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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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

For the quarterly period ended September 30, 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: 000-29311



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DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)



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|                         |  |                                     
|------------------------ |  | ------------------------------------
|Delaware                 |  | 94-3248415                          
|(State 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)



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

Indicate by check mark whether the registrant is 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 ̈Accelerated filer ̈Non-accelerated filer  x

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

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



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##### Table of Contents

DYNEGY HOLDINGS 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                                    |  | 42  
|                              |  | Item 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                                               |  | 68  
|                              |  | Item 4.
CONTROLS AND PROCEDURES                                                                                                  |  | 69  
|                              |  |                                                                                                                                 
|                              |  | PART II.
OTHER INFORMATION                                                                                                       |  |     
|                              |  |                                                                                                                                 
|                              |  | Item 1.
LEGAL PROCEEDINGS                                                                                                        |  | 72  
|                              |  | Item 1A.
RISK FACTORS                                                                                                            |  | 72  
|                              |  | Item 6.
EXHIBITS                                                                                                                 |  | 75  



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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 Holdings, we, us, our and the
Company refer to Dynegy Holdings Inc. and its subsidiaries, unless the context clearly indicates otherwise. The term Dynegy refers to our parent company, Dynegy Inc., and its subsidiaries, including us, 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                           
|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 HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)



|                                                                                                               |  |                   |        |   |                  |   |        |  
|-------------------------------------------------------------------------------------------------------------- |  | ----------------- | ------ | - | ---------------- | - | ------ | -
|                                                                                                               |  | September 30,2006 |        |   | December 31,2005 |  
|ASSETS                                                                                                         |  |                   |        |   |                  |   |        |  
|Current Assets                                                                                                 |  |                   |        |   |                  |   |        |  
|Cash and cash equivalents                                                                                      |  | $                 | 237    |   |                  | $ | 1,301  |  
|Restricted cash                                                                                                |  |                   | 200    |   |                  |   | 335    |  
|Accounts receivable, net of allowance for doubtful accounts of $68 and $101, respectively                      |  |                   | 270    |   |                  |   | 598    |  
|Accounts receivable, affiliates                                                                                |  |                   | 53     |   |                  |   | 61     |  
|Inventory                                                                                                      |  |                   | 190    |   |                  |   | 203    |  
|Assets from risk-management activities                                                                         |  |                   | 346    |   |                  |   | 667    |  
|Deferred income taxes                                                                                          |  |                   | 21     |   |                  |   | 24     |  
|Prepayments and other current assets                                                                           |  |                   | 48     |   |                  |   | 149    |  
|Assets held for sale (Note 4)                                                                                  |  |                   | 1      |   |                  |   |       |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Total Current Assets                                                                                           |  |                   | 1,366  |   |                  |   | 3,338  |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment                                                                                  |  |                   | 6,061  |   |                  |   | 6,160  |  
|Accumulated depreciation                                                                                       |  |                   | (1,395 | ) |                  |   | (1,181 | )
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                                             |  |                   | 4,666  |   |                  |   | 4,979  |  
|                                                                                                               |  |                  
|Other Assets                                                                                                   |  |                   |        |   |                  |   |        |  
|Unconsolidated investments                                                                                     |  |                   | 7      |   |                  |   | 267    |  
|Assets from risk-management activities                                                                         |  |                   | 131    |   |                  |   | 197    |  
|Intangible assets                                                                                              |  |                   | 15     |   |                  |   |       |  
|Long-term note receivable, affiliate                                                                           |  |                   | 291    |   |                  |   |       |  
|Long-term accounts receivable, affiliates                                                                      |  |                   | 664    |   |                  |   | 675    |  
|Deferred income taxes                                                                                          |  |                   | 3      |   |                  |   | 3      |  
|Other long-term assets                                                                                         |  |                   | 123    |   |                  |   | 160    |  
|Assets held for sale (Note 4)                                                                                  |  |                   | 194    |   |                  |   |       |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Total Assets                                                                                                   |  | $                 | 7,460  |   |                  | $ | 9,619  |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                           |  |                   |        |   |                  |   |        |  
|                                                                                                               |  |                  
|Current Liabilities                                                                                            |  |                   |        |   |                  |   |        |  
|Accounts payable                                                                                               |  | $                 | 211    |   |                  | $ | 501    |  
|Accounts payable, affiliates                                                                                   |  |                   |       |   |                  |   | 45     |  
|Accrued interest                                                                                               |  |                   | 82     |   |                  |   | 112    |  
|Accrued liabilities and other current liabilities                                                              |  |                   | 175    |   |                  |   | 616    |  
|Liabilities from risk-management activities                                                                    |  |                   | 351    |   |                  |   | 700    |  
|Liabilities held for sale (Note 4)                                                                             |  |                   | 1      |   |                  |   |       |  
|Note payable to affiliate                                                                                      |  |                   |       |   |                  |   | 120    |  
|Notes payable and current portion of long-term debt                                                            |  |                   | 2      |   |                  |   | 29     |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Total Current Liabilities                                                                                      |  |                   | 822    |   |                  |   | 2,123  |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Long-term debt                                                                                                 |  |                   | 2,727  |   |                  |   | 3,087  |  
|Long-term debt, affiliates                                                                                     |  |                   | 200    |   |                  |   | 200    |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Long-Term Debt                                                                                                 |  |                   | 2,927  |   |                  |   | 3,287  |  
|                                                                                                               |  |                  
|Other Liabilities                                                                                              |  |                   |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                                    |  |                   | 139    |   |                  |   | 295    |  
|Deferred income taxes                                                                                          |  |                   | 154    |   |                  |   | 245    |  
|Other long-term liabilities                                                                                    |  |                   | 308    |   |                  |   | 340    |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Total Liabilities                                                                                              |  |                   | 4,350  |   |                  |   | 6,290  |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Commitments and Contingencies (Note 10)                                                                        |  |                   |        |   |                  |   |        |  
|Stockholders Equity                                                                                           |  |                   |        |   |                  |   |        |  
|Capital Stock, $1 par value, 1,000 shares authorized at September 30, 2006 and December 31, 2005, respectively |  |                   |       |   |                  |   |       |  
|Additional paid-in capital                                                                                     |  |                   | 2,362  |   |                  |   | 2,412  |  
|Accumulated other comprehensive income, net of tax                                                             |  |                   | 59     |   |                  |   | 4      |  
|Accumulated deficit                                                                                            |  |                   | (343   | ) |                  |   | (119   | )
|Stockholders equity                                                                                           |  |                   | 1,032  |   |                  |   | 1,032  |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Total Stockholders Equity                                                                                     |  |                   | 3,110  |   |                  |   | 3,329  |  
|                                                                                                               |  |                   |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                                     |  | $                 | 7,460  |   |                  | $ | 9,619  |  
|                                                                                                               |  |                   |        |   |                  |   |        |  

See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)



|                                                                                                              |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |        |  
|------------------------------------------------------------------------------------------------------------- |  | ------------------------------- | ---- | - | ------------------------------ | - | ---- | ---- |  | - | ----- | - |  | - | ------ | -
|                                                                                                              |  | Three Months EndedSeptember 30, |      |   | Nine Months EndedSeptember 30, |  
|                                                                                                              |  | 2006                            |      |   | 2005                           |   |      | 2006 |  |   | 2005  |  
|Revenues                                                                                                      |  | $                               | 465  |   |                                | $ | 735  |      |  | $ | 1,363 |   |  | $ | 1,525  |  
|Cost of sales, exclusive of depreciation shown separately below                                               |  |                                 | (324 | ) |                                |   | (472 | )    |  |   | (901  | ) |  |   | (1,103 | )
|Depreciation and amortization expense                                                                         |  |                                 | (54  | ) |                                |   | (54  | )    |  |   | (164  | ) |  |   | (158   | )
|Impairment and other charges                                                                                  |  |                                 | (96  | ) |                                |   |     |      |  |   | (107  | ) |  |   | 1      |  
|Gain (loss) on sale of assets, net                                                                            |  |                                 |     |   |                                |   | (2   | )    |  |   | 3     |   |  |   | (2     | )
|General and administrative expenses                                                                           |  |                                 | (57  | ) |                                |   | (78  | )    |  |   | (158  | ) |  |   | (320   | )
|                                                                                                              |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |        |  
|Operating income (loss)                                                                                       |  |                                 | (66  | ) |                                |   | 129  |      |  |   | 36    |   |  |   | (57    | )
|Earnings from unconsolidated investments                                                                      |  |                                 | 4    |   |                                |   | 5    |      |  |   | 6     |   |  |   | 10     |  
|Interest expense                                                                                              |  |                                 | (60  | ) |                                |   | (79  | )    |  |   | (224  | ) |  |   | (229   | )
|Debt conversion costs                                                                                         |  |                                 | (2   | ) |                                |   |     |      |  |   | (204  | ) |  |   |       |  
|Other income and expense, net                                                                                 |  |                                 | 14   |   |                                |   | (4   | )    |  |   | 37    |   |  |   | (4     | )
|                                                                                                              |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |        |  
|Income (loss) from continuing operations before income taxes                                                  |  |                                 | (110 | ) |                                |   | 51   |      |  |   | (349  | ) |  |   | (280   | )
|Income tax benefit (expense) (Note 13)                                                                        |  |                                 | 41   |   |                                |   | (16  | )    |  |   | 122   |   |  |   | 96     |  
|                                                                                                              |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |        |  
|Income (loss) from continuing operations                                                                      |  |                                 | (69  | ) |                                |   | 35   |      |  |   | (227  | ) |  |   | (184   | )
|Income from discontinued operations, net of tax expense of $5, $26, $5 and $24, respectively (Notes 4 and 13) |  |                                 | 3    |   |                                |   | 43   |      |  |   | 3     |   |  |   | 131    |  
|                                                                                                              |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |        |  
|Net income (loss)                                                                                             |  | $                               | (66  | ) |                                | $ | 78   |      |  | $ | (224  | ) |  | $ | (53    | )
|                                                                                                              |  |                                 |      |   |                                |   |      |      |  |   |       |   |  |   |        |  

See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



|                                                                                           |  |                                 |        |   |      |   |      |  
|------------------------------------------------------------------------------------------ |  | ------------------------------- | ------ | - | ---- | - | ---- | -
|                                                                                           |  | Nine Months Ended September 30, |       
|                                                                                           |  | 2006                            |        |   | 2005 |  
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                      |  |                                 |        |   |      |   |      |  
|Net loss                                                                                   |  | $                               | (224   | ) |      | $ | (53  | )
|Adjustments to reconcile net loss to net cash flows from operating activities:             |  |                                 |        |   |      |   |      |  
|Depreciation and amortization                                                              |  |                                 | 198    |   |      |   | 204  |  
|Impairment and other charges                                                               |  |                                 | 107    |   |      |   | (1   | )
|(Earnings) losses from unconsolidated investments, net of cash distributions               |  |                                 | (6     | ) |      |   | 51   |  
|Risk-management activities                                                                 |  |                                 | (80    | ) |      |   | (96  | )
|Gain on sale of assets, net                                                                |  |                                 | (3     | ) |      |   | (8   | )
|Deferred income taxes                                                                      |  |                                 | (116   | ) |      |   | (74  | )
|Legal and settlement charges                                                               |  |                                 | 14     |   |      |   |     |  
|Debt conversion costs                                                                      |  |                                 | 204    |   |      |   |     |  
|Other                                                                                      |  |                                 | 4      |   |      |   | 3    |  
|Changes in working capital:                                                                |  |                                 |        |   |      |   |      |  
|Accounts receivable                                                                        |  |                                 | 353    |   |      |   | (183 | )
|Inventory                                                                                  |  |                                 | 12     |   |      |   | (13  | )
|Prepayments and other assets                                                               |  |                                 | 96     |   |      |   | 106  |  
|Accounts payable and accrued liabilities                                                   |  |                                 | (776   | ) |      |   | (103 | )
|Changes in non-current assets                                                              |  |                                 | 11     |   |      |   | (4   | )
|Changes in non-current liabilities                                                         |  |                                 | (6     | ) |      |   | 8    |  
|                                                                                           |  |                                 |        |   |      |   |      |  
|Net cash used in operating activities                                                      |  |                                 | (212   | ) |      |   | (163 | )
|                                                                                           |  |                                 |        |   |      |   |      |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                      |  |                                 |        |   |      |   |      |  
|Capital expenditures                                                                       |  |                                 | (90    | ) |      |   | (132 | )
|Proceeds from asset sales, net                                                             |  |                                 | 15     |   |      |   | 11   |  
|Proceeds from exchange of unconsolidated investments, net of cash acquired (Notes 3 and 4) |  |                                 | 165    |   |      |   |     |  
|Decrease in restricted cash and restricted investments                                     |  |                                 | 135    |   |      |   |     |  
|Affiliate transactions                                                                     |  |                                 | (8     | ) |      |   | 194  |  
|Other investing                                                                            |  |                                 | (3     | ) |      |   |     |  
|                                                                                           |  |                                 |        |   |      |   |      |  
|Net cash provided by investing activities                                                  |  |                                 | 214    |   |      |   | 73   |  
|                                                                                           |  |                                 |        |   |      |   |      |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                      |  |                                 |        |   |      |   |      |  
|Proceeds from long-term borrowings, net                                                    |  |                                 | 1,071  |   |      |   |     |  
|Repayments of long-term borrowings                                                         |  |                                 | (1,762 | ) |      |   | (23  | )
|Debt conversion costs                                                                      |  |                                 | (204   | ) |      |   |     |  
|Repayments to affiliate, net                                                               |  |                                 | (120   | ) |      |   |     |  
|Dividends to affiliates                                                                    |  |                                 | (50    | ) |      |   |     |  
|Other financing, net                                                                       |  |                                 | (1     | ) |      |   | (13  | )
|                                                                                           |  |                                 |        |   |      |   |      |  
|Net cash used in financing activities                                                      |  |                                 | (1,066 | ) |      |   | (36  | )
|                                                                                           |  |                                 |        |   |      |   |      |  
|Net decrease in cash and cash equivalents                                                  |  |                                 | (1,064 | ) |      |   | (126 | )
|Cash and cash equivalents, beginning of period                                             |  |                                 | 1,301  |   |      |   | 245  |  
|Less: Cash classified as held for sale at end of period (Note 4)                           |  |                                 |       |   |      |   | (18  | )
|                                                                                           |  |                                 |        |   |      |   |      |  
|Cash and cash equivalents, end of period                                                   |  | $                               | 237    |   |      | $ | 101  |  
|                                                                                           |  |                                 |        |   |      |   |      |  

See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)



|                                                                                                          |  |                                  |     |   |      |   |     |  
|--------------------------------------------------------------------------------------------------------- |  | -------------------------------- | --- | - | ---- | - | --- | -
|                                                                                                          |  | Three Months Ended September 30, |    
|                                                                                                          |  | 2006                             |     |   | 2005 |  
|Net income (loss)                                                                                         |  | $                                | (66 | ) |      | $ | 78  |  
|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)                                                                               |  | $                                | (27 | ) |      | $ | 73  |  
|                                                                                                          |  |                                  |     |   |      |   |     |  



|                                                                                                           |  |                                 |      |   |      |   |     |  
|---------------------------------------------------------------------------------------------------------- |  | ------------------------------- | ---- | - | ---- | - | --- | -
|                                                                                                           |  | Nine Months Ended September 30, |     
|                                                                                                           |  | 2006                            |      |   | 2005 |  
|Net loss                                                                                                   |  | $                               | (224 | ) |      | $ | (53 | )
|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                                                                                         |  | $                               | (169 | ) |      | $ | (68 | )
|                                                                                                           |  |                                 |      |   |      |   |     |  

See the notes to condensed consolidated financial statements.



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##### Table of Contents

DYNEGY HOLDINGS 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.

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 HOLDINGS 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 by Dynegy after January 1, 2003 are accounted for on a
fair value basis. Options granted by Dynegy prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Accordingly, for options granted by Dynegy 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. Dynegy has granted in-the-money options in the past and we have recognized compensation expense over the applicable vesting periods.
No in-the-money stock options have been granted by Dynegy since 1999.

Had compensation cost for all stock options granted prior to 2003
been determined on a fair value basis consistent with SFAS No. 123(R), our net loss 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 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



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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 No. 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 HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 2Dynegy Inc. and LS Power Combination

On September 14, 2006, Dynegy 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 Dynegy, as a result of which we and Dynegy will become wholly-owned subsidiaries of New Dynegy.

Dynegy will combine their 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 Dynegys Class A Common Stock and 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, Dynegy 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 Dynegy and the LS Entities, and further
provides that, upon termination of the Merger Agreement under certain circumstances, (i) Dynegy may be required to pay the LS Entities or (ii) the LS Entities may be required to pay Dynegy, 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 Dynegys Class A Common Stock voting as a class, (ii) issued and outstanding shares of Dynegys Class B Common
Stock voting as a class and (iii) issued and outstanding shares of Dynegys 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 Dynegys 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 (Kendall) 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. Dynegy has 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



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

waiting periods under the HSR; and (iii) satisfaction of certain other conditions. Upon the completion of either the Merger Agreement or the Kendall Agreement, our transactions with Kendall will become affiliate
transactions.

Note 3Acquisition

Rocky Road. On March 31, 2006, contemporaneous with our sale of our interest in WCP (Generation) Holdings LLC (West Coast Power) (please read Note 4 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
7Unconsolidated InvestmentsVariable Interest Entities for further discussion.

Note 4Dispositions, Contract Terminations and
Discontinued Operations

Dispositions and Contract Terminations

Rockingham. On November 9, 2006, we completed our sale to Duke Energy Carolinas, LLC (a subsidiary of Duke Energy) (Duke
Power) of our Rockingham facility, a peaking facility in North Carolina, which is included in our GEN-SO reportable segment, for $195 million in cash. 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 8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 3Acquisition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



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

acquired. We did not recognize a material gain or loss on the sale. Pursuant to our divestiture of West 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 7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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DYNEGY HOLDINGS 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 our U.K. CRM business, which has 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      |    |   | NGL |   | Total
|                                           |  | (in millions)
|Three Months Ended September 30, 2006      |  |               |    |   |     |   |       |  |   |      
|Income from operations before taxes        |  | $             | 6  |   |     | $ | 2     |  | $ | 8    
|Income from operations after taxes         |  |               | 1  |   |     |   | 2     |  |   | 3    
|                                           |  |               |   
|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  |  |               | (3 | ) |     |   | 46    |  |   | 43   



|                                     |  |               |   |     |   |       |  |   |      
|------------------------------------ |  | ------------- | - | --- | - | ----- |  | - | -----
|                                     |  | U.K. CRM      |   | NGL |   | Total
|                                     |  | (in millions)
|Nine Months Ended September 30, 2006 |  |               |   |     |   |       |  |   |      
|Income from operations before taxes  |  | $             | 5 |     | $ | 3     |  | $ | 8    
|Income from operations after taxes   |  |               | 1 |     |   | 2     |  |   | 3    
|                                     |  |               |  
|Nine Months Ended September 30, 2005 |  |               |   |     |   |       |  |   |      
|Revenues                             |  | $             |  |     | $ | 3,172 |  | $ | 3,172
|Income from operations before taxes  |  |               | 3 |     |   | 152   |  |   | 155  
|Income from operations after taxes   |  |               |  |     |   | 131   |  |   | 131  

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 5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.

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



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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 |                                     | $ | 15 |       |  | $ | 18 |  
|Cash payments                 |  |               |  |                                     |   | (6 | )     |  |   | (6 | )
|                              |  |               |   |                                     |   |    |       |  |   |    |  
|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 4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 6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 5Risk Management Activities and Financial Instruments beginning on page F-23 of
our Form 10-K.

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.

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



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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 stockholders 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 HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 7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 |                  |   | 207
|                                 |  |                   |   |                  |   |    
|Total unconsolidated investments |  | $                 | 7 |                  | $ | 267
|                                 |  |                   |   |                  |   |    

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     |  | $            | 141 |  | $ | 60 
|Operating income |  |                                  | 6  |              |   | 3     |  |              | 28  |  |   | 14 
|Net income       |  |                                  | 6  |              |   | 3     |  |              | 30  |  |   | 14 
|                 | 
|                 |  | Nine Months Ended September 30, 
|                 |  | 2006                             |    | 2005        
|                 |  | Total                            |    | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)                   
|Revenues         |  | $                                | 42 |              | $ | 21    |  | $            | 461 |  | $ | 188
|Operating income |  |                                  | 10 |              |   | 5     |  |              | 50  |  |   | 21 
|Net income       |  |                                  | 10 |              |   | 5     |  |              | 55  |  |   | 23 

Earnings from unconsolidated investments for the three months ended September 30, 2006 were
$3 million. Earnings from unconsolidated investments of $14 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 were $6 million for the nine months ended September 30, 2006. Earnings from unconsolidated investments of $23 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 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 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.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

For further discussion, please read Note 3AcquisitionRocky Road and Note 4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 3 AcquisitionRocky Road and Note 4Dispositions, Contract Terminations and Discontinued
OperationsDispositions and Contract TerminationsWest Coast Power.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 8Debt

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



|                                                                                        |  |                   |       |   |                  |   |      
|--------------------------------------------------------------------------------------- |  | ----------------- | ----- | - | ---------------- | - | -----
|                                                                                        |  | September 30,2006 |       |   | December 31,2005
|                                                                                        |  | (in millions)    
|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  
|Note Payable to Dynegy, due 2006                                                        |  |                   |      |   |                  |   | 120  
|                                                                                        |  |                   |       |   |                  |   |      
|                                                                                        |  |                   | 2,936 |   |                  |   | 3,431
|Unamortized premium (discount) on debt, net                                             |  |                   | (7    | ) |                  |   | 5    
|                                                                                        |  |                   |       |   |                  |   |      
|                                                                                        |  |                   | 2,929 |   |                  |   | 3,436
|Less: Amounts due within one year, including non-cash amortization of basis adjustments |  |                   | 2     |   |                  |   | 149  
|                                                                                        |  |                   |       |   |                  |   |      
|Total Long-Term Debt                                                                    |  | $                 | 2,927 |   |                  | $ | 3,287
|                                                                                        |  |                   |       |   |                  |   |      

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: 2006-$2 million, 2007-zero, 2008-zero, 2009-zero, 2010-$11 million and thereafter-$2,916 million.

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 our assets, as borrower, and certain of our
subsidiaries, as subsidiary guarantors, and certain of Dynegys assets, as parent guarantor. The revolving



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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 us and certain of our subsidiaries of any permitted additional non-recourse indebtedness. Commencing in 2008 with respect to the fiscal year ending December 31, 2007, each year
we 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 our 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 our 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, we and our 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 us and certain of our 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 us and
certain of our 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 to Dynegy and the remainder used for working capital and general corporate purposes. 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 November 15, 2006, due to the completion of the sale of the Rockingham facility. Please read Note 4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 our obligations and the obligations of the guarantors of the Second Priority
Notes.



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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, we 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. 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, we 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.

Sithe Subordinated Debt Exchange. On July 21, 2006, we executed and consummated an exchange agreement (the Exchange
Agreement), by and among us 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, a subsidiary of Dynegy and our affiliate, 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 our 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, we exchanged the Additional 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.

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 our 8.375% Senior Unsecured Notes due 2016 registered under the Securities Act of 1933 for all $1,047 million aggregate principal amount of our outstanding 8.375% Senior Unsecured Notes due 2016.



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Note 9Related Party Transactions

We routinely engage in business transactions with
subsidiaries of Dynegy that are not part of our consolidated group. These transactions included among others, purchases of energy and capacity from Independence, as further discussed below. Please see Note 12Related Party
TransactionsOther beginning on page F-34 of our Form 10-K for further discussion.

Transactions with Independence.On
January 31, 2005, Dynegy completed the acquisition of ExRes. In exchange for $120 million, net of transaction costs and cash acquired, and the assumption of $919 million of face value project debt, Dynegy acquired the 1,021 MW Independence
power generation facility located near Scriba, New York, as well as four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. Independence holds a power tolling contract, financial swap and
other contracts with one of our subsidiaries. Upon completion of this acquisition, our transactions with Independence became related party transactions.

Our transactions with ExRes include purchases of energy and capacity under a tolling arrangement, sales of natural gas and payments associated with a financial derivative instrument. During the three months ended
September 30, 2006 and 2005, we incurred costs of $41 million and $98 million, respectively, under these contracts. Additionally, during the three months ended September 30, 2006 and 2005, we sold an aggregate of $42 million and $71
million, respectively, in natural gas to ExRes. During the nine months ended September 30, 2006 and the period from February 1, 2005 through September 30, 2005, we incurred costs of $97 million and $58 million, respectively, under
these contracts. Additionally, during the nine months ended September 30, 2006 and the period from February 1, 2005 through September 30, 2005, we sold an aggregate of $139 million and $152 million, respectively, in natural gas to
ExRes. The terms of these transactions are in accordance with the contractual agreements that were in place prior to Dynegys acquisition of ExRes. In addition to the contractual arrangements discussed above, we pay all employee and payroll
costs, as well as certain general and administrative costs, on behalf of ExRes, and they reimburse us for these costs. For the three months ended September 30, 2006 and 2005, we paid $1 million and $3 million, respectively, of such costs on
behalf of ExRes. For the nine months ended September 30, 2006 and the period from February 1, 2005 through September 30, 2005, we paid $3 million and $14 million, respectively, of such costs on behalf of ExRes. During the period ended
September 30, 2005, we received a payment of $6 million from ExRes in order to terminate their obligation to post collateral with us. As of September 30, 2006, we have a net outstanding affiliate receivable balance of $34 million from
ExRes.

On July 21, 2006, we executed and consummated an Exchange Agreement. Pursuant to the Exchange Agreement, the Reservoir
Entities exchanged approximately $419 million principal amount of the subordinated debt of Independence for approximately $297 million principal amount of our 8.375% Senior Unsecured Notes due 2016. Please read Note8DebtSithe
Subordinated Debt Exchange for further information.

Pending Acquisition of the Kendall Facility. Upon the completion of the
merger between Dynegy and the LS Entities, as described in Note 2Dynegy Inc. and LS Power Combination, or the completion of the Kendall facility acquisition, transactions with Kendall will become transactions with an affiliate.

Other. In the second quarter of 2006, we made a one time cash dividend to Dynegy of $50 million from the proceeds of the Term Loan. Please
read Note 8DebtSenior Secured Credit Facility for further discussion.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 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 1Accounting PoliciesContingencies, Commitments, Guarantees and Indemnifications beginning on page F-12 of our Form 10-K for further discussion of our reserve policies.
Environmental reserves do not reflect managements assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the
amount of any reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

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

Summary of Recent Developments. As described in greater detail below, the following significant developments involving our material legal
proceedings occurred since the 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. We 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 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



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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:



| |  | A settlement payment by us 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, we 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 and/or Dynegy 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



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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.

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/or Dynegy 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



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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 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 Dynegy, 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 settled by Dynegy in
December 2004, including claims that certain of Dynegys former officers (who are past members of its 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 Dynegys 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 of Dynegy as defendants and amending the fraud claims. In June 2006, the court granted Dynegys 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 Dynegy 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, Dynegy 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 Dynegy has 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



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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. 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.

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.



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Severance Arbitration. Dynegys 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 Dynegy maintains
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 Dynegys 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.

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. Dynegy continues 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 maintained by
Dynegy and its ERISA affiliates. Dynegy cooperated with the Department of Labor throughout this investigation, which focused on a review of plan documentation, plan reporting and disclosure, plan record keeping, plan investments and investment
options, plan fiduciaries and third party service providers, plan contributions and other operational aspects of the plans. In February 2005, Dynegy received a letter from the Department of Labor indicating that, as a result of Dynegys
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



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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.

WCP Indemnities. In connection with our sale to NRG of our 50% ownership
interest in West Coast Power (please read Note 4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.

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 and Indian Basin. 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 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.



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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
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



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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.

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 17Employee Compensation, Savings and Pension Plans beginning
on page F-52 of our Form 10-K.

Share-Based Compensation. Dynegys 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



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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Black-Scholes model, with the following weighted-average assumptions used for grants for the nine months ended September 30, 2006 and 2005:



|                                 |  |                                 |   |  |          |  
|-------------------------------- |  | ------------------------------- | - |  | -------- | -
|                                 |  | Nine Months Ended September 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 Dynegys
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 Dynegys 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.

Dynegy has seven stock option plans in which our past and present employees participate, all of which contain authorized shares of its 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 Dynegys 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 Dynegy granted options below the fair market value of its Class A common
stock on the date of grant. This plan had 20,358,802 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.
| | - | -------------------------------------------------------------------------------------------------------



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



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DYNEGY HOLDINGS INC.

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(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

All of Dynegys 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 Dynegys 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Dynegy Inc. and LS Power Combination 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, Dynegy entered into an exchange transaction with its Chairman and CEO, who also serves as our 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, Dynegy cancelled all of the 2,378,605 stock options then held by its Chairman and CEO. As consideration for canceling these stock options, Dynegy granted its
Chairman and CEO 967,707 stock options at an exercise price of $4.88, which equaled the closing price of its 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.

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



|                                                           |  |                       |   |  |                              |       |                                                   |      |                                      |   |    
|---------------------------------------------------------- |  | --------------------- | - |  | ---------------------------- | ----- | ------------------------------------------------- | ---- | ------------------------------------ | - | ---
|                                                           |  | Options(in thousands) |   |  | WeightedAverageExercisePrice |       | WeightedAverageRemainingContractualLife (inyears) |      | AggregateIntrinsicValue (inmillions)
|Outstanding at December 31, 2005                           |  | 9,122                 |   |  | $                            | 12.62 |                                                   |      |                                      |   |    
|Granted                                                    |  | 3,268                 |   |  | $                            | 4.88  |                                                   |      |                                      |   |    
|Exercised                                                  |  | (1,423                | ) |  | $                            | 3.46  |                                                   |      |                                      |   |    
|Forfeited or expired                                       |  | (2,824                | ) |  | $                            | 4.91  |                                                   |      |                                      |   |    
|                                                           |  |                       |   |  |                              |       |                                                   |      |                                      |   |    
|Outstanding at September 30, 2006                          |  | 8,143                 |   |  | $                            | 13.79 |                                                   | 6.23 |                                      | $ | 5.0
|                                                           |  |                       |   |  |                              |       |                                                   |      |                                      |   |    
|Vested and unvested expected to vest at September 30, 2006 |  | 7,448                 |   |  | $                            | 14.62 |                                                   | 5.8  |                                      | $ | 4.6
|Exercisable at September 30, 2006                          |  | 4,508                 |   |  | $                            | 21.03 |                                                   | 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.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

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



|                                |  |                                |   |  |                                     |     
|------------------------------- |  | ------------------------------ | - |  | ----------------------------------- | ----
|                                |  | Number of Shares(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Dynegy Inc. and LS Power
Combination 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.

Cash received from option exercises for the three
and nine months ended September 30, 2006 was $1 million 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                             |    |   | 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
|                                              |  |                                  |    |   |                |   |    |      |  |      |   |  |   |  



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005



|                                              |  |                                 |    |   |                |   |    |      |  |      |   |  |   |  
|--------------------------------------------- |  | ------------------------------- | -- | - | -------------- | - | -- | ---- |  | ---- | - |  | - | -
|                                              |  | 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 other postretirement benefit plans in the fourth quarter 2006.



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DYNEGY HOLDINGS 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 Ended September 30, |  
|                             |  | 2006                            |    |   | 2005                            |   |     | 2006 |  |   | 2005 |  
|                             |  | (in millions, except rates)     |   
|Income tax benefit (expense) |  | $                               | 41 |   |                                 | $ | (16 | )    |  | $ | 122  |   |  | $ | 96 |  
|Effective tax rate           |  |                                 | 37 | % |                                 |   | 31  | %    |  |   | 35   | % |  |   | 34 | %

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 infrequent transactions. Income taxes for significant unusual or infrequent transactions are computed and recorded in the period that the
specific transaction occurs. In general, differences between our effective tax 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-deductable portion of the charge associated with the shareholder litigation
settlement, offset 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 $1 million related to our
Texas operations. The effect of the change in Texas law produced a total charge of $1 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.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2006 and 2005

Our former natural gas liquids operations comprise the NGL segment and are included in discontinued operations. 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:

Segment Data for the Three Months Ended
September 30, 2006

(in millions)



|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|--------------------------------------------------- |  | ---------------- | ----- | - | ------ | - | --- | ------ |  | - | --- | - |  | --- | --- | --------------------- |  | - | ----- |  | - | ----- | - |  | - | ----- | -
|                                                    |  | Power Generation |       |   |        |   |     |        |  |   |     |   |  |    
|                                                    |  | GEN-MW           |       |   | GEN-NE |   |     | GEN-SO |  |   | CRM |   |  | NGL |     | Other andEliminations |  |   | Total | 
|Unaffiliated revenues:                              |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Domestic                                            |  | $                | 260   |   |        | $ | 109 |        |  | $ | 97  |   |  | $   | (18 | )                     |  | $ |      |  | $ |      |   |  | $ | 448   |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |    |   |  |     | 4   |                       |  |   |      |  |   |      |   |  |   | 4     |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|                                                    |  |                  | 260   |   |        |   | 109 |        |  |   | 97  |   |  |     | (14 | )                     |  |   |      |  |   |      |   |  |   | 452   |  
|Affiliate revenues                                  |  |                  |      |   |        |   |    |        |  |   |    |   |  |     | 13  |                       |  |   |      |  |   |      |   |  |   | 13    |  
|Intersegment revenues                               |  |                  |      |   |        |   |    |        |  |   |    |   |  |     |    |                       |  |   |      |  |   |      |   |  |   |      |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Total revenues                                      |  | $                | 260   |   |        | $ | 109 |        |  | $ | 97  |   |  | $   | (1  | )                     |  | $ |      |  | $ |      |   |  | $ | 465   |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Depreciation and amortization                       |  | $                | (43   | ) |        | $ | (3  | )      |  | $ | (4  | ) |  | $   |    |                       |  | $ |      |  | $ | (4    | ) |  | $ | (54   | )
|Impairment and other charges                        |  |                  | (96   | ) |        |   |    |        |  |   |    |   |  |     |    |                       |  |   |      |  |   |      |   |  |   | (96   | )
|Operating income (loss)                             |  | $                | (10   | ) |        | $ | 19  |        |  | $ | 8   |   |  | $   | (44 | )                     |  | $ |      |  | $ | (39   | ) |  | $ | (66   | )
|Earnings from unconsolidated investments            |  |                  |      |   |        |   |    |        |  |   | 4   |   |  |     |    |                       |  |   |      |  |   |      |   |  |   | 4     |  
|Other items, net                                    |  |                  | 1     |   |        |   |    |        |  |   |    |   |  |     | 2   |                       |  |   |      |  |   | 11    |   |  |   | 14    |  
|Interest expense and debt conversion costs          |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | (62   | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Loss from continuing operations before income taxes |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | (110  | )
|Income tax benefit                                  |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | 41    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Loss from continuing operations                     |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | (69   | )
|Income from discontinued operations, net of taxes   |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | 3     |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Net loss                                            |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  | $ | (66   | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Identifiable assets:                                |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Domestic                                            |  | $                | 4,764 |   |        | $ | 407 |        |  | $ | 702 |   |  | $   | 479 |                       |  | $ | 30    |  | $ | 1,008 |   |  | $ | 7,390 |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |    |   |  |     | 70  |                       |  |   |      |  |   |      |   |  |   | 70    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Total                                               |  | $                | 4,764 |   |        | $ | 407 |        |  | $ | 702 |   |  | $   | 549 |                       |  | $ | 30    |  | $ | 1,008 |   |  | $ | 7,460 |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Unconsolidated investments                          |  | $                |      |   |        | $ |    |        |  | $ | 7   |   |  | $   |    |                       |  | $ |      |  | $ |      |   |  | $ | 7     |  
|Capital expenditures                                |  | $                | (22   | ) |        | $ | (5  | )      |  | $ | (4  | ) |  | $   |    |                       |  | $ |      |  | $ | (2    | ) |  | $ | (33   | )



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DYNEGY HOLDINGS 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 |       |   |        |   |     |        |  |   |       |   |  |     |      
|                                                      |  | GEN-MW           |       |   | GEN-NE |   |     | GEN-SO |  |   | CRM   |   |  | NGL |       |   | Other andEliminations |   |       | Total | 
|Unaffiliated revenues:                                |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Domestic                                              |  | $                | 255   |   |        | $ | 220 |        |  | $ | 133   |   |  | $   | 30    |   |                       | $ |      |       |  | $ |      |   |  | $ | 638    |  
|Other                                                 |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | (83   | ) |                       |   |      |       |  |   |      |   |  |   | (83    | )
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|                                                      |  |                  | 255   |   |        |   | 220 |        |  |   | 133   |   |  |     | (53   | ) |                       |   |      |       |  |   |      |   |  |   | 555    |  
|Affiliate revenues                                    |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | 180   |   |                       |   |      |       |  |   |      |   |  |   | 180    |  
|Intersegment revenues                                 |  |                  |      |   |        |   |    |        |  |   | (4    | ) |  |     | 5     |   |                       |   |      |       |  |   | (1    | ) |  |   |       |  
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Total revenues                                        |  | $                | 255   |   |        | $ | 220 |        |  | $ | 129   |   |  | $   | 132   |   |                       | $ |      |       |  | $ | (1    | ) |  | $ | 735    |  
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Depreciation and amortization                         |  | $                | (40   | ) |        | $ | (3  | )      |  | $ | (7    | ) |  | $   |      |   |                       | $ |      |       |  | $ | (4    | ) |  | $ | (54    | )
|Operating income (loss)                               |  | $                | 55    |   |        | $ | 37  |        |  | $ | 12    |   |  | $   | 63    |   |                       | $ |      |       |  | $ | (38   | ) |  | $ | 129    |  
|Earnings (losses) from unconsolidated investments     |  |                  | 7     |   |        |   |    |        |  |   | (2    | ) |  |     |      |   |                       |   |      |       |  |   |      |   |  |   | 5      |  
|Other items, net                                      |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | (4    | ) |                       |   |      |       |  |   |      |   |  |   | (4     | )
|Interest expense                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | (79    | )
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Income from continuing operations before income taxes |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | 51     |  
|Income tax expense                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | (16    | )
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Income from continuing operations                     |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | 35     |  
|Income from discontinued operations, net of taxes     |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | 43     |  
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Net income                                            |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  | $ | 78     |  
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Identifiable assets:                                  |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Domestic                                              |  | $                | 5,165 |   |        | $ | 553 |        |  | $ | 1,040 |   |  | $   | 1,524 |   |                       | $ | 1,705 |       |  | $ | 1,184 |   |  | $ | 11,171 |  
|Other                                                 |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | 105   |   |                       |   |      |       |  |   |      |   |  |   | 105    |  
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Total                                                 |  | $                | 5,165 |   |        | $ | 553 |        |  | $ | 1,040 |   |  | $   | 1,629 |   |                       | $ | 1,705 |       |  | $ | 1,184 |   |  | $ | 11,276 |  
|                                                      |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Unconsolidated investments                            |  | $                | 65    |   |        | $ |    |        |  | $ | 221   |   |  | $   |      |   |                       | $ | 77    |       |  | $ |      |   |  | $ | 363    |  
|Capital expenditures                                  |  | $                | (17   | ) |        | $ | (4  | )      |  | $ | (1    | ) |  | $   |      |   |                       | $ | (16   | )     |  | $ | (1    | ) |  | $ | (39    | )



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DYNEGY HOLDINGS 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 |       |   |        |   |     |        |  |   |     |   |  |    
|                                                    |  | GEN-MW           |       |   | GEN-NE |   |     | GEN-SO |  |   | CRM |   |  | NGL |     | Other andEliminations |  |   | Total | 
|Unaffiliated revenues:                              |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Domestic                                            |  | $                | 744   |   |        | $ | 247 |        |  | $ | 276 |   |  | $   | 6   |                       |  | $ |      |  | $ |      |   |  | $ | 1,273 |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |    |   |  |     | 12  |                       |  |   |      |  |   |      |   |  |   | 12    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|                                                    |  |                  | 744   |   |        |   | 247 |        |  |   | 276 |   |  |     | 18  |                       |  |   |      |  |   |      |   |  |   | 1,285 |  
|Affiliate revenues                                  |  |                  |      |   |        |   |    |        |  |   |    |   |  |     | 78  |                       |  |   |      |  |   |      |   |  |   | 78    |  
|Intersegment revenues                               |  |                  |      |   |        |   | (3  | )      |  |   | 1   |   |  |     | 2   |                       |  |   |      |  |   |      |   |  |   |      |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Total revenues                                      |  | $                | 744   |   |        | $ | 244 |        |  | $ | 277 |   |  | $   | 98  |                       |  | $ |      |  | $ |      |   |  | $ | 1,363 |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Depreciation and amortization                       |  | $                | (126  | ) |        | $ | (8  | )      |  | $ | (16 | ) |  | $   |    |                       |  | $ |      |  | $ | (14   | ) |  | $ | (164  | )
|Impairment and other charges                        |  |                  | (96   | ) |        |   |    |        |  |   | (9  | ) |  |     |    |                       |  |   |      |  |   | (2    | ) |  |   | (107  | )
|                                                    |  |                  |       |   |        |   |    
|Operating income (loss)                             |  | $                | 159   |   |        | $ | 33  |        |  | $ | (15 | ) |  | $   | (22 | )                     |  | $ |      |  | $ | (119  | ) |  | $ | 36    |  
|Earnings from unconsolidated investments            |  |                  |      |   |        |   |    |        |  |   | 6   |   |  |     |    |                       |  |   |      |  |   |      |   |  |   | 6     |  
|Other items, net                                    |  |                  | 1     |   |        |   |    |        |  |   | 1   |   |  |     | 1   |                       |  |   |      |  |   | 34    |   |  |   | 37    |  
|Interest expense and debt conversion costs          |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | (428  | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Loss from continuing operations before income taxes |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | (349  | )
|Income tax benefit                                  |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | 122   |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Loss from continuing operations                     |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | (227  | )
|Income from discontinued operations, net of taxes   |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   | 3     |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Net loss                                            |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  | $ | (224  | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Identifiable assets:                                |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Domestic                                            |  | $                | 4,764 |   |        | $ | 407 |        |  | $ | 702 |   |  | $   | 479 |                       |  | $ | 30    |  | $ | 1,008 |   |  | $ | 7,390 |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |    |   |  |     | 70  |                       |  |   |      |  |   |      |   |  |   | 70    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Total                                               |  | $                | 4,764 |   |        | $ | 407 |        |  | $ | 702 |   |  | $   | 549 |                       |  | $ | 30    |  | $ | 1,008 |   |  | $ | 7,460 |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |     |   |  |     |     |                       |  |   |       |  |   |       |   |  |   |       |  
|Unconsolidated investments                          |  | $                |      |   |        | $ |    |        |  | $ | 7   |   |  | $   |    |                       |  | $ |      |  | $ |      |   |  | $ | 7     |  
|Capital expenditures                                |  | $                | (58   | ) |        | $ | (10 | )      |  | $ | (16 | ) |  | $   |    |                       |  | $ |      |  | $ | (6    | ) |  | $ | (90   | )



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DYNEGY HOLDINGS 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 |       |   |        |   |     |        |  |   |       |   |  |     |      
|                                                    |  | GEN-MW           |       |   | GEN-NE |   |     | GEN-SO |  |   | CRM   |   |  | NGL |       |   | Other andEliminations |   |       | Total | 
|Unaffiliated revenues:                              |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Domestic                                            |  | $                | 695   |   |        | $ | 415 |        |  | $ | 281   |   |  | $   | 49    |   |                       | $ |      |       |  | $ |      |   |  | $ | 1,440  |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | (163  | ) |                       |   |      |       |  |   |      |   |  |   | (163   | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|                                                    |  |                  | 695   |   |        |   | 415 |        |  |   | 281   |   |  |     | (114  | ) |                       |   |      |       |  |   |      |   |  |   | 1,277  |  
|Affiliate revenues                                  |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | 248   |   |                       |   |      |       |  |   |      |   |  |   | 248    |  
|Intersegment revenues                               |  |                  |      |   |        |   | 24  |        |  |   | (52   | ) |  |     | 29    |   |                       |   |      |       |  |   | (1    | ) |  |   |       |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Total revenues                                      |  | $                | 695   |   |        | $ | 439 |        |  | $ | 229   |   |  | $   | 163   |   |                       | $ |      |       |  | $ | (1    | ) |  | $ | 1,525  |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Depreciation and amortization                       |  | $                | (117  | ) |        | $ | (8  | )      |  | $ | (17   | ) |  | $   | (1    | ) |                       | $ |      |       |  | $ | (15   | ) |  | $ | (158   | )
|                                                    |  |                  |       |   |        |   |    
|Operating income (loss)                             |  | $                | 161   |   |        | $ | 39  |        |  | $ | (7    | ) |  | $   | 11    |   |                       | $ |      |       |  | $ | (261  | ) |  | $ | (57    | )
|Earnings from unconsolidated investments            |  |                  | 7     |   |        |   |    |        |  |   | 3     |   |  |     |      |   |                       |   |      |       |  |   |      |   |  |   | 10     |  
|Other items, net                                    |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | (4    | ) |                       |   |      |       |  |   |      |   |  |   | (4     | )
|Interest expense                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | (229   | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Loss from continuing operations before income taxes |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | (280   | )
|Income tax benefit                                  |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | 96     |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Loss from continuing operations                     |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | (184   | )
|Income from discontinued operations, net of taxes   |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   | 131    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Net loss                                            |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  | $ | (53    | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Identifiable assets:                                |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Domestic                                            |  | $                | 5,165 |   |        | $ | 553 |        |  | $ | 1,040 |   |  | $   | 1,524 |   |                       | $ | 1,705 |       |  | $ | 1,184 |   |  | $ | 11,171 |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |      |   |  |     | 105   |   |                       |   |      |       |  |   |      |   |  |   | 105    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Total                                               |  | $                | 5,165 |   |        | $ | 553 |        |  | $ | 1,040 |   |  | $   | 1,629 |   |                       | $ | 1,705 |       |  | $ | 1,184 |   |  | $ | 11,276 |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |       |   |  |     |       |   |                       |   |       |       |  |   |       |   |  |   |        |  
|Unconsolidated investments                          |  | $                | 65    |   |        | $ |    |        |  | $ | 221   |   |  | $   |      |   |                       | $ | 77    |       |  | $ |      |   |  | $ | 363    |  
|Capital expenditures                                |  | $                | (74   | ) |        | $ | (11 | )      |  | $ | (2    | ) |  | $   |      |   |                       | $ | (39   | )     |  | $ | (6    | ) |  | $ | (132   | )



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DYNEGY HOLDINGS 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.

On November 9, 2006, we completed the sale of our Rockingham facility, a peaking facility in North
Carolina, to Duke Power for $195 million in cash. 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
4Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsRockingham for further discussion of the sale and Note 8DebtSenior Secured Credit Facility for discussion of the Term
Loan.



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DYNEGY HOLDINGS 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.

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 arrangements 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

Dynegy Inc. and LS Power Combination. On September 14, 2006, Dynegy 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 Dynegys current assets, and for Dynegy 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 Dynegys 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 Dynegy 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Dynegy Inc. and LS Power Combination for further discussion of the terms of the Plan of Merger, Contribution and Sale Agreement.

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.



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The closing of the Kendall Agreement will occur only if closing does not occur with respect to the transactions
contemplated by the Merger Agreement. Dynegy has 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. Upon the completion of the merger between Dynegy and the LS Entities
or the completion of the Kendall facility acquisition, transactions with Kendall will become transactions with an affiliate. Please read Note 2Dynegy Inc. and LS Power Combination and Note 9Related Party TransactionsPending
Acquisition of the Kendall Facility for further discussion.

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.

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. We 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.

Rockingham Sale. On November 9, 2006, we completed the sale of our Rockingham peaking facility to Duke
Power for $195 million. Please read Note 4Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsRockingham for further discussion.

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



| |  |  | Redemption of Second Priority Notes Due 2008. On July 15, 2006, we redeemed all $74 million of our 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 8DebtSecond Priority Senior Secured Notes for further discussion of the redemption.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Sithe Subordinated Debt Exchange. On July 21, 2006, we issued $297 million principal amount of additional 8.375% Senior Unsecured Notes due 2016 in exchange for
all of Dynegys $419 million of outstanding Independence subordinated debt. Please read Note 8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 our 8.375% Senior
Unsecured Notes due 2016. Please read Note 8DebtSenior Unsecured Notes Exchange Offer for further discussion of the exchange offer.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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. 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 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. Additionally, we may borrow money from time to time from our parent.

Debt Obligations

During 2006, we continued our efforts to reduce our outstanding debt obligations and extend our maturity profile. Please read Note
8Debt for further discussion.



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Collateral Postings

We continue to use a significant portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands. These counterparty collateral demands reflect our
non-investment grade credit ratings and counterparties views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. The following table summarizes our consolidated
collateral postings to third parties by segment at November 3, 2006, September 30, 2006 and December 31, 2005:



|                         |  |                 |     |                   |   |                  |  |   |    
|------------------------ |  | --------------- | --- | ----------------- | - | ---------------- |  | - | ---
|                         |  | November 3,2006 |     | September 30,2006 |   | December 31,2005
|                         |  |                 |     | (in millions)     |   |                 
|By Business:             |  |                 |     |                   |   |                  |  |   |    
|Generation               |  | $               | 126 |                   | $ | 135              |  | $ | 263
|Customer risk management |  |                 | 63  |                   |   | 70               |  |   | 106
|Other                    |  |                 | 9   |                   |   | 10               |  |   | 12 
|                         |  |                 |     |                   |   |                  |  |   |    
|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 $128 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 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 4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 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 $272 million. These NOL carry-forwards will begin to expire in the year 2022. If substantial changes in Dynegys 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 Dynegy 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.



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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
4Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSterlington Contract Termination for further discussion.

Please also read Note 8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.

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. Additionally, we may borrow money from time to time from our parent.

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                                                                    |  |                 | 117  | (2)(3) |                   |   | 237  | (2)(3)           |  |   | 1,301 | (2)
|                                                                        |  |                 |      |        |                   |   |      |                  |  |   |       |    
|Total available liquidity                                               |  | $               | 612  |        |                   | $ | 713  |                  |  | $ | 1,367 |    
|                                                                        |  |                 |      |        |                   |   |      |                  |  |   |       |    

---

|(1) | In April 2006, we amended and restated the credit facility. Please read Note 8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 8Debt
for further discussion.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Cash Flows from Operations. We had operating cash outflows of $212 million for the
nine months ended September 30, 2006. This consisted of $520 million in operating cash inflows from our power generation business, offset by $407 million of cash outflows relating to our customer risk management business and $325 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.



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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 $117 million
and $237 million, respectively, as compared to $1,301 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 8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.

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 20Subsequent Events beginning on page F-62 of our Form 10-K 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 8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 3AcquisitionRocky Road for further discussion. Please read Note 4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 Dynegys ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of the consolidated enterprises
asset-based business, which is subject to cyclical changes in commodity prices, we and Dynegy 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



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strategic growth opportunities, legal judgments or regulatory requirements, which could require it to pursue additional
capital in the near-term. In particular, in connection with the pending transaction with the LS Entities, we and Dynegy will be evaluating various opportunities to provide additional liquidity and streamline the combined capital structure.

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 arrangements 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. 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 | )   |          | $ | 19                    |  | $ | 8     |  | $ | (44 | ) |  | $ | (39 | ) |  | $ | (66  | )
|Earnings from unconsolidated investments            |  |                  |    |     |          |   |                      |  |   | 4     |  |   |    |   |  |   |    |   |  |   | 4    |  
|Other items, net                                    |  |                  | 1   |     |          |   |                      |  |   |      |  |   | 2   |   |  |   | 11  |   |  |   | 14   |  
|Interest expense and debt conversion costs          |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   | (62  | )
|                                                    |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   |      |  
|Loss from continuing operations before income taxes |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   | (110 | )
|Income tax benefit                                  |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   | 41   |  
|                                                    |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   |      |  
|Loss from continuing operations                     |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   | (69  | )
|Income from discontinued operations, net of taxes   |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   | 3    |  
|                                                    |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   |      |  
|Net loss                                            |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  | $ | (66  | )
|                                                    |  |                  |     |     |          |   |                       |  |   |       |  |   |     |   |  |   |     |   |  |   |      |  



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Three Months Ended September 30, 2005



|                                                      |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   |     |  
|----------------------------------------------------- |  | ---------------- | -- | -------- | --- | ------ |  | --------------------- | -- | - | ----- | - | -- | - |  | - | --- | - |  | - | --- | -
|                                                      |  | Power Generation |    |          | CRM |        |  | Other andEliminations |    |   | Total |  
|                                                      |  | GEN-MW           |    | GEN - NE |     | GEN-SO |  |                       |    |  
|                                                      |  | (in millions)    |   
|Operating income (loss)                               |  | $                | 55 |          | $   | 37     |  | $                     | 12 |   |       | $ | 63 |   |  | $ | (38 | ) |  | $ | 129 |  
|Earnings (losses) from unconsolidated investments     |  |                  | 7  |          |     |       |  |                       | (2 | ) |       |   |   |   |  |   |    |   |  |   | 5   |  
|Other items, net                                      |  |                  |   |          |     |       |  |                       |   |   |       |   | (4 | ) |  |   |    |   |  |   | (4  | )
|Interest expense                                      |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   | (79 | )
|                                                      |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   |     |  
|Income from continuing operations before income taxes |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   | 51  |  
|Income tax expense                                    |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   | (16 | )
|                                                      |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   |     |  
|Income from continuing operations                     |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   | 35  |  
|Income from discontinued operations, net of taxes     |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   | 43  |  
|                                                      |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   |     |  
|Net income                                            |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  | $ | 78  |  
|                                                      |  |                  |    |          |     |        |  |                       |    |   |       |   |    |   |  |   |     |   |  |   |     |  

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



|                                                        |  |                                  |      |      |   |     
|------------------------------------------------------- |  | -------------------------------- | ---- | ---- | - | ----
|                                                        |  | Three Months Ended September 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          |  |                                  | .9   |      |   | 2.2 
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                  |      |      |   |     
|New York Zone G                                        |  | $                                | 84   |      | $ | 110 
|                                                        |  |                                 
|GEN-SO                                                  |  |                                  |      |      |   |     
|Million Megawatt Hours GeneratedGross                  |  |                                  | 1.2  |      |   | 1.6 
|Million Megawatt Hours GeneratedNet                    |  |                                  | 1.1  |      |   | 1.2 
|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  | )
|Legal and settlement charges |  |                                       |    |   |        |   |       |  |     |  |  |     | (22 | )     |  |       |   |  |   |  |  |   | (22  | )
|                             |  |                                       |     |   |        |   |        |  |     |   |  |     |     |       |  |       |    |  |   |   |  |   |      |  
|Total                        |  | $                                     | (96 | ) |        | $ |       |  | $   |  |  | $   | (22 | )     |  | $     |   |  | $ |  |  | $ | (118 | )
|                             |  |                                       |     |   |        |   |        |  |     |   |  |     |     |       |  |       |    |  |   |   |  |   |      |  
|                             | 
|                             |  | 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 | )     |  | $     |   |  | $ |  |  | $ | (29  | )
|Discontinued operations      |  |                                       |    |   |        |   |       |  |     |  |  |     | (2  | )     |  |       | 71 |  |   |  |  |   | 69   |  
|                             |  |                                       |     |   |        |   |        |  |     |   |  |     |     |       |  |       |    |  |   |   |  |   |      |  
|Total                        |  | $                                     |    |   |        | $ |       |  | $   |  |  | $   | (31 | )     |  | $     | 71 |  | $ |  |  | $ | 40   |  
|                             |  |                                       |     |   |        |   |        |  |     |   |  |     |     |       |  |       |    |  |   |   |  |   |      |  

Operating Income (Loss)

Operating loss was $66 million for the three months ended September 30, 2006, compared to operating income of $129 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 also 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 5Restructuring and Impairment ChargesAsset Impairment for further discussion.

Power Generation Northeast Segment. Operating income for GEN-NE was $19 million for the three months ended September 30, 2006,
compared to $37 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 $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 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.

Depreciation expense remained flat at $3 million for the three months ended September 30, 2006 and 2005, respectively.

Power Generation South Segment. Operating income for GEN-SO was $8 million for three months ended September 30, 2006, compared to income of $12 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 4Dispositions, Contract Terminations and Discontinued OperationsRockingham for further discussion.

CRM. Operating loss for the CRM segment was $44 million for the three months ended September 30, 2006, compared to operating income of $63 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. Additionally, we recognized $36 million of losses from our tolling and financial swap arrangements with Sithe Energies. The loss is driven primarily by the effect of gas and
power price volatility on the value of our financial swap instrument.



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In the third quarter of 2005, we recognized $82 million of income from our tolling and financial swap
arrangements with Sithe Energies. This income is driven primarily by the effect of gas and power price volatility on the value of our financial swap instrument. Additionally, in the third quarter of 2005, we recognized a $21 million gain related to
the termination of a contract to sell emissions allowances. However, these benefits were partly 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 income 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 $39 million for the three months ended September 30, 2006, compared to a loss of $38 million for the three months ended September 30, 2005. Results for third quarter 2006 include approximately $35 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 $34 million.

Consolidated general and administrative expenses decreased from $78 million for the three months
ended September 30, 2005 to $57 million for the three months ended September 30, 2006, primarily due to $29 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 $5 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 $14 million of income for the three months ended September 30, 2006,
compared to a loss of $4 million 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 to favorable foreign exchange rates.

Interest Expense

Interest expense and debt conversion costs totaled $62 million for the three months ended September 30, 2006, compared to $79 million for the three months ended September 30, 2005. The decrease is primarily due to lower principal
amounts outstanding as a result of our liability management program executed in the second quarter. Please read Note 8Debtfor further discussion.

Income Tax Benefit

We reported an income tax benefit from continuing operations of $41
million for the three months ended September 30, 2006, compared to an income tax expense from continuing operations of $16 million for the three months ended September 30, 2005. The 2006 effective tax rate was 37%, compared to 31% 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 was different than the statutory rate of 35% in 2005 due primarily to the nondeductible portion of the charge associated with the shareholder litigation settlement.



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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                                               |  |               |   |     |   |       |  |   | (5 | )
|                                                                 |  |               |   |     |   |       |  |   |    |  
|Income from discontinued operations                              |  |               |   |     |   |       |  | $ | 3  |  
|                                                                 |  |               |   |     |   |       |  |   |    |  

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
4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.

During the three months ended September 30, 2006, the pre-tax income from discontinued operations was $8 million ($3 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.



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Income Tax Expense From Discontinued Operations. We recorded an income tax expense from
discontinued operations of $5 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 63% 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 and Eliminations |     |   | Total |  
|                                                    |  | (in millions)    |    
|Operating income (loss)                             |  | $                | 159 |          | $ | 33     |  | $ | (15 | ) |  | $                      | (22 | ) |       | $ | (119 | ) |  | $ | 36   |  
|Earnings from unconsolidated investments            |  |                  |    |          |   |       |  |   | 6   |   |  |                        |    |   |       |   |     |   |  |   | 6    |  
|Other items, net                                    |  |                  | 1   |          |   |       |  |   | 1   |   |  |                        | 1   |   |       |   | 34   |   |  |   | 37   |  
|Interest expense and debt conversion costs          |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   | (428 | )
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   |      |  
|Loss from continuing operations before income taxes |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   | (349 | )
|Income tax benefit                                  |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   | 122  |  
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   |      |  
|Loss from continuing operations                     |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   | (227 | )
|Income from discontinued operations, net of taxes   |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   | 3    |  
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   |      |  
|Net loss                                            |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  | $ | (224 | )
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |     |   |       |   |      |   |  |   |      |  



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Nine Months Ended September 30, 2005



|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   |      |  
|--------------------------------------------------- |  | ---------------- | --- | -------- | - | ------ |  | - | --- | - |  | ---------------------- | -- | - | ----- | - | ---- | - |  | - | ---- | -
|                                                    |  | Power Generation |     |          |   |       
|                                                    |  | GEN-MW           |     | GEN - NE |   | GEN-SO |  |   | CRM |   |  | Other and Eliminations |    |   | Total |  
|                                                    |  | (in millions)    |    
|Operating income (loss)                             |  | $                | 161 |          | $ | 39     |  | $ | (7  | ) |  | $                      | 11 |   |       | $ | (261 | ) |  | $ | (57  | )
|Earnings from unconsolidated investments            |  |                  | 7   |          |   |       |  |   | 3   |   |  |                        |   |   |       |   |     |   |  |   | 10   |  
|Other items, net                                    |  |                  |    |          |   |       |  |   |    |   |  |                        | (4 | ) |       |   |     |   |  |   | (4   | )
|Interest expense                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   | (229 | )
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   |      |  
|Loss from continuing operations before income taxes |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   | (280 | )
|Income tax benefit                                  |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   | 96   |  
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   |      |  
|Loss from continuing operations                     |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   | (184 | )
|Income from discontinued operations, net of taxes   |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   | 131  |  
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   |      |  
|Net loss                                            |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  | $ | (53  | )
|                                                    |  |                  |     |          |   |        |  |   |     |   |  |                        |    |   |       |   |      |   |  |   |      |  

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



|                                                        |  |                                |      |      |   |     
|------------------------------------------------------- |  | ------------------------------ | ---- | ---- | - | ----
|                                                        |  | NineMonths Ended September 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          |  |                                | 2.2  |      |   | 4.6 
|Average Actual On-Peak Market Power Prices ($/MWh) (1): |  |                                |      |      |   |     
|New York Zone G                                        |  | $                              | 78   |      | $ | 86  
|                                                        |  |                               
|GEN-SO                                                  |  |                                |      |      |   |     
|Million Megawatt Hours GeneratedGross                  |  |                                | 3.5  |      |   | 5.1 
|Million Megawatt Hours GeneratedNet                    |  |                                | 3.0  |      |   | 3.8 
|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           |  | $                                    |    |   |        | $ |       |  | $ |    |   |  | $   |    |       |  | $ |      |  | $ | (204 | ) |  | $ | (204 | )
|Asset impairments               |  |                                      | (96 | ) |        |   |       |  |   | (9  | ) |  |     |    |       |  |   |      |  |   |     |   |  |   | (105 | )
|Legal and settlement charges    |  |                                      |    |   |        |   |       |  |   |    |   |  |     | (53 | )     |  |   |      |  |   |     |   |  |   | (53  | )
|Acceleration of financing costs |  |                                      |    |   |        |   |       |  |   |    |   |  |     |    |       |  |   |      |  |   | (34  | ) |  |   | (34  | )
|                                |  |                                      |     |   |        |   |        |  |   |     |   |  |     |     |       |  |   |       |  |   |      |   |  |   |      |  
|Total                           |  | $                                    | (96 | ) |        | $ |       |  | $ | (9  | ) |  | $   | (53 | )     |  | $ |      |  | $ | (238 | ) |  | $ | (396 | )
|                                |  |                                      |     |   |        |   |        |  |   |     |   |  |     |     |       |  |   |       |  |   |      |   |  |   |      |  
|                                | 
|                                |  | 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 | )     |  | $ |      |  | $ | (154 | ) |  | $ | (183 | )
|Discontinued operations         |  |                                      |    |   |        |   |       |  |   |    |   |  |     | 3   |       |  |   | 152   |  |   |     |   |  |   | 155  |  
|Taxes                           |  |                                      |    |   |        |   |       |  |   |    |   |  |     |    |       |  |   |      |  |   | 34   |   |  |   | 34   |  
|                                |  |                                      |     |   |        |   |        |  |   |     |   |  |     |     |       |  |   |       |  |   |      |   |  |   |      |  
|Total                           |  | $                                    |    |   |        | $ |       |  | $ |    |   |  | $   | (26 | )     |  | $ | 152   |  | $ | (120 | ) |  | $ | 6    |  
|                                |  |                                      |     |   |        |   |        |  |   |     |   |  |     |     |       |  |   |       |  |   |      |   |  |   |      |  

Operating Income (Loss)

Operating income was $36 million for the nine months ended September 30, 2006, compared to an operating loss of $57 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 $161 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 in the second quarter 2006, 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
5Restructuring and Impairment ChargesAsset Impairment for further discussion.

Power Generation Northeast
Segment. Operating income for GEN-NE was $33 million for the nine months ended September 30, 2006, compared to $39 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 $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 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 4.6 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.

Depreciation expense remained flat at $8 million for the nine months ended September 30, 2006 and 2005, respectively.

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 $7 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 the second quarter of 2006 added to these losses.

Results from our other South assets increased from $5 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 4Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsRockingham for
further discussion.

CRM. Operating loss for the CRM segment was $22 million for the nine months ended September 30,
2006, compared to operating income of $11 million for the nine months ended September 30, 2005.



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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. Additionally, we recognized $21 million of losses from our tolling and financial swap arrangements with Sithe Energies. The income is driven primarily by the effect of gas and power price volatility on the value
of our financial swap instrument.

Results for 2005 reflect net earnings of $67 million related to our tolling and swap arrangements with
Sithe Energies, driven primarily by the effect of gas and power price volatility on the value of our financial swap instrument, 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. These gains were offset by $59 million of fixed payments on our Sterlington and Gregory tolling arrangements in excess of realized margins on power generated and sold.
Additionally, 2005 results include a $29 million increase in 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.

Other. Other operating loss was $119 million for the nine months ended September 30,
2006, compared to a loss of $261 million for the nine months ended September 30, 2005. Results for the nine months ended September 30, 2006 include approximately $105 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 $247 million.

Consolidated general and administrative expenses decreased from $320 million for the nine months ended September 30, 2005 to $158 million for the
nine months ended September 30, 2006. General and administrative expenses for 2005 included a $154 million charge associated with settlement of our shareholder class action litigation and other legal settlement charges totaling $29 million,
while 2006 included $53 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 $10 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.

Other
Items, Net

Other items, net totaled $37 million of income for the nine months ended September 30, 2006, compared to $4 million
of expense 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 $428 million for the nine months ended September 30, 2006, compared to $229 million for the nine months ended September 30, 2005. The increase is primarily due to debt conversion and acceleration
of financing costs. These charges are partially offset by reductions due to lower principal amounts outstanding as a result of our liability management program. Please read Note 8Debt for further discussion.



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Income Tax Benefit

We reported an income tax benefit from continuing operations of $122 million for the nine months ended September 30, 2006, compared to an income tax
benefit from continuing operations of $96 million for the nine months ended September 30, 2005. The 2006 effective tax rate was 35%, compared to 34% 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  |  
|                                                                 |  |               |   |     |   |       |  |   |    |  

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 expense                                                                       |  |               |    |   |     |   |     |       |  |   | (24 | )
|                                                                                         |  |               |    |   |     |   |     |       |  |   |     |  
|Income from discontinued operations                                                      |  |               |    |   |     |   |     |       |  | $ | 131 |  
|                                                                                         |  |               |    |   |     |   |     |       |  |   |     |  

We completed the sale of DMSLP on October 31, 2005 as further discussed in Note
4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 ($131 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.



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Income Tax Expense 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 expense from discontinued operations of $24 million during the nine months ended September 30, 2005. The income tax expense in
2005 includes a $34 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 4 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, Dynegy 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. 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 Lyondell facility, 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 commodity markets. The only intermediate (combined cycle) assets in our current portfolio is the Lyondell natural gas-fired facility. The combination will result in a more balanced portfolio geographically and in terms of fuel type and
dispatch characteristics for Dynegy, and will result in the recharacterization of transactions with Kendall to affiliate transactions.

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



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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 focus on safe and efficient operations, 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.



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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 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.



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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                |  | $                              | 520  |   |      | $ | 343  |  
|Operating cash flows used in our customer risk management business |  |                                | (407 | ) |      |   | (56  | )
|Operating cash flows from our natural gas liquids business         |  |                                |     |   |      |   | 241  |  
|Other operating cash flows                                         |  |                                | (325 | ) |      |   | (691 | )
|                                                                   |  |                                |      |   |      |   |      |  
|Net cash used in operating activities                              |  | $                              | (212 | ) |      | $ | (163 | )
|                                                                   |  |                                |      |   |      |   |      |  

Operating Cash Flow. Our cash flow used in operations totaled $212 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 $520 million primarily due to positive earnings for the period. Our
customer risk management business used approximately $407 million in cash primarily due to a $370 million termination payment on our Sterlington tolling contract. Please read Note 4Dispositions, Contract Terminations and Discontinued
Operations Dispositions and Contract TerminationsSterlington Contract Termination for further information. Other and Eliminations includes a use of approximately $325 million in cash primarily due to interest payments to service debt and
general and administrative expenses, partially offset by interest income on cash balances.

Our cash flow used in operations totaled $163
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 $343 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 $56 million in cash primarily due to fixed payments associated with power tolling arrangements and our final
payment of $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 $691 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 $214 million. Capital spending of $90 million was primarily comprised of $58 million, $10 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 4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 3AcquisitionRocky Road for more information.

The decrease in restricted cash of $135 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.



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Cash provided by investing activities during the nine months ended September 30, 2005 totaled $73
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. Proceeds from asset sales primarily consisted of $10 million due to the sale of land at our former NGL segments Port Everglades facility.

Financing Activities. Cash used in financing activities during the nine months ended September 30, 2006 totaled $1,066 million. Repayments of long-term debt totaled $1,762 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
| | - |  | ---------------------------------------------------------------------------------

Debt conversion costs of $204 million consisted of the following payment:



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

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

Cash
used in financing activities includes $170 million in payments to Dynegy, which consists of repayments of borrowings of $120 million and a one time dividend payment of $50 million.

Cash used in financing activities during the nine months ended September 30, 2005 totaled $36 million. Repayments of long-term debt totaled $23
million for the nine months ended September 30, 2005 and consisted of the following: (i) payments of $18 million on a maturing series of our senior notes and (ii) payments of $5 million on our Term Loan.



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RISK-MANAGEMENT DISCLOSURES

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



|                                                                                 |  |                                                      |      |  
|-------------------------------------------------------------------------------- |  | ---------------------------------------------------- | ---- | -
|                                                                                 |  | As of and for theNine Months EndedSeptember 30, 2006 |     
|                                                                                 |  | (in millions)                                        |     
|Balance Sheet Risk-Management Accounts                                           |  |                                                      |      |  
|Fair value of portfolio at January 1, 2006                                       |  | $                                                    | (131 | )
|Risk-management gains recognized through the income statement in the period, net |  |                                                      | 11   |  
|Cash received related to risk-management contracts settled in the period, net    |  |                                                      | 11   |  
|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                                    |  | $                                                    | (13  | )
|                                                                                 |  |                                                      |      |  

---

|(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 $13 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.

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 (2) |   |     | 2007 |  |   | 2008 |   |  | 2009 |     |   | 2010 |   |    | Thereafter
|                    |  | (in millions)
|September 30, 2006  |  | $             | (68  | ) |          | $ | 1   |      |  | $ | (68  | ) |  | $    | (10 | ) |      | $ | (8 | )          |  | $ | (3 | ) |  | $ | 20
|December 31, 2005   |  |               | (103 | ) |          |   | (16 | )    |  |   | (73  | ) |  |      | (29 | ) |      |   | (2 | )          |  |   |   |   |  |   | 17
|                    |  |               |      |   |          |   |     |      |  |   |      |   |  |      |     |   |      |   |    |            |  |   |    |   |  |   |   
|Increase (decrease) |  | $             | 35   |   |          | $ | 17  |      |  | $ | 5    |   |  | $    | 19  |   |      | $ | (6 | )          |  | $ | (3 | ) |  | $ | 3 
|                    |  |               |      |   |          |   |     |      |  |   |      |   |  |      |     |   |      |   |    |            |  |   |    |   |  |   |   

---

|(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 $13 million on the unaudited condensed consolidated balance sheets include the $68
million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Amounts represent October 1 to December 31, 2006 values in the September 30, 2006 row and January 1 to December 31, 2006 values in the December 31,
2005 row.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------



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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) |  | $                                 | 28 |                                   | $ | 1         |  | $ | 29   |   |  | $    | (70 | ) |      | $ | (11 | )    |  | $ | (9         | ) |  | $ | (3 | ) |  | $ | 28
|December 31, 2005     |  |                                   |    |                                   |   |           |  |   | (10  | ) |  |      | (72 | ) |      |   | (33 | )    |  |   | (3         | ) |  |   |   |   |  |   | 24
|                      |  |                                   |    |                                   |   |           |  |   |      |   |  |      |     |   |      |   |     |      |  |   |            |   |  |   |    |   |  |   |   
|Increase (decrease)   |  |                                   |    |                                   |   |           |  | $ | 39   |   |  | $    | 2   |   |      | $ | 22  |      |  | $ | (6         | ) |  | $ | (3 | ) |  | $ | 4 
|                      |  |                                   |    |                                   |   |           |  |   |      |   |  |      |     |   |      |   |     |      |  |   |            |   |  |   |    |   |  |   |   

---

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

Net Fair Value of Risk-Management Portfolio



|                       |  |               |     |   |      |   |      |  |   |      |   |  |      |     |   |      |   |    |            |  |   |    |   |  |   |   
|---------------------- |  | ------------- | --- | - | ---- | - | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | -- | ---------- |  | - | -- | - |  | - | --
|                       |  | Total         |     |   | 2006 |   | 2007 |  |   | 2008 |   |  | 2009 |     |   | 2010 |   |    | Thereafter
|                       |  | (in millions)
|Market Quotations (1)  |  | $             | (81 | ) |      | $ | 1    |  | $ | (68  | ) |  | $    | (10 | ) |      | $ | (8 | )          |  | $ |   |   |  | $ | 4 
|Prices Based on Models |  |               | 13  |   |      |   |     |  |   |     |   |  |      |    |   |      |   |   |            |  |   | (3 | ) |  |   | 16
|                       |  |               |     |   |      |   |      |  |   |      |   |  |      |     |   |      |   |    |            |  |   |    |   |  |   |   
|Total                  |  | $             | (68 | ) |      | $ | 1    |  | $ | (68  | ) |  | $    | (10 | ) |      | $ | (8 | )          |  | $ | (3 | ) |  | $ | 20
|                       |  |               |     |   |      |   |      |  |   |      |   |  |      |     |   |      |   |    |            |  |   |    |   |  |   |   

---

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

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 of Dynegy with the LS Entities including satisfying closing conditions and obtaining shareholder and regulatory approvals;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | expected synergies resulting from the combination of Dynegy 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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | 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.

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 69 of our Form 10-K for a complete description of our critical accounting policies,
with respect to which there have been no material changes since the filing of our Form 10-K.



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Item 3QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A.
Quantitative and Qualitative Disclosures About Market Risk beginning on page 75 of our Form 10-K 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                             |  | $                 | 8  |                  | $ | 5 
|One Day VaR99% Confidence Level                             |  | $                 | 12 |                  | $ | 7 
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $                 | 11 |                  | $ | 11

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

We are not subject to the disclosure requirements promulgated under
Section 404 of the Sarbanes-Oxley Act of 2002 with respect to our internal control over financial reporting until we file our 2007 Form 10-K. Nevertheless, because we comprise a significant part of Dynegy as a consolidated enterprise, our
internal control over financial reporting has been reviewed in connection with Dynegys efforts to achieve compliance with Section 404 of the Sarbanes-Oxley Act.

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 and the management of Dynegy, including our Chief Executive Officer
and our Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprises 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 Dynegys disclosure committee in an effort to ensure that information required to be disclosed in the consolidated entitys 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 participation in Dynegys 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.



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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:

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. 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



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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.

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 20 of our 2005 Form 10-K, page 56
of our first quarter 2006 Form 10-Q and page 70 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 Dynegy with certain risks and uncertainties, and have imposed and will continue to impose on Dynegy and 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 Dynegys shareholders.

The consummation of the Merger Agreement with the LS Entities and
related transactions is subject to the approval of Dynegys shareholders and is conditioned upon Dynegys and the LS Entities receipt of various approvals, consents and clearances from various governmental and regulatory entities. We
cannot assure you that Dynegy 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, Dynegys and/or New Dynegys business, financial condition and results of operations and may cause Dynegy and/or the LS Entities to abandon the Merger Agreement and related transactions. In addition, the
Merger Agreement restricts Dynegy, without the LS Entities consent, from taking certain specified actions until the Merger Agreement is consummated or terminated. These restrictions may prevent Dynegy from pursuing otherwise attractive
business opportunities and effecting other beneficial transactions and changes to its business and operations prior to the consummation or termination of the Merger Agreement.

Dynegy 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 Dynegy expects 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, Dynegy has incurred and expect to continue to incur significant costs in connection with consummating the Merger Agreement and related
transactions. Dynegy also expects to incur, upon the consummation of the Merger Agreement and related transactions, costs in connection with integrating its 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 Dynegys 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, Dynegy will face significant challenges
in integrating, in a timely and efficient manner, its 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 Dynegys 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 Dynegys 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 Dynegy issues a material amount of its common stock in the future or certain of its shareholders sell a material amount of Dynegy common stock, we could be subject to an annual limitation on the utilization
of our net operating losses (NOLs) under Section 382 of the Internal Revenue Code.

If Dynegy 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. 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. The annual
limitation would not affect the expiration dates of our NOLs, which, under current law, begin to expire in 2022. The consummation of the Merger Agreement and related transactions with the LS Entities will increase the likelihood that previously
incurred NOLs will become subject to the limitations set forth in Section 382 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 $95 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, Dynegy did not maintain effective internal control over
financial reporting due to a material weakness in Dynegys processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. Managements assessment of the effectiveness of Dynegys
internal control over financial reporting as of December



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

Likewise, in connection with managements assessment of the effectiveness of our internal control over financial reporting as of September 30, 2006, Dynegy management concluded that, as of September 30, 2006, Dynegy did not
maintain effective internal control over financial reporting due to the same material weakness in Dynegys processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. Also in connection
with managements assessment as of September 30, 2006, Dynegys management concluded that, as of September 30, 2006, Dynegy 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 Dynegy did not maintain effective internal control over 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. 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 Dynegys 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 Dynegy is taking the steps necessary to remediate the material weakness relating to Dynegys 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
Dynegy is taking the steps necessary to remediate the material weakness related to the accuracy of Dynegys 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 expect Dynegy 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.



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Item 6EXHIBITS

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



|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|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).                                                                                                                                                                                                                             
|              | 
|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).                                                                                                                                                                                                                                           
|              | 
|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          |  | 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).                                                                 
|              | 
|10.4          |  | 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.                                                                                                                                                                                                                                                                                                                                         

---

|** | 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 HOLDINGS INC.

SIGNATURES

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



|                        |  |     |  |                                                                                                                               
|----------------------- |  | --- |  | ------------------------------------------------------------------------------------------------------------------------------
|                        |  |     |  | DYNEGY HOLDINGS INC.                                                                                                          
|                        |  |    
|Date: November 14, 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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