax provisions; (ii) formalized processes, procedures and documentation standards relating to the income tax provision; and (iii) restructured our Tax Department to ensure appropriate
segregation of duties regarding preparation and review of the quarterly and annual tax provision. Despite these efforts, when making managements assessment of the effectiveness of our internal control over financial reporting as of
December 31, 2005, we determined that those controls were still not operating effectively.

In addition to continuing the enhanced
processes implemented in 2005 and described above, during the second and third quarters of 2006, we implemented the following steps in an attempt to remediate the material weakness reported at December 31, 2005: (i) implemented new
processes around the analysis of the income tax provision, including detailed reconciliations between book basis and tax basis of significant tax sensitive balance sheet accounts; (ii) implemented additional procedures around identifying,
analyzing and recording the tax effects of significant transactions; (iii) formalized communication channels between the Tax and Accounting Departments, and (iv) enhanced the competencies of our Tax Department personnel through the addition of
experienced tax professionals. We are also in the process of implementing the following steps: (i) further formalizing and documenting the procedures around the preparation and review of the tax provision and tax accounts; (ii) enhancing
the competencies and capabilities of our Tax Department personnel through ongoing formal training initiatives in key tax-related areas and (iii) simplifying the data entry process surrounding the automated tax provision calculation. Finally, we
also engaged an independent consulting firm, which has assessed and provided recommendations to strengthen our processes and procedures.

We believe we are taking the 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 2006 annual tax provision. Accordingly, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further
changes management determines are necessary. We will not be able to conclude that this material weakness has been successfully remediated, and we cannot assure you we will be able to make such conclusion, until managements testing and
assessment demonstrates that such controls have operated effectively for a sufficient period of time.

Material Weakness Related to
Risk Management Assets and Liabilities

As of September 30, 2006, we did not maintain effective controls over the accuracy of
our risk management asset and liability balances. Our processes, procedures and controls related to the calculation and analysis of applicable pricing data were not effective to ensure that the risk management asset and liability balances were
accurately reflected in the financial statements. This control deficiency resulted in an adjustment to the first quarter 2006 interim condensed consolidated financial statements prior to being reported in our Quarterly Report on Form 10-Q for the
interim period ended March 31, 2006. Further, this control deficiency could result in a misstatement of revenue and the related risk management asset and liability balances that would result in a material misstatement to the annual or interim
consolidated financial statements that would not be prevented or detected. Therefore, as of September 30, 2006, we concluded that this control deficiency constitutes a material weakness.



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Status of Remediation of Material Weakness Related to Risk Management Assets and Liabilities.In order to remediate this material weakness, during the second and third quarters 2006, we implemented the following steps around our risk management asset and liability valuation process: (i) automated a process step that was
previously performed manually; (ii) further formalized and documented the procedures around the end-of-day valuation process; (iii) expanded the review and validation process with respect to pricing data; (iv) performed a review of
all pricing data to eliminate redundant or unnecessary data; (v) implemented a new monthly process to identify pricing data related to active positions; and (vi) further restricted access to and assigned accountability for process
documentation. We also engaged an independent third party to review, evaluate and test our processes, procedures and controls related to the calculation and analysis of pricing data. This review was completed in the third quarter 2006, and the
resulting recommendations did not require significant changes to our current procedures or controls.

We believe we have taken the steps
necessary to remediate this material weakness related to the accuracy of our risk management asset and liability balances. However, the controls have not been in place for an adequate period of time to test and conclude that they are operating
effectively and that the material weakness has been remediated. Accordingly, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further changes management determines are necessary.

Changes in Internal Control Over Financial Reporting

The changes discussed above in the Item 4 were 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 control performed during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial
reporting. There were no other changes in our internal control over financial reporting during the quarter ended September 30, 2006.



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DYNEGY INC.

PART II. OTHER INFORMATION

Item 1LEGAL PROCEEDINGS

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

Item 1ARISK FACTORS

Item 1A. Risk Factors beginning on page 23 of our 2005 Form 10-K, page 56
of our first quarter 2006 Form 10-Q and page 72 of our second quarter 2006 Form 10-Q includes a detailed discussion of our risk factors. The information presented below updates, and should be read in conjunction with, the risk factors and
information disclosed in our 2005 Form 10-K and first and second quarter 2006 Form 10-Qs.

The Merger Agreement with the LS Entities
and related transactions, regardless of whether they are ultimately consummated, have presented and will continue to present us with certain risks and uncertainties, and have imposed and will continue to impose on us and our business and operations
certain restrictions and significant financial and other costs. In addition, if the Merger Agreement and related transactions are ultimately consummated, the expected benefits of the Merger Agreement and related transactions may not be realized in a
timely or efficient manner or at all, and the LS Entities, by virtue of their stock ownership of New Dynegy, will have significant influence over New Dynegys business and operations and may have interests that differ from, and conflict with,
the interests of our shareholders.

The consummation of the Merger Agreement with the LS Entities and related transactions is
subject to the approval of our shareholders and is conditioned upon our and the LS Entities receipt of various approvals, consents and clearances from various governmental and regulatory entities. We cannot assure you that we and the LS
Entities will receive these approvals, consents and clearances in a timely manner or at all and, as a result, we cannot assure you that the Merger Agreement and related transactions will be consummated in a timely manner or at all. Moreover, a
substantial delay in obtaining these approvals, consents and clearances or the imposition of unfavorable terms or conditions in connection with obtaining such approvals, consents and clearances could have a material adverse effect on our and/or New
Dynegys business, financial condition and results of operations and may cause us and/or the LS Entities to abandon the Merger Agreement and related transactions. In addition, the Merger Agreement restricts us, without the LS Entities
consent, from taking certain specified actions until the Merger Agreement is consummated or terminated. These restrictions may prevent us from pursuing otherwise attractive business opportunities and effecting other beneficial transactions and
changes to our business and operations prior to the consummation or termination of the Merger Agreement.

We entered into the Merger
Agreement with the LS Entities with the expectation that the combination of our business and operations with the business and operations of the power generation entities to be contributed by the LS Entities pursuant to the Merger Agreement would
result in various benefits, including, among other things, certain synergies, cost savings and operating efficiencies. Although we expect these and other anticipated benefits of the Merger Agreement and related transactions to be realized, we cannot
assure you that such benefits will be realized in a timely manner, in full or at all.

In addition, we have incurred and expect to continue
to incur significant costs in connection with consummating the Merger Agreement and related transactions. We also expect to incur, upon the consummation of the Merger Agreement and related transactions, costs in connection with integrating our
operations and procedures with the operations and procedures of the power generation entities to be contributed by the LS Entities. Although we believe that the realization of certain synergies, cost savings and operating efficiencies related to the
integration of our business with that of the power generation entities to be contributed by the LS Entities will offset these costs over time, we cannot assure you that this benefit will be realized in a timely manner, in full or at all.



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If the Merger Agreement and related transactions are consummated, we will face significant challenges in
integrating, in a timely and efficient manner, our operations and procedures with the operations and procedures of the power generation entities to be contributed by the LS Entities. As a result, we cannot assure you that the integration will be
completed in a timely or efficient manner. In addition, such integration efforts could also divert our managements focus and resources from our and, subsequent to the consummation of the Merger Agreement, New Dynegys day-to-day business
and operations. Such diversion of our managements focus and resources could have a material and adverse effect on our and, subsequent to the consummation of the Merger Agreement, New Dynegys business, financial condition and results of
operations.

Furthermore, subsequent to the consummation of the Merger Agreement and related transactions, the LS Entities will own
approximately 40% of the voting power of New Dynegy and will have the right to nominate up to three members of the 11-member board of directors of New Dynegy. By virtue of such stock ownership and board representation, the LS Entities will have the
power to influence New Dynegys affairs as well as the outcome of matters submitted to a vote of New Dynegys stockholders. Moreover, the LS Entities may have interests that differ from, and conflict with, those of our shareholders, who
will be holders of New Dynegys common stock upon the consummation of the Merger Agreement and related transactions.

If we
issue a material amount of our common stock in the future or certain of our shareholders sell a material amount of our common stock, we could be subject to an annual limitation on the utilization of our net operating losses (NOLs) and alternative
minimum tax (AMT) credits under Sections 382 and 383 of the Internal Revenue Code.

If we were to undergo an ownership
change within the meaning of Section 382 of the Internal Revenue Code (the Code), an annual limitation could be imposed against our utilization of previously incurred NOLs against future taxable income or existing AMT credits
against future tax liability. In general, an ownership change occurs whenever there is more than a 50% change in the ownership of the stock of a corporation, taking into account all cumulative changes in ownership over the preceding three years.

More specifically, depending on prevailing interest rates and our market value at the time of such future ownership change, an ownership
change under Section 382 of the Code would establish an annual limitation which might prevent full utilization of the deferred tax assets attributable to our previously incurred NOLs against the total future taxable income of a given year or
full utilization of our AMT credits against the total future tax liability of a given year. The annual limitation would not affect the expiration dates of our NOLs, which, under current law, begin to expire in 2022; AMT credits do not expire. The
consummation of the Merger Agreement and related transactions with the LS Entities will increase the likelihood that previously incurred NOLs and AMT credits will become subject to the limitations set forth in Sections 382 and 383 of the Code.
Avoiding such an ownership change may limit our ability and, subsequent to the consummation of the Merger Agreement and related transactions (if consummated), New Dynegys ability to raise additional equity capital in the near future.

The magnitude of such limitations and their effect on us and, subsequent to the consummation of the Merger Agreement and related
transactions (if consummated), their effect on New Dynegy, is difficult to assess and may depend in part on our or New Dynegys (as the case may be) value at the time of any such ownership change and prevailing interest rates. For accounting
purposes, at December 31, 2005, our net operating loss deferred tax asset attributable to our previously incurred NOLs was valued at approximately $198 million and our AMT credits were valued at approximately $256 million.

We have reported two material weaknesses in our internal control over financial reporting, one of which caused a restatement, and both of which, if
not remedied, could continue to adversely affect our internal controls and financial reporting.

In connection with our
managements assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, our management concluded that, as of December 31, 2005, we did not maintain effective internal control over our
financial reporting due to a material weakness in our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. Our managements



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assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 was audited by PricewaterhouseCoopers LLP,
which expressed an unqualified opinion on managements assessment and an adverse opinion on the effectiveness of our internal control over financial reporting as of December 31, 2005.

Likewise, in connection with our managements assessment of the effectiveness of our internal control over financial reporting as of
September 30, 2006, our management concluded that, as of September 30, 2006, we did not maintain effective internal control over our financial reporting due to the same material weakness in our processes, procedures and controls related to
the preparation, analysis and recording of the income tax provision. Also in connection with our managements assessment as of September 30, 2006, our management concluded that, as of September 30, 2006, we did not maintain effective
internal control over our financial reporting due to a material weakness in our processes, procedures and controls related to the calculation and analysis of our risk management asset and liability balances. A material weakness is a control
deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements would not be prevented or detected.

We previously reported in our Annual Report on Form 10-K, as amended, for the fiscal year ended December 31, 2004 that we did not maintain effective
internal control over our financial reporting as of December 31, 2004 due to a material weakness in our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. During 2005, actions were
taken to remediate this material weakness. Despite these efforts, when making managements assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, we determined that those processes and
controls were still not operating effectively. This control deficiency resulted in the restatement of our 2004 and 2003 annual consolidated financial statements, as well as year-end audit adjustments to the 2005 income tax provision. This control
deficiency also resulted in the restatement of our consolidated financial statements for the year ended December 31, 2005, as reported in Amendment No. 1 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2005.
Further, this control deficiency could have resulted in a misstatement of the income tax provision and related deferred tax accounts and disclosures that would result in a material misstatement to our annual or interim consolidated financial
statements that would not be prevented or detected.

The material weakness related to the calculation and analysis of our risk management
asset and liability balances resulted in an adjustment to our condensed consolidated financial statements as of and for the three months ended March 31, 2006 prior to being reported in our Quarterly Report on Form 10-Q for the quarterly period
ended March 31, 2006. Further, this control deficiency could result in a misstatement of revenue and the related risk management asset and liability balances that would result in a material misstatement to our annual or interim consolidated
financial statements that would not be prevented or detected.

We believe we are taking the steps necessary to remediate the 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
2006 annual tax provision. We also believe we are taking the steps necessary to remediate the material weakness related to the accuracy of our risk management asset and liability balances. However, the controls have not been in place for an adequate
period of time to test and conclude that they are operating effectively. Accordingly, in each case, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further changes management
determines are necessary; however, we cannot assure you that these processes, procedures and controls will result in full remediation of the two material weaknesses described above. Failure to remediate these material weaknesses, or the
identification of one or more additional material weaknesses, could result in materially inaccurate financial reports and negatively impact the markets view of our control environment and, potentially, our stock price.



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Item 6EXHIBITS

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



|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                
|------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                    
|              | 
|2.1           |  | Plan of Merger, Contribution and Sale Agreement dated September 14, 2006 by and among Dynegy Inc., LSP Gen Investors, LP, LS Power Partners, LP, LS Power Equity Partners PIE I, L.P., LS Power
Equity Partners, L.P., LS Power Associates, L.P., Falcon Merger Sub Co. and Dynegy Acquisition, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No.
1-15659).
|              | 
|2.2           |  | Limited Liability Company Membership Interests and Stock Purchase Agreement dated as of September 14, 2006, among LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity
Partners PIE I, L.P., LS Power Partners, L.P. and Kendall Power LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).                                    
|              | 
|4.1           |  | Registration Rights Agreement, effective as of July 21, 2006, by and among Dynegy Holdings Inc., RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 4.1 to the Current
Report on Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659).                                                                                                                                                                        
|              | 
|4.2           |  | Shareholder Agreement dated as of September 14, 2006 among Dynegy Acquisition, Inc. and LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity
Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).                                                        
|              | 
|4.3           |  | Registration Rights Agreement dated as of September 14, 2006 among Dynegy Acquisition, Inc., LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power
Equity Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).                                                   
|              | 
|4.4           |  | Registration Rights Agreement dated as of September 14, 2006 among Dynegy Acquisition, Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K
of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).                                                                                                                                                                                 
|              | 
|4.5           |  | Registration Rights Agreement dated as of September 14, 2006 among Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K of Dynegy
Inc. filed on September 19, 2006, File No. 1-15659).                                                                                                                                                                                              
|              | 
|4.6           |  | Lock-Up Agreement dated as of September 14, 2006 by and among LSP Gen Investors, LP, LS Power Partners, LP, LS Power Associates, L.P., LS Power Equity Partners PIE I, LP, LS Power Equity
Partners, L.P. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).                                                                   
|              | 
|10.1          |  | Exchange Agreement, dated as of July 21, 2006, by and among Dynegy Holdings Inc., RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on
Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659).                                                                                                                                                                                      



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|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.2   |  | Amendment No. 2, dated as of July 11, 2006, to the Fourth Amended and Restated Credit Agreement, dated as of April 19, 2006, among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent
guarantor, the other guarantors party thereto, the lenders party thereto and the various other parties thereto (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Dynegy Inc. for the quarterly period ended June 30,
2006 filed on August 10, 2006, File No. 1-15659).
|       | 
|10.3   |  | Voting Agreement dated as of September 14, 2006 by and among LSP Gen Investors, LP, LS Power Partners LP, LS Power Associates, L.P., LS Power Equity Partners PIE I, LP, LS Power Equity
Partners, L.P. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).                                                                                                                         
|       | 
|10.4   |  | Voting Agreement dated as of September 14, 2006 by and among LS Power Associates, L.P., LSP Gen Investors, LP, LS Power Equity Partners PIE I, LP, LS Power Equity Partners, L.P., LS Power
Partners, LP and Bruce A. Williamson, Stephen A. Furbacher, Holli C. Nichols, Lynn A. Lednicky and J. Kevin Blodgett (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No.
1-15659).                                        
|       | 
|10.5   |  | Corporate Opportunity Agreement dated as of September 14, 2006 between Dynegy Acquisition, Inc. and LS Power Development, LLC (incorporated by reference to Exhibit 10.3 to the Current Report
on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).                                                                                                                                                                                                                           
|       | 
|10.6   |  | BGS-FP Supplier Forward Contract by and between Dynegy Power Marketing, Inc., Central Illinois Light Company d/b/a AmerenCILCO, Central Illinois Public Service Company d/b/a AmerenCIPS and
Illinois Power Company d/b/a AmerenIP dated September 20, 2006 (Term through May 31, 2008) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 25, 2006, File No. 1-15659).                                                                 
|       | 
|10.7   |  | BGS-FP Supplier Forward Contract by and between Dynegy Power Marketing, Inc., Central Illinois Light Company d/b/a AmerenCILCO, Central Illinois Public Service Company d/b/a AmerenCIPS and
Illinois Power Company d/b/a AmerenIP dated September 20, 2006 (Term through May 31, 2009) (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 25, 2006, 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.                                                                                                                                                                                                                                                                                                                                         



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|   |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|-- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|** |  | 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 Securities Act.



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DYNEGY INC.

SIGNATURES

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



|                       |  |             |  |                                                                                                                               
|---------------------- |  | ----------- |  | ------------------------------------------------------------------------------------------------------------------------------
|                       |  | DYNEGY INC.
|                       |  |            
|Date: November 8, 2006 |  | By:         |  | /S/ HOLLI C. NICHOLS                                                                                                          
|                       |  |             |  | Holli C. Nichols Executive Vice President and Chief Financial Officer(Duly Authorized Officer and Principal Financial Officer)



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