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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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



| | For the quarterly period ended September 30, 2003
| | -------------------------------------------------



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



| | For the transition period from  to
| | ----------------------------------



Commission file number: 1-15659



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DYNEGY INC.

(Exact name of registrant as specified in its charter)



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



1000 Louisiana,
Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)



(713) 507-6400

(Registrants telephone number, including area code)



---



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



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



Number of shares outstanding of each of the issuers
classes of common stock, as of the latest practicable date: Class A common stock, no par value per share, 280,100,523 shares outstanding as of November 5, 2003; Class B common stock, no par value per share, 96,891,014 shares outstanding as of
November 5, 2003.



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##### Table of Contents

DYNEGY INC.



TABLE OF CONTENTS



|                                                                                              | 
|--------------------------------------------------------------------------------------------- | 
|                                                                                              | 
|                                                                                              | 
|PART I. FINANCIAL INFORMATION                                                                 | 
|                                                                                              | 
|Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:                                          | 
|                                                                                              | 
|Condensed Consolidated Balance Sheets:                                                        | 
|                                                                                              | 
|September 30, 2003 and December 31, 2002                                                      | 
|                                                                                              | 
|Condensed Consolidated Statements of Operations:                                              | 
|                                                                                              | 
|For the three and nine months ended September 30, 2003 and 2002                               | 
|                                                                                              | 
|Condensed Consolidated Statements of Cash Flows:                                              | 
|                                                                                              | 
|For the nine months ended September 30, 2003 and 2002                                         | 
|                                                                                              | 
|Condensed Consolidated Statements of Comprehensive Income (Loss):                             | 
|                                                                                              | 
|For the three and nine months ended September 30, 2003 and 2002                               | 
|                                                                                              | 
|Notes to Condensed Consolidated Financial Statements                                          | 
|                                                                                              | 
|Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 
|                                                                                              | 
|Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                            | 
|                                                                                              | 
|Item 4. CONTROLS AND PROCEDURES                                                               | 
|                                                                                              | 
|PART II. OTHER INFORMATION                                                                    | 
|                                                                                              | 
|Item 1. LEGAL PROCEEDINGS                                                                     | 
|                                                                                              | 
|Item 6. EXHIBITS AND REPORTS ON FORM 8-K                                                      | 



Glossary of Key
Terms



|ARO           |  | Asset retirement obligation.                                                                                                                                                                                                                                             
|------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Bcf/d         |  | Billion cubic feet per day.                                                                                                                                                                                                                                              
|Cal ISO       |  | The California Independent System Operator.                                                                                                                                                                                                                              
|Cal PX        |  | The California Power Exchange.                                                                                                                                                                                                                                           
|CDWR          |  | California Department of Water Resources.                                                                                                                                                                                                                                
|CFTC          |  | Commodity Futures Trading Commission.                                                                                                                                                                                                                                    
|CMS Energy    |  | CMS Energy Corporation.                                                                                                                                                                                                                                                  
|CRM           |  | Our customer risk management business segment.                                                                                                                                                                                                                           
|Destec        |  | Dynegy Power Corp., formerly Destec Energy, Inc.                                                                                                                                                                                                                         
|DGC           |  | Dynegy Global Communications.                                                                                                                                                                                                                                            
|DGC-Asia      |  | Dynegy Global Communications-Asia, our former Asian communications business.                                                                                                                                                                                             
|DHI           |  | Dynegy Holdings Inc., our primary financing subsidiary.                                                                                                                                                                                                                  
|DMG           |  | Dynegy Midwest Generation, Inc.                                                                                                                                                                                                                                          
|DMS           |  | Dynegy Midstream Services.                                                                                                                                                                                                                                               
|DMT           |  | Dynegy Marketing and Trade.                                                                                                                                                                                                                                              
|DPM           |  | Dynegy Power Marketing Inc.                                                                                                                                                                                                                                              
|Dynegy        |  | Dynegy Inc.                                                                                                                                                                                                                                                              
|DynegyConnect |  | DynegyConnect, L.P.                                                                                                                                                                                                                                                      
|EBIT          |  | A non-GAAP measure of Earnings Before Interest and Taxes. As an indicator of our segment operating performance, EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flows from operations as determined in accordance with GAAP.
|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.                                                                                                                                                                                                         
|Exelon        |  | Exelon Corporation.                                                                                                                                                                                                                                                      



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|FASB              |  | Financial Accounting Standards Board.                                                                                                                                                                                                                                   
|----------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|FERC              |  | Federal Energy Regulatory Commission.                                                                                                                                                                                                                                   
|FIN               |  | FASB Interpretation.                                                                                                                                                                                                                                                    
|Form 10-K/A       |  | Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, 2002, filed on July 25, 2003.                                                                                                                                                         
|FPA               |  | Federal Power Act.                                                                                                                                                                                                                                                      
|GAAP              |  | Generally Accepted Accounting Principles.                                                                                                                                                                                                                               
|GEN               |  | Our power generation business segment.                                                                                                                                                                                                                                  
|ICC               |  | Illinois Commerce Commission.                                                                                                                                                                                                                                           
|Illinois Power    |  | Illinois Power Company.                                                                                                                                                                                                                                                 
|Illinova          |  | Illinova Corporation, a wholly owned subsidiary of Dynegy and the direct parent company of Illinois Power.                                                                                                                                                              
|Kroger            |  | The Kroger Co.                                                                                                                                                                                                                                                          
|MBbls/d           |  | Thousands of barrels per day.                                                                                                                                                                                                                                           
|MMBtu             |  | Millions of British thermal units.                                                                                                                                                                                                                                      
|MW                |  | Megawatts.                                                                                                                                                                                                                                                              
|NGL               |  | Our natural gas liquids business segment.                                                                                                                                                                                                                               
|Nicor Energy      |  | Nicor Energy L.L.C., a joint venture with Nicor Inc.                                                                                                                                                                                                                    
|Northern Natural  |  | Northern Natural Gas Company.                                                                                                                                                                                                                                           
|NOV               |  | Notice of Violation issued by the EPA.                                                                                                                                                                                                                                  
|NRG Energy        |  | NRG Energy, Inc.                                                                                                                                                                                                                                                        
|PUCT              |  | Public Utility Commission of Texas.                                                                                                                                                                                                                                     
|PUHCA             |  | The Public Utility Holding Company Act of 1935, as amended.                                                                                                                                                                                                             
|REG               |  | Our regulated energy delivery business segment.                                                                                                                                                                                                                         
|Rolling Hills     |  | Our Rolling Hills power generating facility.                                                                                                                                                                                                                            
|SEC               |  | U.S. Securities and Exchange Commission.                                                                                                                                                                                                                                
|Series B Exchange |  | The restructuring transaction consummated on August 11, 2003 pursuant to which a subsidiary of ChevronTexaco exchanged $1.5 billion in Series B Mandatorily Convertible Redeemable
Preferred Stock for $225 million in cash and $625 million in newly issued securities.
|SFAS              |  | Statement of Financial Accounting Standards.                                                                                                                                                                                                                            
|Southern Power    |  | Southern Power Company.                                                                                                                                                                                                                                                 
|VaR               |  | Value at Risk.                                                                                                                                                                                                                                                          
|Versado           |  | Versado Gas Processors, L.L.C.                                                                                                                                                                                                                                          
|WECC              |  | Western Electricity Coordinating Council.                                                                                                                                                                                                                               
|WEN               |  | Our former wholesale energy network business segment.                                                                                                                                                                                                                   
|West Coast Power  |  | West Coast Power, LLC, a joint venture equally owned by Dynegy and NRG Energy.                                                                                                                                                                                          



Additionally, the terms
Dynegy, we, us and our refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.





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DYNEGY INC.



CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)



|                                                                                                                                                                                                                                   |  | September 30,2003 |        |   | December 31,2002 |  
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------- | ------ | - | ---------------- | -
|ASSETS                                                                                                                                                                                                                             |  |                   |        |   |                  |  
|Current Assets                                                                                                                                                                                                                     |  |                   |        |   |                  |  
|Cash and cash equivalents                                                                                                                                                                                                          |  | $                 | 688    |   |                  | $
|Restricted cash                                                                                                                                                                                                                    |  |                   | 19     |   |                  |  
|Accounts receivable, net of allowance for doubtful accounts of $167 and $151, respectively                                                                                                                                         |  |                   | 1,029  |   |                  |  
|Accounts receivable, affiliates                                                                                                                                                                                                    |  |                   | 22     |   |                  |  
|Inventory                                                                                                                                                                                                                          |  |                   | 294    |   |                  |  
|Assets from risk-management activities                                                                                                                                                                                             |  |                   | 833    |   |                  |  
|Prepayments and other assets                                                                                                                                                                                                       |  |                   | 337    |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Total Current Assets                                                                                                                                                                                                               |  |                   | 3,222  |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Property, Plant and Equipment                                                                                                                                                                                                      |  |                   | 9,817  |   |                  |  
|Accumulated depreciation                                                                                                                                                                                                           |  |                   | (1,427 | ) |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Property, Plant and Equipment, Net                                                                                                                                                                                                 |  |                   | 8,390  |   |                  |  
|Other Assets                                                                                                                                                                                                                       |  |                   |        |   |                  |  
|Unconsolidated investments                                                                                                                                                                                                         |  |                   | 668    |   |                  |  
|Assets from risk-management activities                                                                                                                                                                                             |  |                   | 693    |   |                  |  
|Goodwill                                                                                                                                                                                                                           |  |                   | 396    |   |                  |  
|Other assets                                                                                                                                                                                                                       |  |                   | 472    |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Total Assets                                                                                                                                                                                                                       |  | $                 | 13,841 |   |                  | $
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                                                                               |  |                   |        |   |                  |  
|Current Liabilities                                                                                                                                                                                                                |  |                   |        |   |                  |  
|Accounts payable                                                                                                                                                                                                                   |  | $                 | 564    |   |                  | $
|Accounts payable, affiliates                                                                                                                                                                                                       |  |                   | 71     |   |                  |  
|Accrued liabilities and other                                                                                                                                                                                                      |  |                   | 850    |   |                  |  
|Liabilities from risk-management activities                                                                                                                                                                                        |  |                   | 818    |   |                  |  
|Notes payable and current portion of long-term debt                                                                                                                                                                                |  |                   | 325    |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Total Current Liabilities                                                                                                                                                                                                          |  |                   | 2,628  |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Long-Term Debt                                                                                                                                                                                                                     |  |                   | 5,987  |   |                  |  
|Other Liabilities                                                                                                                                                                                                                  |  |                   |        |   |                  |  
|Liabilities from risk-management activities                                                                                                                                                                                        |  |                   | 817    |   |                  |  
|Deferred income taxes                                                                                                                                                                                                              |  |                   | 797    |   |                  |  
|Other long-term liabilities                                                                                                                                                                                                        |  |                   | 718    |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Total Liabilities                                                                                                                                                                                                                  |  |                   | 10,947 |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Minority Interest                                                                                                                                                                                                                  |  |                   | 124    |   |                  |  
|Commitments and Contingencies (Note 9)                                                                                                                                                                                             |  |                   |        |   |                  |  
|Redeemable Preferred Securities, redemption value of $411 and $1,711 at September 30, 2003 and December 31, 2002,
respectively                                                                                                     |  |                   | 411    |   |                  |  
|Stockholders Equity                                                                                                                                                                                                               |  |                   |        |   |                  |  
|Class A Common Stock, no par value, 900,000,000 shares authorized at September 30, 2003 and December 31, 2002, 279,817,574 and
274,850,589 shares issued and outstanding at September 30, 2003 and December 31, 2002, respectively |  |                   | 2,846  |   |                  |  
|Class B Common Stock, no par value, 360,000,000 shares authorized at September 30, 2003 and December 31, 2002, 96,891,014 shares
issued and outstanding at September 30, 2003 and December 31, 2002                                |  |                   | 1,006  |   |                  |  
|Additional paid-in capital                                                                                                                                                                                                         |  |                   | 39     |   |                  |  
|Subscriptions receivable                                                                                                                                                                                                           |  |                   | (10    | ) |                  |  
|Accumulated other comprehensive loss, net of tax                                                                                                                                                                                   |  |                   | (20    | ) |                  |  
|Accumulated deficit                                                                                                                                                                                                                |  |                   | (1,434 | ) |                  |  
|Treasury stock, at cost, 1,679,183 shares at September 30, 2003 and December 31, 2002                                                                                                                                              |  |                   | (68    | ) |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Total Stockholders Equity                                                                                                                                                                                                         |  |                   | 2,359  |   |                  |  
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  
|Total Liabilities and Stockholders Equity                                                                                                                                                                                         |  | $                 | 13,841 |   |                  | $
|                                                                                                                                                                                                                                   |  |                   |        |   |                  |  



See the notes to
condensed consolidated financial statements.



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DYNEGY INC.



CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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



|                                                                            |  | Three Months EndedSeptember 30, |        |   | Nine Months EndedSeptember 30, |  
|--------------------------------------------------------------------------- |  | ------------------------------- | ------ | - | ------------------------------ | -
|                                                                            |  | 2003                            |        |   | 2002                           |  
|Revenues (Note 1)                                                           |  | $                               | 1,385  |   |                                | $
|Cost of sales, exclusive of depreciation shown separately below (Note 1)    |  |                                 | (1,091 | ) |                                |  
|Depreciation and amortization expense                                       |  |                                 | (109   | ) |                                |  
|Goodwill impairment (Note 3)                                                |  |                                 |       |   |                                |  
|Impairment and other charges                                                |  |                                 | (1     | ) |                                |  
|Gain on sale of assets                                                      |  |                                 |       |   |                                |  
|General and administrative expenses                                         |  |                                 | (83    | ) |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Operating income (loss)                                                     |  |                                 | 101    |   |                                |  
|Earnings (losses) from unconsolidated investments                           |  |                                 | 51     |   |                                |  
|Interest expense                                                            |  |                                 | (145   | ) |                                |  
|Other income and expense, net                                               |  |                                 | 2      |   |                                |  
|Minority interest income (expense)                                          |  |                                 | (2     | ) |                                |  
|Accumulated distributions associated with trust preferred securities        |  |                                 |       |   |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Income (loss) from continuing operations before income taxes                |  |                                 | 7      |   |                                |  
|Income tax benefit (provision)                                              |  |                                 | (3     | ) |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Income (loss) from continuing operations                                    |  |                                 | 4      |   |                                |  
|Income (loss) on discontinued operations, net of taxes (Note 2)             |  |                                 | 1      |   |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Income (loss) before cumulative effect of change in accounting principles   |  |                                 | 5      |   |                                |  
|Cumulative effect of change in accounting principles, net of taxes (Note 1) |  |                                 |       |   |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Net income (loss)                                                           |  |                                 | 5      |   |                                |  
|Less: preferred stock dividends (gain) (Note 7)                             |  |                                 | (1,183 | ) |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Net income (loss) applicable to common stockholders                         |  | $                               | 1,188  |   |                                | $
|                                                                            |  |                                 |        |   |                                |  
|Earnings (Loss) Per Share (Note 8):                                         |  |                                 |        |   |                                |  
|Basic earnings (loss) per share:                                            |  |                                 |        |   |                                |  
|Earnings (loss) from continuing operations                                  |  | $                               | 3.17   |   |                                | $
|Loss from discontinued operations                                           |  |                                 |       |   |                                |  
|Cumulative effect of change in accounting principles                        |  |                                 |       |   |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Basic earnings (loss) per share                                             |  | $                               | 3.17   |   |                                | $
|                                                                            |  |                                 |        |   |                                |  
|Diluted earnings (loss) per share:                                          |  |                                 |        |   |                                |  
|Earnings (loss) from continuing operations                                  |  | $                               | 2.65   |   |                                | $
|Loss from discontinued operations                                           |  |                                 |       |   |                                |  
|Cumulative effect of change in accounting principles                        |  |                                 |       |   |                                |  
|                                                                            |  |                                 |        |   |                                |  
|Diluted earnings (loss) per share                                           |  | $                               | 2.65   |   |                                | $
|                                                                            |  |                                 |        |   |                                |  
|Basic shares outstanding                                                    |  |                                 | 375    |   |                                |  
|Diluted shares outstanding                                                  |  |                                 | 464    |   |                                |  



See the notes to
condensed consolidated financial statements.



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DYNEGY INC.



CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



|                                                                                 |  | Nine Months Ended September 30, |       
|-------------------------------------------------------------------------------- |  | ------------------------------- | ------
|                                                                                 |  | 2003                            |       
|CASH FLOWS FROM OPERATING ACTIVITIES:                                            |  |                                 |       
|Net loss                                                                         |  | $                               | (138  
|Adjustments to reconcile net income to net cash flows from operating activities: |  |                                 |       
|Depreciation and amortization                                                    |  |                                 | 399   
|Goodwill impairment (Note 3)                                                     |  |                                 |      
|Impairment and other charges                                                     |  |                                 |      
|(Earnings) losses from unconsolidated investments, net of cash distributions     |  |                                 | (26   
|Risk-management activities                                                       |  |                                 | 378   
|Loss (gain) on sale of assets                                                    |  |                                 | (45   
|Deferred income taxes                                                            |  |                                 | (119  
|Cumulative effect of change in accounting principles (Note 1)                    |  |                                 | (55   
|Other                                                                            |  |                                 | 33    
|Changes in working capital:                                                      |  |                                 |       
|Accounts receivable                                                              |  |                                 | 1,704 
|Inventory                                                                        |  |                                 | 78    
|Prepayments and other assets                                                     |  |                                 | 817   
|Accounts payable and accrued liabilities                                         |  |                                 | (2,043
|Changes in non-current assets and liabilities, net                               |  |                                 | (49   
|                                                                                 |  |                                 |       
|Net cash provided by operating activities                                        |  |                                 | 934   
|                                                                                 |  |                                 |       
|CASH FLOWS FROM INVESTING ACTIVITIES:                                            |  |                                 |       
|Capital expenditures                                                             |  |                                 | (259  
|Investments in unconsolidated affiliates                                         |  |                                 |      
|Business acquisitions, net of cash acquired                                      |  |                                 |      
|Proceeds from asset sales, net                                                   |  |                                 | 57    
|Other investing, net                                                             |  |                                 |      
|                                                                                 |  |                                 |       
|Net cash provided by (used in) investing activities                              |  |                                 | (202  
|                                                                                 |  |                                 |       
|CASH FLOWS FROM FINANCING ACTIVITIES:                                            |  |                                 |       
|Net proceeds from long-term borrowings                                           |  |                                 | 1,909 
|Net proceeds from short-term borrowings                                          |  |                                 |      
|Repayments of borrowings                                                         |  |                                 | (2,352
|Net cash flow from commercial paper and revolving lines of credit                |  |                                 | (128  
|Payment to ChevronTexaco for Series B preferred stock restructuring              |  |                                 | (225  
|Proceeds from issuance of capital stock                                          |  |                                 | 6     
|Purchase of serial preferred securities of a subsidiary                          |  |                                 |      
|Purchase of treasury stock                                                       |  |                                 |      
|Dividends and other distributions, net                                           |  |                                 |      
|Increase in restricted cash                                                      |  |                                 | (2    
|Other financing, net                                                             |  |                                 | (16   
|                                                                                 |  |                                 |       
|Net cash provided by (used in) financing activities                              |  |                                 | (808  
|                                                                                 |  |                                 |       
|Effect of exchange rate changes on cash                                          |  |                                 | 7     
|Net increase (decrease) in cash and cash equivalents                             |  |                                 | (69   
|Cash and cash equivalents, beginning of period                                   |  |                                 | 757   
|                                                                                 |  |                                 |       
|Cash and cash equivalents, end of period                                         |  | $                               | 688   
|                                                                                 |  |                                 |       



See the notes to
condensed consolidated financial statements.



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DYNEGY INC.



CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)



|                                                                    |  | Three Months Ended September 30, |     
|------------------------------------------------------------------- |  | -------------------------------- | ----
|                                                                    |  | 2003                             |     
|Net income (loss)                                                   |  | $                                | 5   
|Cash flow hedging activities, net:                                  |  |                                  |     
|Unrealized mark-to-market gains (losses) arising during period, net |  |                                  | 7   
|Reclassification of mark-to-market (gains) losses to earnings, net  |  |                                  | (8  
|                                                                    |  |                                  |     
|Changes in cash flow hedging activities, net                        |  |                                  | (1  
|Foreign currency translation adjustments                            |  |                                  | (9  
|Unrealized holding losses on securities arising during period       |  |                                  |    
|                                                                    |  |                                  |     
|Other comprehensive income (loss), net of tax                       |  |                                  | (10 
|                                                                    |  |                                  |     
|Comprehensive loss                                                  |  | $                                | (5  
|                                                                    |  |                                  |     
|                                                                    | 
|                                                                    |  | Nine Months Ended September 30,  |     
|                                                                    |  | 2003                             |     
|Net loss                                                            |  | $                                | (138
|Cash flow hedging activities, net:                                  |  |                                  |     
|Unrealized mark-to-market gains (losses) arising during period, net |  |                                  | 52  
|Reclassification of mark-to-market (gains) losses to earnings, net  |  |                                  | (29 
|                                                                    |  |                                  |     
|Changes in cash flow hedging activities, net                        |  |                                  | 23  
|Foreign currency translation adjustments                            |  |                                  | 12  
|Unrealized holding gains on securities arising during period        |  |                                  |    
|                                                                    |  |                                  |     
|Other comprehensive income, net of tax                              |  |                                  | 35  
|                                                                    |  |                                  |     
|Comprehensive loss                                                  |  | $                                | (103
|                                                                    |  |                                  |     



See the notes to
condensed consolidated financial statements.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS



(Unaudited)



For the
Interim Periods Ended September 30, 2003 and 2002



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. These interim financial statements should be read together with the consolidated financial
statements and notes thereto included in our Form 10-K/A.



The
unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Interim period results
are not necessarily indicative of the results for the full year. The preparation of the condensed consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to
develop estimates and make assumptions that affect reported financial position and results of operations and that impact the nature and extent of disclosure, if any, of contingent assets and liabilities. We review significant estimates affecting our
consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time
such judgments and estimates are made. Adjustments made with respect to the use of these estimates often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of
financial statements. Estimates are primarily used in (1) developing fair value assumptions, including estimates of future cash flows and discount rates, (2) analyzing tangible and intangible assets for impairment, (3) estimating the useful lives of
our assets, (4) assessing future tax exposure and the realization of tax assets, (5) determining the amounts to accrue related to contingencies and (6) estimating various factors that impact the valuation of our pension assets. 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, primarily related to discontinued operations, our new segment presentation and the
application of EITF Issue 02-03, Issues involved in Accounting for Derivatives Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.



Accounting Principles Adopted



EITF Issue 02-03. In 2002, the EITF reached consensus on two
issues presented in EITF Issue 02-03. First, the EITF concluded that all mark-to-market gains and losses on energy trading contracts (whether realized or unrealized) should be shown net in the income statement, irrespective of whether the contract
is physically or financially settled. In the third quarter 2002, we began presenting all mark-to-market gains and losses on a net basis to reflect this change in accounting principle.



Second, in October 2002, the EITF reached a consensus to rescind EITF Issue 98-10, Accounting for Contracts Involved
in Energy Trading and Risk Management Activities, which previously required us to use mark-to-market accounting for our energy trading contracts. While the rescission of EITF Issue 98-10 will reduce the number of contracts accounted for on a
mark-to-market basis, it does not eliminate mark-to-market accounting. All derivative contracts that either do not qualify, or are not designated, as hedges or as normal purchases or sales, as defined by SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, will continue to be marked-to-market in accordance with SFAS No. 133. Any earnings/losses previously recognized under EITF Issue 98-10 that would not have been recognized under SFAS No. 133 were reversed in
the first quarter 2003 pursuant to the adoption provisions of EITF Issue 02-03. The cumulative effect of this change in accounting principle resulted in after-tax earnings of $21 million in the first quarter 2003 and was comprised of the following
items, which are no longer required to be recorded using mark-to-market accounting (in millions):



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



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

---

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



SFAS No. 143. In June 2001, the
FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. We adopted SFAS No. 143 effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible,
long-lived assets. Under SFAS No. 143, the ARO is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its fair value
and the capitalized costs are depreciated over the useful life of the related asset. The cumulative effect of applying SFAS No. 143 has been recognized as a change in accounting principle in the unaudited condensed consolidated statements of
operations.



As part of the transition adjustment in adopting
SFAS No. 143, existing environmental liabilities in the amount of $73 million were reversed in the first quarter 2003. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the ARO
and was recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities exceeded the fair value of the future retirement obligations, the impact of adopting SFAS No. 143 was an increase in earnings, net of tax, of approximately $34
million in the first quarter 2003, which is reflected as a cumulative effect of a change in accounting principle in the unaudited condensed consolidated financial statements. The annual amortization of the assets resulting from adoption of this
standard and the accretion of the liability to its fair value is estimated to be approximately $6 million in 2003. In addition to these liabilities, we also have potential retirement obligations for the dismantlement of power generation facilities,
power transmission assets, a fractionation facility and natural gas storage facilities. It is our current intent to maintain these facilities in a manner such that the facilities will be operational indefinitely. As such, we cannot estimate any
potential retirement obligations associated with these assets. At the time we are able to estimate any new AROs, liabilities will be recorded in accordance with SFAS No. 143.



At January 1, 2003, our ARO liabilities were $26 million for our GEN segment, $9 million for our NGL segment and $6 million
for our REG segment. These retirement obligations related to activities such as ash pond and landfill capping, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. During the three-
and nine-month periods ended September 30, 2003, accretion expense recognized for the fair value for all of our ARO liabilities totaled approximately $1 million and $4 million, respectively. There were no additional AROs recorded or settled, nor
were there any revisions to estimated cash flows associated with existing AROs, during the three- and nine-month periods ended September 30, 2003. At September 30, 2003, our ARO liability totaled $45 million.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Had SFAS No. 143 been applied retroactively in the three- and nine-month periods ended September 30,
2002, our net loss applicable to common stockholders would have been $1,736 million and $2,712 million, respectively. Basic and diluted loss per share for the three- and nine-month periods ended September 30, 2002 would have been $4.72 and $7.43,
respectively. Please see Note 8 Earnings (Loss) Per Share for a discussion of diluted earnings (loss) per share calculations.



SFAS No. 146. In July 2002, the FASB issued SFAS No. 146, Accounting for Exit or Disposal Activities. SFAS No. 146 addresses
issues regarding the recognition, measurement and reporting of costs that are associated with exit and disposal activities, including restructuring activities that were previously accounted for pursuant to the guidance in EITF Issue 94-3,
Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 is effective for exit or disposal activities that are initiated after
December 31, 2002. The adoption of SFAS No. 146 did not have any impact on our financial statements.



SFAS No. 148. In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based CompensationTransition and
Disclosure. SFAS No. 148 amends SFAS No. 123 and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based
employee compensation in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entitys accounting policy decisions with respect to stock-based employee
compensation. We transitioned to a fair value-based method of accounting for stock-based compensation in the first quarter 2003 and are using the prospective method of transition as described under SFAS No. 148. As a result, a charge of
approximately $1 million will be reflected in general and administrative expenses for the year ended December 31, 2003.



Under the prospective method of transition, all stock options granted since January 1, 2003 will be accounted for on a fair value basis. Options granted
prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Had compensation cost for stock options issued prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income (loss) and basic
and diluted earnings (loss) per share amounts would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2003 and 2002, respectively.



|                                                                                                                                            |  | Three Months Ended September 30,     |      |   | Nine Months Ended September 30, |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------------------ | ---- | - | ------------------------------- | -
|                                                                                                                                            |  | 2003                                 |      |   | 2002                            |  
|                                                                                                                                            |  | (in millions, except per share data) |     
|Net income (loss) as reported                                                                                                               |  | $                                    | 5    |   |                                 | $
|Add: Stock-based employee compensation expense included in reported net loss, net of related tax effects                                    |  |                                      |     |   |                                 |  
|Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related
tax effects |  |                                      | (13  | ) |                                 |  
|                                                                                                                                            |  |                                      |      |   |                                 |  
|Pro forma net loss                                                                                                                          |  | $                                    | (8   | ) |                                 | $
|                                                                                                                                            |  |                                      |      |   |                                 |  
|Earnings (loss) per share:                                                                                                                  |  |                                      |      |   |                                 |  
|Basicas reported                                                                                                                           |  | $                                    | 3.17 |   |                                 | $
|Basicpro forma                                                                                                                             |  | $                                    | 3.14 |   |                                 | $
|Dilutedas reported                                                                                                                         |  | $                                    | 2.65 |   |                                 | $
|Dilutedpro forma                                                                                                                           |  | $                                    | 2.62 |   |                                 | $



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Please see Note 8Earnings (Loss) Per Share for a discussion of our third quarter 2003 earnings
per share calculation.



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



SFAS No. 150. In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity. SFAS No. 150 establishes how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Instruments which have an unconditional obligation requiring the issuer
to redeem the instrument by transferring an asset at a specified date are required to be classified as liabilities on the balance sheet. Instruments which require the issuance of a variable number of equity shares by the issuer generally do not have
the risks associated with equity instruments and as such should also be classified as liabilities on the balance sheet. SFAS No. 150 is effective for contracts in existence or created or modified for the first interim period beginning after June 15,
2003. Upon adoption, we reclassified approximately $200 million of Company Obligated Preferred Securities, previously recorded in the mezzanine section of our balance sheet between liabilities and stockholders equity, to long-term liabilities.
Accordingly, the interest related to this instrument is recorded as interest expense beginning July 1, 2003. Previously, the preferred return on this instrument was reported in Accumulated distributions associated with trust preferred securities in
the unaudited condensed consolidated statements of operations. Further, the $400 million in Series C convertible preferred stock issued to ChevronTexaco in August 2003 in connection with the Series B Exchange is classified within the mezzanine
section of our balance sheet due to the $5.78 per share substantive conversion option, which renders the mandatory redemption feature conditional contingent upon the holder not exercising their conversion option. Please read Note
6DebtChevronTexaco Series B Preferred Stock Restructuring for further discussion.



FIN No. 45. In November 2002, the FASB issued FIN No. 45, Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. As
required by FIN No. 45, we adopted the disclosure requirements on December 31, 2002. On January 1, 2003, we adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. The adoption of the
recognition and measurement provisions did not have any impact on our financial statements.



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



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Cumulative Effect of Change in Accounting Principles



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



We adopted SFAS No. 142, Goodwill and Other Intangible Assets, effective January 1, 2002, and, accordingly, tested for impairment all amounts recorded as goodwill. We determined that goodwill associated
with our communications business was impaired and recognized a charge of $234 million for this impairment in the first quarter 2002. The fair value of this reporting segment was estimated using expected discounted future cash flows. The value was
negatively impacted by continued weakness in the communications and broadband markets. The first quarter 2002 impairment charge is reflected in the unaudited condensed consolidated statements of operations as a cumulative effect of change in
accounting principle. There were no changes in the carrying amount of goodwill for any of our reporting units for the three- and nine-month periods ended September 30, 2003.



Accounting Principles Not Yet Adopted



FIN No. 46. In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest
Entitiesan Interpretation of ARB No. 51. In summary, this interpretation increases the level of risk that must be assumed by equity investors in variable interest entities. FIN No. 46 requires that the equity investor have significant
equity at risk (a minimum of 10 percent with few exceptions, which is an increase from the 3 percent required under previous guidance) and hold a controlling interest, evidenced by voting rights, risk of loss and the benefit of residual returns. If
the equity investor is unable to evidence these characteristics, the entity that retains these ownership characteristics will be required to consolidate the variable interest entity. While we have not entered into any arrangements in 2003 that would
be subject to FIN No. 46, we are analyzing the structures of entities previously formed to determine whether we have any arrangements that are impacted. FIN No. 46 was applicable immediately to variable interest entities created or obtained after
January 31, 2003. For variable interest entities created or obtained before February 1, 2003, FIN No. 46 was applicable as of July 1, 2003. In October 2003, the FASB deferred the implementation date of FIN No. 46 until the fourth quarter 2003. The
adoption of FIN No. 46 could have a significant impact on our financial statements and will be reflected as a cumulative effect of change in accounting principle in the fourth quarter 2003.



Note 2Dispositions, Contract Terminations and Discontinued Operations



Dispositions and Contract Terminations



Pending Sale of Illinois Power.
Please see Note 13Subsequent Event, for a discussion of our pending sale of substantially all of the assets and liabilities of Illinois Power.



SouthStar Energy Services. During the first quarter 2003, we completed the sale of our 20 percent
equity investment in SouthStar Energy Services LLC. We received cash proceeds of approximately $20 million and recognized an after-tax gain on the sale of approximately $0.8 million. The gain is included in gain on sale of assets in the unaudited
condensed consolidated statements of operations.



Hackberry LNG Project. During the first quarter 2003, we entered into an agreement to sell our interest in Hackberry LNG Terminal LLC, the entity we formed in connection with our proposed LNG terminal/gasification
project in Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction closed in April 2003. At closing, we received an initial payment of $20 million and recognized a pre-tax gain of approximately $12
million in the second quarter 2003 in relation to this sale. We have the right to receive additional contingent payments based upon project development milestones. In October 2003, we received a $15



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



million payment associated with the completion of a project milestone and will recognize a pre-tax gain of $15
million in the fourth quarter 2003.



Southern Power
Tolling Arrangements. In April 2003, we reached an agreement in principle with Southern Power to terminate three power tolling arrangements among Dynegy, Southern Power and our respective affiliates covering an aggregate of 1,100 MW.
Under the terms of the agreement, we paid Southern Power $155 million to terminate these arrangements. The terminations resulted in $89 million of net collateral being returned to us and eliminated our obligation to make $1.7 billion in capacity
payments to Southern Power over the next 30 years. The transaction closed in May 2003, and we recognized an after-tax loss of approximately $84 million.



Kroger Company Settlement. In July 2003, we reached a settlement with Kroger related to four power supply contracts. Under the terms
of the settlement agreement, which was approved by the FERC on July 23, 2003, Kroger paid us approximately $110 million to terminate two of the four power contracts and to restructure at current market prices the remaining two contracts through
which we provide electricity to Kroger subsidiary stores in California. As part of the settlement, we also resolved an outstanding FERC dispute related to contract pricing.



The four contracts were derivatives under SFAS No. 133 and were carried at their fair value on the condensed consolidated
balance sheets, with changes in fair value recognized in earnings. Our net risk management asset related to these contracts was approximately $140 million at June 30, 2003. Therefore, the $30 million difference between the settlement of $110 million
and the carrying value of the net risk management asset was recorded as a charge in the second quarter 2003. The remaining two contracts were carried at fair value with changes in fair value recognized in earnings through August 2003, when such
contracts were terminated. The cash payment was received from Kroger in the third quarter 2003.



Discontinued Operations



During 2002, we sold our ownership interests in each of Northern Natural, our United Kingdom natural gas storage business, our global liquids business and
DGC-Asia. The historical results from these operations are included in discontinued operations for the nine-month period ended September 30, 2002. In addition, as part of our restructuring plan, we sold or liquidated portions of our operations
during the nine-month period ended September 30, 2003, some of which have been accounted for as discontinued operations under SFAS No. 144, as further discussed below.



Global Communications. During January 2003, we disposed of Dynegy Europe Communications to an affiliate
of Klesch & Company, a London-based private equity firm. We recognized an after-tax gain on the sale of approximately $19 million in the first quarter 2003. During May 2003, we disposed of our U.S. communications network to an affiliate of
360networks Corporation. During the second quarter 2003, we recognized an after-tax gain on the sale of approximately $2 million, the closing of which completed our exit from the communications business. Approximately $12 million of undiscounted
obligations with respect to this business remain following these sales.



U.K. CRM. During the first quarter 2003, the wind-down efforts of the U.K. CRM business were substantially completed. During the nine-month period ending September 30, 2003, we recognized an after-tax loss of $13 million
resulting primarily from selling and terminating all U.K. gas and power positions, offset by administrative expenses, depreciation and amortization, shut-down costs and currency translation losses. In connection with the wind-down, collateral
postings totaling $98 million were eliminated. We do not expect the U.K. CRM business to have a material impact on our results in the future.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



The following table summarizes information related to our discontinued operations:



|                                               |  | NorthernNatural |      |   | U.K.Storage |   | U.K.CRM |  |   | GlobalLiquids |   |  | DGC |     |   | Total |  
|---------------------------------------------- |  | --------------- | ---- | - | ----------- | - | ------- |  | - | ------------- | - |  | --- | --- | - | ----- | -
|                                               |  | (in millions)   |     
|Three Months Ended September 30, 2003          |  |                 |      |   |             |   |         |  |   |               |   |  |     |     |   |       |  
|Revenue                                        |  | $               |     |   |             | $ |        |  | $ |              |   |  | $   |    |   |       | $
|Loss from operations before taxes              |  |                 |     |   |             |   |        |  |   | (7            | ) |  |     | (2  | ) |       |  
|Loss from operations after taxes               |  |                 |     |   |             |   |        |  |   | (4            | ) |  |     | (1  | ) |       |  
|Gain on sale before taxes                      |  |                 |     |   |             |   | 1       |  |   |              |   |  |     |    |   |       |  
|Gain on sale after taxes                       |  |                 |     |   |             |   | 1       |  |   |              |   |  |     |    |   |       |  
|Three Months Ended September 30, 2002          |  |                 |      |   |             |   |         |  |   |               |   |  |     |     |   |       |  
|Revenue                                        |  | $               | 30   |   |             | $ | 47      |  | $ |              |   |  | $   | 175 |   |       | $
|Income (loss) from operations before taxes (1) |  |                 |     |   |             |   | 17      |  |   | (51           | ) |  |     | (3  | ) |       |  
|Income (loss) from operations after taxes      |  |                 |     |   |             |   | 11      |  |   | (32           | ) |  |     | (2  | ) |       |  
|Loss on sale before taxes                      |  |                 | (586 | ) |             |   |        |  |   |              |   |  |     |    |   |       |  
|Loss on sale after taxes                       |  |                 | (566 | ) |             |   |        |  |   |              |   |  |     |    |   |       |  
|                                               |  |                 |      |   |             |  
|                                               |  | NorthernNatural |      |   | U.K.Storage |   | U.K.CRM |  |   | GlobalLiquids |   |  | DGC |     |   | Total |  
|                                               |  | (in millions)   |     
|Nine Months Ended September 30, 2003           |  |                 |      |   |             |   |         |  |   |               |   |  |     |     |   |       |  
|Revenue                                        |  | $               |     |   |             | $ |        |  | $ | 21            |   |  | $   |    |   |       | $
|Loss from operations before taxes              |  |                 |     |   |             |   |        |  |   | (18           | ) |  |     | (3  | ) |       |  
|Loss from operations after taxes               |  |                 |     |   |             |   |        |  |   | (13           | ) |  |     | (2  | ) |       |  
|Gain on sale before taxes                      |  |                 |     |   |             |   | 1       |  |   |              |   |  |     |    |   |       |  
|Gain on sale after taxes                       |  |                 |     |   |             |   | 1       |  |   |              |   |  |     |    |   |       |  
|Nine Months Ended September 30, 2002           |  |                 |      |   |             |   |         |  |   |               |   |  |     |     |   |       |  
|Revenue                                        |  | $               | 207  |   |             | $ | 132     |  | $ | 12            |   |  | $   | 571 |   |       | $
|Income (loss) from operations before taxes (1) |  |                 | 37   |   |             |   | 37      |  |   | (60           | ) |  |     | (8  | ) |       |  
|Income (loss) from operations after taxes      |  |                 | 22   |   |             |   | 24      |  |   | (40           | ) |  |     | (5  | ) |       |  
|Loss on sale before taxes                      |  |                 | (586 | ) |             |   |        |  |   |              |   |  |     |    |   |       |  
|Loss on sale after taxes                       |  |                 | (566 | ) |             |   |        |  |   |              |   |  |     |    |   |       |  

---

|(1) | During the second quarter 2002, we reviewed DGCs long-lived assets for impairment in accordance with SFAS No. 144 and determined that future cash flows from DGCs
operations were insufficient to cover the carrying value of its long-lived assets. As a result, a pre-tax impairment charge totaling $611 million was recorded in Impairment and Other Charges, and subsequently reclassified to discontinued operations.
In addition, during the first quarter 2002 and third quarter 2002, $20 million and $4 million, respectively, of impairment charges were recorded related to our discontinued communications business.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Note 3Restructuring and Other Charges



In the first quarter 2002, we recorded pre-tax charges of $65 million ($42
million after-tax) primarily related to our investment in the communications business.



During the second quarter 2002, we recognized a $683 million pre-tax ($444 million after-tax) charge principally related to the impairment, write-off or obsolescence of certain assets and an accrual for severance
related to a corporate restructuring. The charge primarily relates to the impairment of our investment in the communications



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##### Table of Contents

DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



business, the impairment of investments in securities of entities engaged in technology-related ventures and a
severance charge related to the restructuring plan of our operations.



During the third quarter 2002, we recognized a $1,693 million pre-tax ($1,600 million after-tax) charge principally related to the impairment of goodwill associated with our GEN and CRM segments, a loss on the sale of Northern Natural, an
impairment of investments in generating facilities and the write-off of other obsolete assets.



The pre-tax charges consisted of the following for the periods ended September 30, 2002:



|                                      |  | Three MonthsEndedSeptember 30,2002 |       | Nine MonthsEndedSeptember 30,2002
|------------------------------------- |  | ---------------------------------- | ----- | ---------------------------------
|                                      |  | (in millions)                     
|Goodwill impairment                   |  | $                                  | 897   |                                  
|Loss on sale of Northern Natural      |  |                                    | 586   |                                  
|Impairment of communications business |  |                                    | 4     |                                  
|Impairment of generation investments  |  |                                    | 144   |                                  
|Impairment of technology investments  |  |                                    | 12    |                                  
|Severance charge                      |  |                                    |      |                                  
|Enron settlement                      |  |                                    | 25    |                                  
|Write-off of other obsolete assets    |  |                                    | 25    |                                  
|                                      |  |                                    |       |                                  
|Total                                 |  | $                                  | 1,693 |                                  
|                                      |  |                                    |       |                                  



Goodwill
Impairment. The value of goodwill associated with the GEN and CRM segments was reviewed for impairment at September 30, 2002. Based on this assessment, an after-tax charge of $897 million was recorded to impair substantially all of the
goodwill associated with the GEN and CRM segments. The fair value of GEN and CRM consists of value associated with the power generation business as well as the value associated with the marketing and trading business. The fair values of the
respective components were estimated utilizing the expected discounted future cash flows. The primary factors leading to this impairment were: (1) the reduction in near-term power prices, (2) an increase in the rate of return required for investors
to enter the energy merchant sector and (3) our decision to exit third party risk management aspects of the marketing and trading business. The charge was recorded in Goodwill impairment in the condensed consolidated statements of operations.



Loss on Sale of Northern Natural. On August 16,
2002, we sold Northern Natural to MidAmerican for $879 million in cash, net of working capital adjustments. MidAmerican acquired all of the common and preferred stock of Northern Natural and assumed all of Northern Naturals $950 million of
debt. We incurred a pre-tax loss of $586 million ($566 million after-tax) in the third quarter 2002 associated with the sale. This charge is recorded in Discontinued operations in the condensed consolidated statements of operations.



For federal income tax purposes, the sale resulted in a capital loss, which
may be deducted solely against capital gains, if any, realized by the enterprise in its consolidated federal tax returns. There is a five-year carryforward for capital losses under existing federal statutes. For financial reporting purposes, we
recorded a valuation allowance against a portion of the potential tax benefit as a result of uncertainty as to the ability to generate capital gains in the future.



Impairment of Communications Business. As discussed in Note 2Dispositions, Contract Terminations and
Discontinued Operations, for the nine-month period ended September 30, 2002, a cumulative pre-tax



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



impairment charge totaling $635 million ($414 million after-tax) was recorded in Impairment and other charges, and
subsequently reclassified to Discontinued operations.



Impairment of Generation Investments. During the third quarter 2002, in conjunction with our review of the carrying value of goodwill, we assessed the carrying value of our generation portfolio on an asset-by-asset basis. The
generation portfolio includes wholly-owned generating facilities, which are reflected in Property, plant and equipment, as well as investments in partnerships and limited liability companies that own generating facilities, which are reflected in
Unconsolidated investments. Based on this review, the carrying value associated with the wholly-owned generation facilities was considered realizable. However, certain investments in partnerships and limited liability companies were considered
impaired, resulting in a pre-tax charge of $144 million ($94 million after-tax) in the third quarter 2002, which is reflected in Earnings (losses) from unconsolidated investments in the unaudited condensed consolidated statements of operations. The
diminution in the fair value of these investments is primarily a result of depressed power prices.



Impairment of Technology Investments. During the second quarter 2002, we recognized an impairment charge associated with certain technology
investments. The $23 million pre-tax ($15 million after-tax) charge was recorded in Earnings (losses) from unconsolidated investments and $4 million of the charge ($3 million after-tax) was subsequently reclassified to Discontinued operations. This
is in addition to the first quarter 2002 pre-tax charge of $45 million ($30 million after-tax) resulting from unfavorable market conditions, which was recorded in Earnings (losses) from unconsolidated investments and subsequently reclassified to
Discontinued operations.



These investments were reevaluated at
September 30, 2002 based on our inability to sell certain investments for their adjusted carrying values and the continued depressed conditions in the technology sector. Based on this assessment, the remaining carrying value of such investments was
written-off, resulting in a pre-tax charges of $12 million ($8 million after-tax), which was recorded in Earnings (losses) from unconsolidated investments. The cumulative pre-tax charge related to technology investments for the nine months ended
September 30, 2002 was $80 million ($53 million after-tax), of which $49 million was subsequently reclassified to Discontinued operations.



During the third quarter 2003, we recognized an additional impairment charge of approximately $3 million related to investments made in late 2001 in
conjunction with our communications business investment strategy.



Restructuring Charges. During the second quarter 2002, we recognized a $37 million pre-tax ($24 million after-tax) charge for severance benefits in connection with a reduction in force affecting approximately 325 employees. In
October 2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business. As part of this restructuring, which included a further reduction in force affecting approximately 780
employees, we recognized a pre-tax charge of $182 million during the fourth quarter 2002.



The following is a schedule of 2003 activity for the liabilities recorded in connection with these charges:



|                              |  | Severance     |     |   | CancellationFees andOperatingLeases |   |     | Total | 
|----------------------------- |  | ------------- | --- | - | ----------------------------------- | - | --- | ----- | 
|                              |  | (in millions) |    
|Balance at December 31, 2002  |  | $             | 71  |   |                                     | $ | 61  |       | 
|2003 adjustments to liability |  |               | (8  | ) |                                     |   | 4   |       | 
|Cash payments                 |  |               | (40 | ) |                                     |   | (32 | )     | 
|                              |  |               |     |   |                                     |   |     |       | 
|Balance at September 30, 2003 |  | $             | 23  |   |                                     | $ | 33  |       | 
|                              |  |               |     |   |                                     |   |     |       | 



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



The adjustment to the accrued liability during the first nine months of 2003 primarily reflects
reductions in the severance accrual provided for employees that will now be retained, as well as for individuals in our foreign operations. In addition, we adjusted the liability for operating leases to reflect revised estimates of potential income
from subleasing the leased facilities.



Enron
Settlement. In August 2002, we agreed to pay Enron $25 million to settle the lawsuit Enron had filed alleging wrongful termination of our November 2001 merger agreement, $10 million of which was paid to Enron upon approval of the settlement
agreement by the Bankruptcy Court, with the remaining $15 million released from escrow and paid to Enron in May 2003 when the settlement was finalized. This pre-tax $25 million ($16 million after-tax) charge was recorded during the third quarter
2002 in Other income (expense) in the unaudited condensed consolidated statements of operations. Please see Note 9Commitments and Contingencies for further discussion.



Write-off of Other Obsolete Assets. During the second quarter 2002, we recorded a pre-tax charge of $12
million ($8 million after-tax) related to the retirement of partially depreciated information technology equipment and software and miscellaneous deposits that are not expected to provide future value. The equipment and software was replaced during
the second quarter 2002 with new system applications and arrangements. The charge was recorded in Impairment and other charges, and $1 million of the charge ($1 million after-tax) was subsequently reclassified to Discontinued operations.



As a result of our decision to exit third party risk management aspects of
the marketing and trading business, our investment in Dynegydirect was written off in the third quarter 2002, resulting in a pre-tax charge of $25 million ($16 million after-tax). The charge was recorded in Impairment and other charges in the
condensed consolidated statements of operations.



Note 4Commercial
Operations, Risk Management Activities and Financial Instruments



The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in an attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more
fully described in Note 5 to our Form 10-K/A beginning on page F-36.



From time to time, we enter into various financial derivative instruments that qualify as cash flow hedges. Instruments related to our power generation and natural gas liquids businesses are entered into for purposes of hedging future fuel
requirements and power sales commitments for power generation and fractionation facilities and locking in future margin in the domestic natural gas liquids and power generation businesses. In addition, prior to exiting the global liquids business,
we utilized these instruments to hedge price risks associated with that business. Interest rate swaps are also used to convert the floating interest-rate component of some obligations to fixed rates.



During the three- and nine-month periods ended September 30, 2003 and 2002,
there was no material ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three- and nine-month periods ended
September 30, 2003, we recorded a $4 million charge related to the reclassification of earnings in connection with forecasted transactions that were no longer considered probable of occurring. During the three- and nine-month periods ended September
30, 2002, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.



The balance in cash flow hedging activities, net at September 30, 2003 is expected to be reclassified to future earnings, contemporaneously with the
related purchases of fuel, sales of electricity or natural gas liquids and payments of interest, as applicable to each type of hedge. Of this amount, after-tax gains of approximately $18



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



million are currently estimated to be reclassified into earnings over the twelve-month period ending September 30,
2004. The actual amounts that will be reclassified to earnings over the next year and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.



From time to time, we also enter into derivative instruments that qualify as
fair-value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into variable-rate debt. During the three- and nine-month periods ended September 30, 2003 and 2002, 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-month periods ended September 30, 2003, we recorded a $6 million gain related to firm commitments that no longer
qualified as fair-value hedge items. During the three- and nine-month periods ended September 30, 2002, no amounts were recognized in relation to firm commitments that no longer qualified as fair-value hedge items.



We have investments in foreign subsidiaries, the net assets of which are
exposed to currency exchange-rate volatility. We have used derivative financial instruments, including foreign exchange forward contracts and cross-currency interest rate swaps, to hedge this exposure. As of September 30, 2003, we had no net
investment hedges in place. For the nine months ended September 30, 2002, approximately $61 million of net losses related to these contracts were included in the foreign currency translation adjustment. This amount offsets the cumulative translation
gains of the underlying net investments in foreign subsidiaries for the period the derivative financial instruments were outstanding.



During the nine months ended September 30, 2003, our efforts to exit the U.K. CRM business and the European communications business were substantially
completed. As required by SFAS No. 52, Foreign Currency Translation, unrealized gains and losses resulting from translation and financial instruments utilized to hedge currency exposures previously recorded in stockholders equity
were recognized in income, resulting in an after-tax loss of approximately $10 million.



Accumulated other comprehensive loss, net of tax, is included in stockholders equity on the unaudited condensed consolidated balance sheets as follows:



|                                                 |  | September 30,2003 |     |   | December 31,2002 |  
|------------------------------------------------ |  | ----------------- | --- | - | ---------------- | -
|                                                 |  | (in millions)     |    
|Cash flow hedging activities, net                |  | $                 | 31  |   |                  | $
|Foreign currency translation adjustment          |  |                   | 15  |   |                  |  
|Minimum pension liability                        |  |                   | (66 | ) |                  |  
|                                                 |  |                   |     |   |                  |  
|Accumulated other comprehensive loss, net of tax |  | $                 | (20 | ) |                  | $
|                                                 |  |                   |     |   |                  |  



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Note 5Unconsolidated Investments



A summary of our unconsolidated investments is as follows:



|                                 |  | September 30,2003 |     | December 31,2002
|-------------------------------- |  | ----------------- | --- | ----------------
|                                 |  | (in millions)    
|Equity affiliates:               |  |                   |     |                 
|GEN investments                  |  | $                 | 560 |                 
|NGL investments                  |  |                   | 95  |                 
|CRM investments                  |  |                   |    |                 
|                                 |  |                   |     |                 
|Total equity affiliates          |  |                   | 655 |                 
|Other affiliates, at cost        |  |                   | 13  |                 
|                                 |  |                   |     |                 
|Total unconsolidated investments |  | $                 | 668 |                 
|                                 |  |                   |     |                 



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



|                 |  | Nine Months Ended September 30,
|---------------- |  | -------------------------------
|                 |  | 2003                           
|                 |  | Total                          
|                 |  | (in millions)                  
|Revenues         |  | $                              
|Operating income |  |                                
|Net income       |  |                                



Earnings from
unconsolidated investments of $142 million for the nine months ended September 30, 2003, include the $148 million above, offset by $5 million in losses due to impairments of cost investments and a $1 million loss on the sale of an investment. Losses
from unconsolidated investments of $66 million for the nine months ended September 30, 2002 include the $109 million of net income related to the investments above, offset by losses of $31 million and $144 million associated with the impairment of
technology and generation investments, respectively (see Note 3Restructuring and Other Charges).



As previously described in our Form 10-K/A, a petition was filed in the United States Bankruptcy Court for the District of Minnesota by several former
officers of NRG Energy, the parent company of the partner and operator in two of our joint ventures (including our largest investment, West Coast Power), to put NRG Energy into bankruptcy. This proceeding was settled and the involuntary bankruptcy
was dismissed in early May 2003. NRG Energy and certain of its affiliates subsequently made voluntary Chapter 11 bankruptcy filings in the United States Bankruptcy Court for the Southern District of New York, together with a filing of a plan of
reorganization. Although we cannot predict with any degree of certainty the effects of these actions on the operations of the joint ventures, NRG Energy has stated that it will continue to operate in the ordinary course of business and we do not
expect these filings to significantly impact the joint ventures.



In June 2003, West Coast Power, a joint venture with generation assets in California, repaid the remaining outstanding balance on a $120 million non-recourse bank facility with cash on hand within the joint venture entity. Concurrent with
the retirement of the bank facility, West Coast Power entered into a $50 million cash collateralized letter of credit facility that will be used to collateralize West Coast Powers obligations.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



We own a 50 percent interest in Nicor Energy, a joint venture with Nicor Inc. that marketed retail
gas and electricity in the Midwest. During the first quarter 2003, substantially all of the operations of Nicor Energy were sold, and we substantially liquidated the company in the second quarter 2003.



In August and September 2003, we sold our interests in the Frontier, Paris
and Ferndale domestic projects located in Texas and Washington (aggregate net generating capacity of approximately 130 MW) and in two international projects located in Honduras and Pakistan (aggregate net generating capacity of approximately 110
MW). Net proceeds associated with these sales were approximately $25 million. We recognized a $1 million net loss on the transactions during the third quarter 2003.



Note 6Debt



Notes payable and long-term debt consisted of the following at September 30, 2003 and December 31, 2002:



|                                                                 |  | September 30,2003 |       | December 31,2002
|---------------------------------------------------------------- |  | ----------------- | ----- | ----------------
|                                                                 |  | (in millions)    
|Dynegy Holdings Inc.                                             |  |                   |       |                 
|Revolving Credit Facilities                                      |  | $                 |      |                 
|Senior Notes and Debentures                                      |  |                   | 2,878 |                 
|Term B Loan                                                      |  |                   | 193   |                 
|Company Obligated Preferred Securities of a Subsidiary Trust (1) |  |                   | 200   |                 
|ABG Gas Supply Credit Agreement                                  |  |                   | 204   |                 
|Generation Facility Debt                                         |  |                   | 184   |                 
|Generation Facility Capital Lease                                |  |                   | 165   |                 
|Black Thunder Secured Financing                                  |  |                   |      |                 
|Renaissance and Rolling Hills Credit Facility                    |  |                   |      |                 
|Illinova                                                         |  |                   |       |                 
|Senior Notes                                                     |  |                   | 95    |                 
|Illinois Power                                                   |  |                   |       |                 
|Mortgage Bonds                                                   |  |                   | 936   |                 
|Transitional Funding Trust Notes                                 |  |                   | 454   |                 
|Pollution Control Revenue Refunding Bonds                        |  |                   | 516   |                 
|Tilton Capital Lease                                             |  |                   | 66    |                 
|Term Loan                                                        |  |                   |      |                 
|Dynegy Inc.                                                      |  |                   |       |                 
|Convertible Subordinated Debentures                              |  |                   | 225   |                 
|Junior Subordinated Notes                                        |  |                   | 223   |                 
|DGC Secured Debt (2)                                             |  |                   |      |                 
|                                                                 |  |                   |       |                 
|                                                                 |  |                   | 6,339 |                 
|Less: Unamortized discount on debt                               |  |                   | 27    |                 
|                                                                 |  |                   |       |                 
|                                                                 |  |                   | 6,312 |                 
|Less: Amounts due within one year                                |  |                   | 325   |                 
|                                                                 |  |                   |       |                 
|Total Long-Term Debt                                             |  | $                 | 5,987 |                 
|                                                                 |  |                   |       |                 



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



---

|(1) | At December 31, 2002, these securities were classified as Redeemable Preferred Securities on the condensed consolidated balance sheets. See Note 1Accounting
PoliciesAccounting Principles AdoptedSFAS No. 150.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | As described below, the DGC Secured Debt was replaced by DHIs Term B Loan as part of the April 2003 new credit facility.
|--- | -------------------------------------------------------------------------------------------------------------------------



The following table provides a summary of our debt maturities for the fourth
quarter 2003, the next four years and thereafter.



|                         |  | Total         |       | 2003 |   | 2004 |  | 2005 |     | 2006 |   | 2007 |  | Thereafter
|------------------------ |  | ------------- | ----- | ---- | - | ---- |  | ---- | --- | ---- | - | ---- |  | ----------
|                         |  | (in millions)
|Dynegy Holdings Inc. (1) |  | $             | 3,815 |      | $ | 19   |  | $    | 79  |      | $ | 460  |  | $         
|Illinova                 |  |               | 95    |      |   |     |  |      | 95  |      |   |     |  |           
|Illinois Power (2)       |  |               | 1,954 |      |   | 22   |  |      | 152 |      |   | 157  |  |           
|Dynegy Inc.              |  |               | 448   |      |   |     |  |      |    |      |   |     |  |           
|                         |  |               |       |      |   |      |  |      |     |      |   |      |  |           
|Total                    |  | $             | 6,312 |      | $ | 41   |  | $    | 326 |      | $ | 617  |  | $         
|                         |  |               |       |      |   |      |  |      |     |      |   |      |  |           

---

|(1) | Of the $460 million in Dynegy Holdings Inc.s 2005 maturities, approximately $360 million was paid off as part of the October 2003 DHI follow-on notes offering, as further
described below.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | Included in Illinois Powers 2004 maturities of $152 million is $66 million related to the Tilton capital lease. In October 1999, Illinois Power entered into a sublease with
DMG pursuant to which DMG is obligated to make all payments under the lease. Please read Note 6  Debt  Tilton Capital Lease for a discussion of the delivery of our notice of intent to exercise our option to purchase the leased turbines
upon the expiration of the lease in September 2004.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Revolvers and Commercial Paper. During the three- and nine-month periods ended September 30, 2003, we repaid zero and $128 million, respectively, under our revolving credit facilities. Additionally, during the three- and
nine-month periods ended September 30, 2003, we issued an aggregate of approximately $71 million and eliminated an aggregate of approximately $519 million, respectively, of letters of credit under these revolving credit facilities. During the period
from September 30, 2003 through November 5, 2003, we reduced our outstanding letters of credit under these revolving credit facilities by $48 million.



On April 2, 2003, DHI entered into a $1.66 billion credit facility consisting of:



| |  | a $1.1 billion DHI secured revolving credit facility, which matures on February 15, 2005;
| | - | -----------------------------------------------------------------------------------------



| |  | a $200 million DHI secured term loan (Term A Loan), which was scheduled to mature on February 15, 2005; and
| | - | -------------------------------------------------------------------------------------------------------------



| |  | a $360 million DHI secured term loan (Term B Loan), which was scheduled to mature on December 15, 2005.
| | - | ---------------------------------------------------------------------------------------------------------



The credit facility replaced, and preserved the commitment of each lender
under, DHIs former $900 million and $400 million revolving credit facilities, which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and Dynegys $360 million DGC secured debt, which had a maturity date of December 15,
2005. The restructured credit facility provides funding for general corporate purposes. The revolving facility is also available



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



for the issuance of letters of credit. Borrowings under the credit facility bear interest, at our option, at (i) a
base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. A letter of credit fee is payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. A 0.15% fronting fee is
incurred upon the issuance of letters of credit. An unused commitment fee of 0.50% per annum is payable on the unused portion of the revolving facility. Please read Note 10 to our Form 10-K/A beginning on page F-47 for further discussion of our
restructured credit facility.



We incurred debt issuance costs
aggregating approximately $41 million in connection with the April 2003 credit facility. Such amounts have been capitalized and are amortized over the term of the credit facility.



Amended Credit Facility. In July and October 2003, in conjunction with the long-term refinancing and
restructuring transactions described below, we entered into the third and fourth amendments, respectively, to DHIs credit facility to, among other things, permit the consummation of the then-proposed transactions, which included repaying the
Term A Loan and the Term B Loan. The third amendment became effective in August 2003, upon the closing of DHIs private placement offering of $1.45 billion in second priority senior secured notes and Dynegys offering of $225 million in
convertible subordinated debentures, and the fourth amendment became effective in October 2003, immediately prior to the closing of DHIs private placement offering of $300 million in additional second priority senior secured notes.



Following repayment of the amounts then-outstanding under the Term A Loan
and Term B Loan as described below, the amended credit facility consists solely of a $1.1 billion secured revolving credit facility that matures on February 15, 2005. We currently have no borrowings under the credit facility, with letters of credit
issued of $305 million at November 5, 2003.



The amended
credit facility contains mandatory commitment reductions and prepayment events. The commitments, subject to specified exceptions, must be permanently reduced or cash collateralized:



| |  | with 100% of the net cash proceeds of all non-ordinary course asset sales, except that, for so long as the Dynegy Inc. Junior Unsecured Subordinated Notes due 2016 issued in
connection with the Series B Exchange are outstanding, such junior notes must be prepaid with 75% of the net cash proceeds from the sale of Illinois Power assets or equity (or 25% of the net cash proceeds from any other asset or equity sales) and
25% of such net cash proceeds must be used to permanently reduce or cash collateralize the commitments under the amended credit facility;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | with 50% of the net cash proceeds from the issuance of equity, subordinated debt or additional second lien debt (other than the proceeds from the DHI second priority senior secured
notes and the Dynegy convertible subordinated debentures), except that we may retain up to $250 million of proceeds of equity issuances and, in addition to such retained amounts, such proceeds may be used to make mandatory prepayments on the junior
notes so long as the revolving commitments are reduced or cash collateralized in connection with such prepayments according to a formula, with such reduction in or cash collateralization of the commitments in connection with any prepayments on the
junior notes not to exceed $100 million;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | with 100% of the net cash proceeds from the issuance of senior debt, other than the proceeds from the DHI second priority senior secured notes;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------



| |  | with 50% of extraordinary receipts (as defined in the amended credit facility); and
| | - | -----------------------------------------------------------------------------------



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



| |  | in connection with the payment of cash dividends on the Dynegy Series C convertible preferred stock issued in connection with the Series B Exchange or the repurchase of DHI senior
notes that have maturity dates on or after 2007, by an amount determined according to a formula, provided that we have $500 million of liquidity after giving effect to such payment or repurchase.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The amended credit facility provides for no amortization of principal amounts
outstanding prior to the maturity dates except upon the occurrence of a mandatory prepayment event.



The amended credit facility generally prohibits us and our subsidiaries, including DHI but excluding Illinois Power, from pre-paying, redeeming or
repurchasing outstanding debt or preferred stock, except that we may, among other things:



| |  | pay cash dividends on the Dynegy Series C convertible preferred stock issued in connection with the Series B Exchange, subject to the following conditions: (i) no default shall have
occurred and be continuing, (ii) a voluntary prepayment of the credit facility is made in connection with such payments according to a formula, and (iii) we must have $500 million of liquidity after giving effect to such payment;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | prepay, repurchase or redeem the balance of DHIs outstanding 2005-2006 senior notes, the Project Alpha credit facility and the Riverside facility with the net cash proceeds of
extraordinary receipts (as defined in the amended credit facility) or issuances of equity or subordinated debt, or cash on hand; provided that in the case of any prepayment of the Project Alpha credit facility or the Riverside facility, we must have
$500 million of liquidity for ten days prior to and as of the date of such prepayment; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | repurchase up to $100 million of DHI senior notes that have maturity dates on or after 2007 so long as we have $500 million of liquidity for ten days prior to and as of the date of
such repurchase and the credit facility is prepaid in connection with such payments according to a formula; provided that up to $300 million of such notes (including any amount repurchased under the foregoing clause) may be repurchased without a
concurrent prepayment under the credit facility with the net cash proceeds of extraordinary receipts (as defined in the amended credit facility) or issuances of equity or subordinated debt.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The amended credit facility also includes a change to the financial covenant
that requires a specified level of Secured Debt to EBITDA (in each case as defined in the amended credit facility). Under the amended covenant, we and our subsidiaries, including DHI but excluding Illinois Power and DGC, are prohibited from
permitting our Secured Debt/EBITDA ratio from and after September 30, 2003 to be greater than the ratios set forth below:



|Measurement Period Ending                            |  | Maximum Secured Debt/ EBITDA Ratio
|---------------------------------------------------- |  | ----------------------------------
|September 30, 2003                                   |  | 9.0:1.0                           
|December 31, 2003                                    |  | 9.0:1.0                           
|March 31, 2004                                       |  | 8.4:1.0                           
|June 30, 2004                                        |  | 8.0:1.0                           
|September 30, 2004                                   |  | 7.1:1.0                           
|December 31, 2004 and each fiscal quarter thereafter |  | 6.7:1.0                           



The definition of
EBITDA in the amended credit facility specifically excludes, among other items, (i) Discontinued Business Operations, as defined therein (including third-party marketing and trading, communications and tolling arrangements), (ii) certain amounts
paid, incurred or reserved in connection with any litigation disclosed under the schedules to the amended credit facility, (iii) extraordinary gains or losses, (iv) any impairment,



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



abandonment, restructuring or similar non-cash expenses, (v) interest expense, (vi) gains/losses on extinguishment of
debt and (vii) turbine cancellation payments up to $50 million in the aggregate.



Refinancing. In August 2003, we consummated a series of refinancing transactions, which we refer to collectively as the Refinancing, comprised of the following:



| |  | Issuance by DHI of $1.45 billion of second priority senior secured notes in a private placement transaction pursuant to Rule 4(2) of the Securities Act of 1933, which notes are
secured on a second priority basis by substantially the same collateral that secures the obligations under DHIs credit facility, which consists of a substantial portion of the available assets and stock of our direct and indirect subsidiaries,
excluding Illinois Power;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Issuance by Dynegy of $225 million of convertible subordinated debentures in a private placement transaction pursuant to Rule 4(2) of the Securities Act of 1933, which debentures
are convertible into Dynegys Class A common stock and guaranteed on a senior unsecured basis by DHI; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | A cash tender offer and related consent solicitation for all of DHIs outstanding 8.125% Senior Notes due 2005, 63⁄4% Senior Notes due 2005 and 7.450% Senior Notes due 2006.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Pursuant to the cash tender offer, which expired
on August 8, 2003, we purchased approximately $282 million in principal amount of the $300 million 8.125% Senior Notes due 2005, approximately $150 million in principal amount of the $150 million 63⁄4% Senior Notes due 2005 and approximately $177
million in principal amount of the $200 million 7.450% Senior Notes due 2006. We paid approximately $5 million above par value of the notes in connection with the purchase of these notes and the consent fee paid in connection with the related
solicitation of the consents to eliminate several of the restrictive covenants and certain other provisions previously contained in the indentures governing these notes. As a result of obtaining the required consents, DHI executed and delivered
supplemental indentures setting forth amendments to the applicable indentures, which govern the notes remaining outstanding following the expiration of the tender offer.



The net proceeds from the Refinancing, along with cash on hand, were utilized to make the $225 million cash payment required
under the Series B Exchange, as described below, and to prepay certain of our indebtedness including:



| |  | Prepay in full the $200 million Term A Loan outstanding under the DHI credit facility;
| | - | --------------------------------------------------------------------------------------



| |  | Prepay approximately $165 million of the $360 million Term B Loan outstanding under the DHI credit facility;
| | - | ------------------------------------------------------------------------------------------------------------



| |  | Repurchase approximately $609 million in the aggregate of DHIs outstanding 8.125% Senior Notes due 2005, 63⁄4% Senior Notes due 2005 and 7.450% Senior Notes due 2006; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Prepay the $696 million of debt outstanding under the Black Thunder secured financing.
| | - | --------------------------------------------------------------------------------------



The prepayment of the debt above resulted in accelerated charges during the third quarter 2003 of approximately $20 million,
pre-tax, of unamortized financing costs and the settlement value of the associated interest rate hedge instruments. We incurred debt issuance costs aggregating approximately $60 million in connection with the Refinancing. Such amounts have been
capitalized and are amortized over the term of the Refinancing.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



DHI Second Priority Senior Secured Notes. In connection with the Refinancing, in August
2003, DHI issued $1.45 billion in second priority senior secured notes, comprised of $225 million in floating rate notes due 2008 which accrue interest at a rate of LIBOR plus 650 basis points (reset on a quarterly basis), $525 million in 9.875%
notes due 2010 with a yield to maturity of 10.0% and $700 million in 10.125% notes due 2013 with a yield to maturity of 10.25%. Each of DHIs existing and future wholly owned domestic subsidiaries that guarantee DHIs obligations under its
existing credit facility guarantee the obligations under the notes on a senior secured basis. In addition, Dynegy and its other subsidiaries that guarantee DHIs existing credit facility guarantee the obligations under the notes on a senior
secured basis.



The notes and guarantees are senior obligations
secured by a second-priority lien on, subject to certain exceptions and permitted liens, all of DHIs and its guarantors existing and future property and assets that secure DHIs obligations under its credit facility.



The indenture governing the notes contains restrictive covenants that limit
the ability of DHI and its subsidiaries that guarantee the notes to, among other things:



| |  | pay dividends or distributions on, or redeem or repurchase, capital stock;
| | - | --------------------------------------------------------------------------



| |  | make investments;
| | - | -----------------



| |  | incur or guarantee additional indebtedness;
| | - | -------------------------------------------



| |  | create certain liens;
| | - | ---------------------



| |  | engage in sale and leaseback transactions;
| | - | ------------------------------------------



| |  | make restricted payments;
| | - | -------------------------



| |  | consolidate, merge or transfer all or substantially all of its assets; or
| | - | -------------------------------------------------------------------------



| |  | engage in certain transactions with affiliates.
| | - | -----------------------------------------------



These covenants are described in more detail in the indenture governing the notes, which is filed as an exhibit to our second quarter 2003 Form 10-Q.



DHI Follow-On Notes Offering. On October 15,
2003, DHI consummated a follow-on offering of $300 million aggregate principal amount of additional second priority senior secured notes in a private placement transaction which we refer to as the follow-on notes offering. The follow-on notes
offering was comprised of:



| |  | $100 million of 9.875% second priority senior secured notes due 2010 issued at a premium to par of 104.25% with a yield to maturity of approximately 9.0%; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | $200 million of 10.125% second priority senior secured notes due 2013 issued at a premium to par of 105.25% with a yield to maturity of approximately 9.3%.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------



Each of these series of additional notes are treated as a single class
with the corresponding series of DHI second priority senior secured notes that were originally issued in August 2003, and are subject to the indenture governing the previously issued notes, which is described above and filed as an exhibit to our
second quarter 2003 Form 10-Q. These additional notes are guaranteed by the same guarantors as the notes issued in the Refinancing,



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



and such notes and guarantees are secured by a second-priority lien on the same property and assets that secure the
previously issued notes.



The net proceeds from the follow-on
notes offering, along with cash on hand, were utilized to:



| |  | prepay the $194 million outstanding under our Term B Loan; and
| | - | --------------------------------------------------------------



| |  | retire the $170 million generation facility capital lease obligation.
| | - | ---------------------------------------------------------------------



We incurred debt issuance costs aggregating approximately $3 million in connection with the follow-on notes offering. Such amounts have been capitalized
and will be amortized over the term of the notes issued in connection with the follow-on notes offering.



Dynegy Convertible Subordinated Debentures. Concurrently with the August 2003 issuance of DHIs second priority senior secured notes,
we issued $175 million in 4.75% convertible subordinated debentures due 2023. We also granted the initial purchasers of the debentures a 30-day option to purchase up to $50 million of additional debentures on these same terms. The purchasers
exercised their option, and the closing of the $50 million overallotment option occurred on August 26, 2003. The debentures are convertible into shares of our Class A common stock at any time at a conversion price of $4.1210 per share, subject to
specified adjustments for dividend payments and other actions. The debentures are subordinated to our existing and future senior indebtedness and effectively subordinated to all indebtedness and liabilities of our non-guarantor subsidiaries. The
debentures are guaranteed on a senior unsecured basis by DHI. We have agreed to file a registration statement covering resale of the debentures and the Class A common stock issuable upon conversion of the debentures, subject to the requirement to
pay additional interest if such registration statement does not become effective within 360 days from August 11, 2003.



The debentures are described in more detail in the indenture governing the debentures, which is filed as an exhibit to our second quarter 2003 Form 10-Q.



ChevronTexaco Series B Preferred Stock
Restructuring. Also in August 2003, we consummated a restructuring of the $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a subsidiary of ChevronTexaco. Pursuant to the restructuring, which we
refer to as the Series B Exchange, this ChevronTexaco subsidiary exchanged its Series B preferred stock for the following:



| |  | a $225 million cash payment;
| | - | ----------------------------



| |  | $225 million principal amount of Junior Unsecured Subordinated Notes due 2016 issued by Dynegy, which we refer to in this report as the junior notes; and
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 8 million shares of Dynegys Series C Mandatorily Redeemable Convertible Preferred Stock due 2033 (liquidation preference of $50 per share), which we refer to in this report as
the Series C convertible preferred stock.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The
junior notes bear interest at a rate of 9.00% per annum during the first two years and a rate of 13.75% per annum thereafter, in each case, compounded semi-annually and, at our option, payable in kind by issuance of additional junior notes. The
junior notes are subject to mandatory prepayment during the first two years and until such time as ChevronTexaco elects otherwise with:



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



| |  | 100% of net cash proceeds from the issuances of qualified capital stock in excess of the first $250 million of qualified capital stock issued after the Series B Exchange;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 50% of net cash proceeds from issuances of subordinated or convertible debt, mandatorily redeemable preferred stock or convertible equity (excluding refinancings thereof);
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 25% of net cash proceeds from asset sales (other than sales of Illinois Power assets or equity) up to $200 million of asset sale proceeds in the aggregate from and after the
consummation of the Series B Exchange; and
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 75% of net cash proceeds from the sale of Illinois Power assets or equity, provided that such net cash proceeds will not include any amounts used for the payment of any debt
associated with Illinois Power. Please read Note 13Subsequent Event for a discussion of our pending sale of substantially all of the assets and liabilities of Illinois Power.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



During September 2003, we used proceeds of approximately $2 million from the
previously described sales of certain non-strategic generation investments to redeem a portion of the junior notes.



To the extent any mandatory prepayment is not made due to restrictions contained in our current or future debt instruments or applicable law, interest
will accrue at the rate of 13.75% on the blocked prepayment amount. The junior notes may be prepaid at our option at par plus accrued interest at any time prior to maturity, provided, however, that the junior noteholders may, at any time after the
date that is 90 days prior to the two-year anniversary of the closing of the Series B Exchange, elect to terminate the mandatory prepayment provisions with such election being effective after expiration of the 90 day period. If such an election is
made, we will be prohibited from redeeming the junior notes through the seven-year anniversary of the Series B Exchange. Following this seven-year anniversary, we will be entitled to redeem the junior notes at par plus accrued interest plus a
premium equal to one-half the coupon, declining ratably to par in year ten.



With respect to the Series C convertible preferred stock, dividends are payable at a rate of 5.5% per annum in cash semi-annually. At our election, we may defer dividend payments for up to 10 consecutive semi-annual
dividend payment periods. Upon termination of any deferral period, all accrued and unpaid amounts are due in cash. We may not pay dividends on our common stock during any deferral period. Additionally, if we fail to obtain shareholder approval
within one year for conversion of the Series C convertible preferred stock into shares of our Class B common stock, the dividend rate on the Series C convertible preferred stock will increase to 10% until such time as we obtain such approval or it
is determined that such approval is not required under NYSE rules and other applicable laws and regulations. Following the receipt of such approval, the shares of Series C convertible preferred stock generally are convertible, at the option of the
holder, at a price of $5.78 per share. The initial holder of the Series C convertible preferred stock may not transfer the shares of the Series C convertible preferred stock (other than to affiliates) until the earlier of (a) 18 months following the
closing of the Series B Exchange or (b) 120 days following the consummation of one or more public or private sales of our qualified capital stock resulting in gross proceeds to us of at least $250 million. On or after the third anniversary of this
lock-up period, we may, at our option, cause the Series C convertible preferred stock to be converted into shares of our Class B common stock at any time the closing price of our Class A common stock exceeds 130% of the conversion price
then in effect for at least 20 trading days within any period of 30 consecutive trading days prior to such conversion. Upon any conversion of the Series C convertible preferred stock, we have the right to deliver, in lieu of shares of our Class B
common stock, cash or a combination of cash and shares of our Class B common stock. At any time after the tenth anniversary of the closing of the Series B Exchange, we may, at our option, redeem all of the shares of Series C convertible preferred
stock for a redemption price equal to $50 per share plus accrued and unpaid dividends.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



In connection with the Series B Exchange, we also amended the shareholder agreement and registration
rights agreement between us and ChevronTexaco and entered into two new registration rights agreements covering the junior notes, the Series C convertible preferred stock and the shares of Class B common stock issuable on the conversion of the Series
C convertible preferred stock.



As part of the Series B
Exchange, we also renegotiated certain prepayment arrangements with ChevronTexaco such that ChevronTexaco returned to us approximately $40 million in pre-payments relating to our commodity purchase obligations and converted our prepayment obligation
from thirty days to seven days.



For a complete description of
the junior notes and the Series C convertible preferred stock, please read the agreements between us and ChevronTexaco entered into in connection with the Series B Exchange that are filed as exhibits to our second quarter 2003 Form 10-Q.



Renaissance and Rolling Hills Credit Facility. In July 2002,
we completed a $200 million interim financing, bearing interest at LIBOR plus 1.38%. This loan was scheduled to mature in January 2003 and was secured by interests in our Renaissance merchant power generation facility and Rolling Hills. In January
2003, we repaid $94 million of this facility and refinanced the remaining $106 million. The maturity date on the remaining $106 million was extended to October 15, 2003 and the interest rate on the remaining balance was changed to LIBOR plus 5%. On
April 16, 2003, we prepaid the remaining $106 million.



Illinova Senior Notes. In March 2003, we purchased on the open market $5 million in aggregate principal amount of Illinovas 7.125% Senior Notes due 2004. The repurchased notes have been cancelled and are no longer
outstanding. As a result, $95 million in aggregate principle amount of the notes remain outstanding at September 30, 2003 and is included within current portion of long-term debt on the unaudited condensed consolidated balance sheets.



Illinois Power Term Loan. In May 2003, Illinois Power used a
portion of the proceeds from its December 2002 sale of $550 million in 111⁄2% Mortgage Bonds due 2010, $150 million of which were issued in January 2003 following receipt of a required approval from the ICC, to pay down the $100 million then
outstanding under its one-year term loan.



Illinois Power
Mortgage Bond Maturities. Illinois Power used interest payments from Illinova on its $2.3 billion intercompany note receivable, together with remaining proceeds from its December 2002 mortgage bond offering, to pay an aggregate of $190
million in mortgage bond maturities in August and September 2003.



Tilton Capital Lease. In September 1999, Illinois Power entered into an $81 million operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. These facilities consist of
peaking units totaling 176 MW of capacity. Illinois Power sublet the turbines to DMG in October 1999. In September 2003, we delivered notice of our intent to exercise our option to purchase the turbines upon the expiration of the operating lease in
September 2004. As a result of this action, we began accounting for the lease obligation as a capital lease. Accordingly, we recorded a $66 million increase to Property, plant and equipment and a corresponding increase to Short-term debt. The
recorded amount of $66 million represents the fair market value of the leased assets at the inception of the capital lease. The difference between the recorded amount and the $81 million purchase price will be accreted over the 12-month term of the
capital lease through a charge to interest expense with a corresponding increase to Short-term debt. This obligation was previously disclosed as a residual value guarantee of approximately $70 million in the footnotes to our financial statements and
the Contingent Financial Commitments table on page 52 of our Form 10-K/A.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Note 7Related Party Transactions



In connection with our previously announced exit from third-party risk management aspects of the marketing and trading
business, we agreed with ChevronTexaco to terminate the natural gas purchase agreement between the parties and to provide for an orderly transition of responsibility for marketing ChevronTexacos domestic natural gas production. This agreement
did not affect our contractual agreements with ChevronTexaco relative to its U.S. natural gas processing and the marketing of its domestic natural gas liquids. The cancellation of the agreement was effective January 1, 2003. In accordance with the
termination of the natural gas purchase agreement, we paid $13 million to ChevronTexaco. As part of the transition, we also provided scheduling, accounting and reporting services to ChevronTexaco through June 2003. In connection with the termination
of the transition agreement, ChevronTexaco paid us $13.5 million in September 2003 as final settlement for the net payable and receivable balances. We also engage in other transactions with ChevronTexaco, including purchases and sales of natural
gas, natural gas liquids and crude oil, which we believe are executed on terms that are fair and reasonable.



In August 2003, we consummated a restructuring of the $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a
subsidiary of ChevronTexaco. Please read Note 6DebtChevronTexaco Series B Preferred Stock Restructuring for further discussion. The following table summarizes the impact of this transaction on our unaudited condensed consolidated balance
sheets and unaudited condensed consolidated statements of operations (in millions):



|Series B Convertible Preferred Securities (previously included in Redeemable Preferred Securities on the condensed consolidated
balance sheets)           |  | $ | 1,414 |  
|--------------------------------------------------------------------------------------------------------------------------------------------------------- |  | - | ----- | -
|Implied dividend on Series B Preferred Stock (previously included in Additional Paid-In-Capital on the condensed consolidated
balance sheets)             |  |   | 660   |  
|                                                                                                                                                          |  |   |       |  
|Total balance immediately prior to transaction                                                                                                            |  |   | 2,074 |  
|Issuance of Series C convertible preferred stock                                                                                                          |  |   | (400  | )
|Issuance of junior notes                                                                                                                                  |  |   | (225  | )
|Cash payment to ChevronTexaco                                                                                                                             |  |   | (225  | )
|                                                                                                                                                          |  |   |       |  
|Gain related to ChevronTexaco Series B Preferred Stock restructuring                                                                                      |  |   | 1,224 |  
|Implied dividends on Series B Preferred Stock recorded in 2003                                                                                            |  |   | (203  | )
|Dividends on Series C convertible preferred stock recorded in 2003                                                                                        |  |   | (3    | )
|                                                                                                                                                          |  |   |       |  
|Net preferred stock dividend gain reflected on the unaudited condensed consolidated statements of operations for the nine-months
ended September 30, 2003 |  | $ | 1,018 |  
|                                                                                                                                                          |  |   |       |  



Note 8Earnings (Loss) Per
Share



Basic earnings (loss) per share represents the
amount of earnings (loss) for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (loss) for the period available to each share of common stock
outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period. The reconciliation of basic earnings (loss) per share from
continuing operations to diluted earnings (loss) per share from continuing operations is shown in the following table:



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



|                                                                        |  | Three MonthsEnded September 30,         |       |      | Nine MonthsEnded September 30, |       
|----------------------------------------------------------------------- |  | --------------------------------------- | ----- | ---- | ------------------------------ | ------
|                                                                        |  | 2003                                    |       | 2002 |                                |       
|                                                                        |  | (in millions, except per share amounts) |      
|Income (loss) from continuing operations                                |  | $                                       | 4     |      | $                              | (1,033
|Convertible preferred stock (dividends) gain                            |  |                                         | 1,183 |      |                                | (83   
|                                                                        |  |                                         |       |      |                                |       
|Income (loss) from continuing operations for basic earnings per share   |  |                                         | 1,187 |      |                                | (1,116
|Effect of dilutive securities:                                          |  |                                         |       |      |                                |       
|Interest on convertible subordinated debentures                         |  |                                         | 1     |      |                                |      
|Dividends on Series C convertible preferred stock                       |  |                                         | 3     |      |                                |      
|Dividends on Series B convertible preferred stock (Note 1)              |  |                                         | 38    |      |                                |      
|                                                                        |  |                                         |       |      |                                |       
|Income (loss) from continuing operations for diluted earnings per share |  | $                                       | 1,229 |      | $                              | (1,116
|                                                                        |  |                                         |       |      |                                |       
|Basic weighted-average shares                                           |  |                                         | 375   |      |                                | 368   
|Effect of dilutive securities:                                          |  |                                         |       |      |                                |       
|Stock options                                                           |  |                                         | 2     |      |                                | 1     
|Convertible subordinated debentures (see Note 6)                        |  |                                         | 28    |      |                                |      
|Series C convertible preferred stock (see Note 6)                       |  |                                         | 37    |      |                                |      
|Series B convertible preferred stock (Note 1)                           |  |                                         | 22    |      |                                |      
|                                                                        |  |                                         |       |      |                                |       
|Diluted weighted-average shares (1)                                     |  |                                         | 464   |      |                                | 369   
|                                                                        |  |                                         |       |      |                                |       
|Earnings (loss) per share from continuing operations                    |  |                                         |       |      |                                |       
|Basic                                                                   |  | $                                       | 3.17  |      | $                              | (3.03 
|                                                                        |  |                                         |       |      |                                |       
|Diluted (2)                                                             |  | $                                       | 2.65  |      | $                              | (3.03 
|                                                                        |  |                                         |       |      |                                |       

---

|(1) | In our third quarter 2003 earnings release furnished with our Form 8-K filed on October 30, 2003, we reported diluted earnings per share of $2.69 for the three-month period ended
September 30, 2003. The difference between that amount and the amount reported herein resulted from an error in the calculation of dilutive shares associated with the Series B convertible preferred stock previously held by a subsidiary of Chevron
Texaco. The year-to-date calculation of dilutive shares, as well as the amount reported for year-to-date diluted earnings per share, are not affected by this correction.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|(2) | When an entity has a net loss from continuing operations, SFAS No. 128, Earnings per Share, prohibits the inclusion of potential common shares in the computation of
diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2002.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Note 9Commitments and Contingencies



Set forth below is a description of our material legal proceedings. In
addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In the opinion of management, 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 in accordance with SFAS No. 5, Accounting for Contingencies. For
environmental matters, we record liabilities when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Please see Note 2Accounting Policies beginning on page F-17 of our Form 10-K/A
for further discussion. During the second quarter 2003, we recorded a



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



pre-tax litigation reserve of $50 million related to contingencies with respect to which there was additional
activity and for which the amount of loss became probable and reasonably estimable during the quarter.



With respect to some of the items listed below, we have determined that a loss is not probable or that any such loss, to the extent probable, is not
reasonably estimable. Notwithstanding the foregoing, management has assessed these matters based on currently available information and made an informed judgment concerning the potential outcome of such matters, 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 during the third quarter 2003:



| |  | In September 2003, the court approved the settlement agreement we executed with the former Enron shareholder plaintiffs in April 2003, which obligates us to pay $6 million to settle
the claims asserted on behalf of all Enron shareholders who held Enron stock at the time our November 2001 merger agreement was terminated. We previously deposited this $6 million into escrow with the court and, assuming the settlement is not
appealed, the money will be paid to the plaintiffs in December 2003.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | In August 2003, Cornerstone Propane Partners, L.P. filed a putative class action in the U.S. District Court for the Southern District of New York, naming Dynegy Marketing &
Trade, DHI, and Dynegy Inc. among the defendants. The complaint alleges that during 2001 and 2002 defendants (i) unlawfully manipulated the prices of natural gas futures and options contracts traded on the New York Mercantile Exchange and (ii)
engaged in a variety of trades, including wash trades, whose sole purpose was to create the perception of increased liquidity and demand for natural gas. We responded to plaintiffs complaint on November 11, 2003. We intend to defend against
these claims vigorously.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | In October 2003, Trans-Elect, Inc. and Illinois Electric Transmission Company, LLC filed suit against Illinois Power in the Northern District of Illinois seeking specific
performance and damages, including lost profits, resulting from our termination in July 2003 of our October 2002 purchase agreement providing for the sale of our transmission assets to Trans-Elect conditioned upon certain regulatory approvals which
were not obtained. Trans-Elect claims that we breached the agreement by failing to use our best efforts to obtain the required approvals and/or to negotiate an alternate agreement that could be approved. We deny these claims, in that we
believe we complied with the terms of the agreement, and intend to defend against them vigorously. We have until November 17, 2003 to respond to the plaintiffs complaint.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



Shareholder Litigation. Since April 2002, a number of purported class action lawsuits have been filed on behalf of purchasers of our
publicly traded securities generally during the period between April 2001 and April 2002. These lawsuits principally assert that Dynegy and certain of our executive officers and directors violated the federal securities laws in connection with our
accounting treatment and disclosure of Project Alpha. These lawsuits have been consolidated in the United States District Court for the Southern District of Texas (Houston Division). The Regents of the University of California have been appointed
lead plaintiff and the law firm of Milberg Weiss has been appointed class counsel. In June 2003, plaintiffs filed a consolidated amended complaint. This amended complaint included, among other items, additional allegations regarding Project Alpha,
round-trip trading, the submission of false trade reports to publications that calculate natural gas index prices, the alleged manipulation of



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



the California power market, and the restatement of financial statements for periods since 1999. The original
complaint covered a class period from April 2001 to April 2002. The amended complaint extended the class period to encompass the period from January 27, 2000 to July 22, 2002. We previously filed two motions to dismiss this action, and the
plaintiffs responded to our motions in October 2003. Our replies to plaintiffs responses are due later in November 2003. An adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.
We previously recorded a reserve in connection with this litigation.



In addition, several derivative lawsuits have been filed in which we are a nominal defendant. Those claims have been consolidated into two groupsone derivative group pending in Federal court (Derusha) and the other derivative group
pending in state court (Gillies). The lawsuits relate to Project Alpha, round-trip trades and alleged manipulation of the California power market. The lawsuits seek recovery on behalf of Dynegy from various present and former officers and directors.
Dynegys motion to dismiss the federal derivative claim is currently pending and is set for hearing on December 10, 2003. Discovery commenced in the state derivative matter in September 2003. Because of the nature of these derivative lawsuits,
we do not expect to incur any material liability with respect to these derivative claims.



ERISA/401(k) Litigation. In August 2002, a purported class action complaint was filed against Dynegy in the United States District Court for the Southern District of Texas (Houston Division) alleging
violations of the Employee Retirement Income Security Act. The lawsuit concerns the Dynegy Inc. 401(k) Savings Plan and claims that our Board and former and current officers involved in the administration of the 401(k) Plan breached their fiduciary
duties to the Plans participants and beneficiaries in connection with the Plans investment in the Dynegy common stock fund. The lawsuit seeks unspecified damages for the losses to the Plan resulting from the alleged breaches of fiduciary
duties, as well as attorneys fees and certain other costs. The putative class was originally defined as participants holding Dynegy common stock in the plan as of April 17, 2001 or later. In February 2003, the plaintiffs filed an amended
complaint, which extended the putative class period back to April 27, 1999. Additional past Board members were named as defendants, as were past and present members of our Benefit Plans Committee. The amended complaint alleges that our earnings and
business conditions were misstated from 1999 forward and that, during such period, Dynegy Inc. and members of the Board, including members of the Compensation and Human Resources Committee of the Board, breached fiduciary duties by failing to
disclose to the Benefit Plans Committee information regarding risks associated with its business due to misstatements about revenues, earnings and operations, which information was material to the appropriateness of Dynegy common stock as an
investment option, and by failing to monitor the Benefit Plans Committee. The amended complaint further alleges that the Benefit Plans Committee breached fiduciary duties by failing to disclose complete and accurate information with respect to the
suitability of investing in common stock and by failing to eliminate Dynegy common stock as a Plan investment option, and that the Benefit Plans Committee breached its duty of loyalty to discharge its duty to the Plan solely in the interest of the
participants and beneficiaries. The amended complaint also alleges that we breached co-fiduciary duties under ERISA and, to the extent we are found not to be a fiduciary, that we benefited by knowingly participating in fiduciary breaches by others.



The plaintiff filed a second amended complaint in April 2003,
which names as additional defendants certain former employees who served on a predecessor committee to the Benefit Plans Committee. The plaintiff also included in the second amended complaint allegations relating to Project Alpha, round-trip trades
and the gas price index investigation. The plaintiff filed a third amended complaint in June 2003, which names as additional defendants additional former employees who served on a predecessor committee to the Benefits Plan Committee as well as
Vanguard Fiduciary Trust Company, which served as the Trustee of the trust that held the assets of the Plan during a portion of the putative class period. In July 2003, Dynegy filed a motion to dismiss this action. Plaintiffs response is due
in late November 2003, and the hearing on our motion is expected to occur in January 2004. Discovery in this litigation is ongoing.



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We are analyzing these claims and intend to defend against them vigorously. It is not possible to
predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with this lawsuit. However, an adverse outcome could have a material adverse effect on our financial condition,
results of operations and cash flows.



Baldwin Station
Litigation. Illinois Power and DMG, collectively referred to in this section as the Defendants, are currently the subject of an NOV from the EPA and a complaint filed by the EPA and the Department of Justice alleging violations of the Clean
Air Act, the regulations promulgated thereunder and certain Illinois regulations adopted pursuant to the Clean Air Act. Eight similar notices and complaints were filed against other owners of coal-fired power plants in what we refer to as the
Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the Defendants three Baldwin Station generating units constituted major modifications
under the Prevention of Significant Deterioration (PSD), the New Source Performance Standard (NSPS) regulations and the applicable Illinois regulations, and that the Defendants failed to obtain required operating permits under the applicable
Illinois regulations. When activities that meet the definition of major modifications occur and are not otherwise exempt, the Clean Air Act and related regulations generally require that the generating facilities at which such activities
occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.



We have undertaken activities to significantly reduce emissions at the Baldwin Station since the complaint was filed in 1999. In 2000, the Baldwin Station
was converted from high to low sulfur coal, resulting in sulfur dioxide emission reductions of over 90% from 1999 levels. Furthermore, selective catalytic reduction equipment has been installed at two of the three units at Baldwin Station, resulting
in significant emission reductions of nitrogen oxides. However, the EPA may seek to require the installation of the best available control technology, or the equivalent, at the Baldwin Station. Current estimates indicate that we could
incur capital expenditures of up to $410 million if the installation of best available control technology were required. The EPA also has the authority to seek penalties for the alleged violations at the rate of up to $27,500 per day for each
violation.



In February 2003, the Court granted our motion for
partial summary judgment based on the five-year statute of limitations. As a result, the EPA is not permitted to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Courts ruling
also precludes monetary civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. We believe that we have meritorious defenses against the remaining claims and vigorously defended against them at
trial. The trial to address these remaining issues began in June 2003 and closing arguments occurred in September 2003. The parties also participated in a mandatory settlement conference with the judge, but did not reach a settlement. Shortly before
closing argument, motions to intervene were filed on behalf of the State of Illinois and on behalf of Bottom Conservancy, Health and Environmental Justice  St. Louis, Inc., Illinois Stewardship Alliance and Prairie Rivers Alliance. The motions
were granted by Order on October 23, 2003 as to all intervenors. The Order specifically limits the participation of the intervenors to filing briefs in support of arguments they believe the United States has ceased to pursue. The judge has indicated
he intends to enter judgment in this matter before the end of 2003. We have recorded a reserve for potential penalties that could be imposed if the EPA were to prosecute successfully these remaining claims for penalties.



In August 2003, two significant decisions were handed down in other cases
that are part of the Utility Enforcement Initiative. In one case, United States v. Ohio Edison, the Court found the defendant liable for violations of the Clean Air Act. In reaching this decision, the Court adopted the EPAs
interpretation of the routine maintenance, repair and replacement exclusion, applying it narrowly at each unit where the projects occurred. The Court held that the projects at issue were not routine and thus the exclusion did not apply.
In the second case, United States v. Duke Energy Company, the Court rejected the EPAs interpretation of the routine maintenance,



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repair and replacement exclusion, holding that the exclusion should be defined relative to what is routine for the particular industry, not what is routine
for the particular unit at issue. The Duke case also held that the government bears the burden of proof on the issue of whether a project at issue is routine.



Also in August 2003, the EPA issued a new rule, the Equipment Replacement Provision of the Routine Maintenance, Repair
and Replacement Exclusion, which became final in October. This rule specifies that the replacement of components of a process unit with identical components (or their functional equivalents) will fall within the scope of the routine
maintenance, repair and replacement exclusion if (i) the replacement cost is less than 20% of the total cost of replacing the unit, (ii) the replacement does not alter the units basic design and (iii) the unit will continue to comply with
applicable emission and operational standards.



None of the
Defendants other facilities are covered in the complaint and NOV, but the EPA previously requested information, that we provided, concerning activities at the Defendants Vermilion, Wood River and Hennepin plants as well as the Danskammer
and Roseton plants operated by other Dynegy subsidiaries. The EPA could eventually commence enforcement actions based on activities at these plants. However, the likelihood of additional enforcement actions is uncertain in light of the August 2003
public statement by the Acting Administrator of the EPA indicating that additional enforcement actions under the Utility Enforcement Initiative are unlikely and the November 2003 public statement by lawyers for the EPA that investigations into
several power plants for past Clean Air Act violations would likely be dropped and that future cases would be judged under the new rule.



California Market Litigation. Six class action lawsuits were filed in 2000-2001 against various Dynegy entities based on the events
occurring in the California power market. All six complaints allege violations of Californias Business and Professions Code, Unfair Trade Practices Act and other related statutes. The plaintiffs allege that the defendants, including the owners
of in-state generation and various power marketers, conspired to manipulate the California wholesale power market to the detriment of California consumers. The plaintiffs allege, among other things, improper sharing of generation outage data,
improper withholding of generation capacity and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages. Dynegy immediately removed and consolidated these cases to Federal court before Judge Robert Whaley on
the grounds of FERC preemption and the filed rate doctrine. The filed rate doctrine bars all claims challenging rates set by FERC under a market based system. FERC has reviewed and approved all of our market-based rate filings that were the subject
of the complaint.



The plaintiffs moved in opposition to
remand, and the cases were remanded to state court in July 2001. All six lawsuits were consolidated before Judge Sammartino, Superior Court Judge for the County of San Diego (the Gordon-Hendricks Cases). Subsequent to this consolidation,
two of the defendants filed cross-complaints against a number of corporations and governmental agencies that sold power in Californias wholesale energy markets. Four cross-defendants removed the six cases to the United States District Court
for the Southern District of California (San Diego) and the cases were returned to Multi-District Litigation Proceeding 1405, referred to as the California Wholesale Electricity Antitrust Litigation. The original plaintiffs in the six consolidated
complaints again filed motions to remand the consolidated cases back to state court, which motions were granted. Some of the cross-defendants then appealed that ruling and, prior to the remand taking effect, the Ninth Circuit Court of Appeals
granted review and stayed the remand order. A ruling by the Ninth Circuit is not expected until late this year at the earliest.



In April and October 2002, respectively, two additional cases, People of the State of California ex rel. Bill Lockyer, AG and Public Utility
District No. 1 of Snohomish County, were consolidated before Judge Whaley with the six cases referenced above pursuant to Multi-District Litigation Proceeding 1405. Dynegy filed motions to dismiss these cases on the grounds of FERC preemption
and the filed rate doctrine and, in March and January 2003, respectively, Judge Whaley dismissed with prejudice both cases. The plaintiffs have appealed both decisions;



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however, the decision on the appeal has been stayed pending a ruling on Mirant Corporations request, subsequent to filing bankruptcy, to continue to be
included in the disposition of these matters.



In addition to
the eight consolidated lawsuits discussed above, nine other putative class actions and/or representative actions were filed on behalf of business and residential electricity consumers against Dynegy and numerous other defendants between April and
October 2002 (T&E Pastorino Cases). The lawsuits were filed in various state courts and in the United States District Court for the Northern District of California. The defendants named in these lawsuits are various power generators
and marketers, including Dynegy and some of our affiliates. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek to enjoin illegal conduct, restitution and unspecified
damages. While some of the allegations in these lawsuits are similar to the allegations in the other six lawsuits, these lawsuits include additional allegations based on events occurring subsequent to the filing of the other six lawsuits. These
additional allegations include allegations similar to those made by the California Attorney General in the March 2002 lawsuit described below as well as allegations that contracts between these power generators and the CDWR constitute unfair
business practices resulting from market manipulation. The lawsuits filed in state court were removed to federal court (with one subsequently remanded) and ultimately these cases were added to the California Wholesale Electricity Antitrust
Litigation (proceeding 1405) in October 2002. The court granted our motion to dismiss the eight actions, although the plaintiffs have filed a notice of appeal of this dismissal. The ninth case, Millar v. Allegheny Energy Supply et al., was
recently remanded to state court and Dynegy is preparing to file a motion to dismiss these allegations.



In December 2002, two additional actions were filed with allegations similar to those in the California Wholesale Electricity Antitrust Litigation on
behalf of residents of the State of Washington and residents of the State of Oregon. Symonds v. Dynegy was filed in the United States District Court for the Western District of Washington. Lodewick v. Dynegy was originally filed in the
State Court of Oregon and was later removed to the United States District Court for the District of Oregon. Defendants in these matters sought to have these actions included in the California Wholesale Electricity Antitrust Litigation; however, the
Multi-District Litigation panel indicated that since Judge Whaley was a resident of the State of Washington, it was unlikely that the cases would be assigned to the California Wholesale Electricity Antitrust Litigation. In May 2003, the plaintiffs
voluntarily dismissed these actions and refiled them as Egger v. Dynegy Inc., et al. in the Superior Court of California in the County of San Diego as a class action complaint. The suit alleges violations of the Cartwright Act and unfair
business practices. The action is brought on behalf of consumers and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market. We have removed the action from state court
and consolidated it with existing actions pending before Judge Walker in the United States District Court for the Northern District of California. Most recently, the Attorney General for the State of Montana has filed a case alleging similar
antitrust and market manipulation claims styled People of the State of Montana ex rel. Mike McGrath v. Williams et al. Dynegy has not yet been served with this lawsuit.



In November 2002, a class action was filed in the Superior Court of the State of California for the County of Los Angeles
styled Cruz Bustamante v. The McGraw Hill Companies, Inc., et al. on behalf of purchasers of natural gas and electricity in the State of California. Plaintiffs alleged damages as the result of the defendants alleged false reporting of
pricing and volume information regarding natural gas transactions. In July 2003, the Court granted defendants motions to dismiss on the basis of FERC preemption and the filed-rate doctrine and dismissed the complaints as filed. The judge has
granted plaintiffs leave to amend, and plaintiffs filed their first amended complaint in August 2003. Defendants filed a motion to dismiss this complaint, with respect to which no ruling has been made.



We believe that we have meritorious defenses to these claims and intend to
defend against them vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the range of possible loss, if



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any, that we might incur in connection with this lawsuit. However, an adverse result in any of these proceedings could have a material adverse effect on our
financial condition, results of operations and cash flows.



FERC and Related Regulatory Investigations.



Requests for Refunds. In July 2001, the FERC initiated a hearing to establish refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2, 2000 through June 19,
2001. In particular, the FERC established a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets. During March 2002 and August 2002, hearings on this matter were held before an administrative law judge. In
December 2002, the administrative law judge issued his recommendations regarding the appropriate level of refunds or offsets. Those recommendations, however, do not fully reflect proposed refund or offset amounts for individual companies. In order
to determine such amounts, the Cal ISO and Cal PX must rerun their settlement processes in a compliance stage of the proceeding. We subsequently filed briefs with the FERC supporting certain aspects of the administrative law judges decision
and opposing others. The matter is awaiting a decision from the FERC.



In August 2002, the FERC requested comments on a proposal made by the FERC staff to change the method for determining natural gas prices for purposes of computing the mitigated market-clearing price that it intends to utilize in calculating
refunds for sales of power in California power markets during the period from October 2, 2000 to June 19, 2001. The proposal replaces the gas prices used in the computation, thus reducing the mitigated market clearing price for power and increasing
calculated refunds, subject to a provision that generally would provide full recoverability of gas costs paid by the generators to unaffiliated third parties. This proposal was adopted by the FERC in March 2003.



In November 2002, the FERC granted a motion filed jointly by the People of
the State of California, ex rel. Bill Lockyer, Attorney General, the California Electricity Oversight Board, the Public Utilities Commission of the State of California, Pacific Gas and Electric Company, and Southern California Edison Company,
referred to in this section as the California Parties, to reopen the record in the refund proceeding to allow 100 days of discovery into allegations of market manipulation. The California Parties sought increased refunds for the period from October
2, 2000 to June 19, 2001 based on, among other things, the adoption of the FERC staffs proposal to change the gas prices used in computing refunds. The California Parties also sought refunds for the period from May 1, 2000 through October 1,
2000. In March 2003, the FERC issued a decision in the refund case in which it essentially adopted the FERC staffs proposal to change the gas-pricing component of the refund calculations. The FERC did, however, recognize that many generators
paid higher prices for gas than would be reflected in this new calculation and provided a mechanism whereby generators can submit evidence of their actual out-of-pocket spot gas purchase costs and have those costs deducted from the refund
calculations. We intend to vigorously pursue relief under this procedure. The FERC otherwise affirmed the decision by the administrative law judge. A FERC determination on specific refunds and offsets to such refunds is still pending. In April 2003,
Dynegy sought rehearing of the FERCs decision changing the gas pricing methodology.



In June 2003, the FERC issued an order to show cause why the activities of certain participants in the California power markets from January 1, 2000 to June 20, 2001, including Dynegy, did not constitute gaming and/or
anomalous market behavior as defined in the Cal ISO and Cal PX tariffs. The order also requires that further trial proceedings be held to allow participants to demonstrate why they should not be found to have engaged in such gaming practices. In the
event that participants conduct is found to violate the tariffs, the order directs the administrative law judge to quantify the extent to which the participants were unjustly enriched by such practices and orders disgorgement of all such
profits from that period. Also in June 2003, the FERC issued an order requiring parties to demonstrate that certain bids did not constitute anomalous market behavior. Specifically, the order requires the FERC Staff to investigate all parties who bid
above the level of $250/MWH in the Cal ISO and Cal PX



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markets during the period from May 1, 2000 to October 2, 2000. Parties identified through this process will be required to demonstrate why this bidding
behavior did not violate market protocols. The order also states that, to the extent such practices are not found to be legitimate business behavior, the FERC will require the disgorgement of all unjust profits for that period and will consider
other non-monetary remedies, such as the revocation of market-based rate authority. We believe that we have meritorious defenses against these claims and intend to defend against them vigorously. See West Coast Power below for a
discussion of the reserves recorded by West Coast Power relative to its exposure in the California power market.



Other FERC and California Investigations. In February 2002, the FERC initiated an investigation of possible manipulation of natural gas and
power prices in the western United States during the period from January 2001 through the present. In May 2002, in response to three memoranda of a third party discovered by the FERC allegedly containing evidence of market manipulation in
California, the FERC issued requests for information to all sellers in the Cal ISO and Cal PX markets during 2000 and 2001, including Dynegy, seeking information with respect to whether those sellers engaged in trading strategies described in the
three memoranda. We responded to these requests, indicating that we did not engage in the trading strategies described in the three memoranda. In August 2002, the FERC staff issued its preliminary report on its investigation into trading practices
described in the three memoranda. We continue to provide FERC with additional information relevant to its investigation.



In March 2003, the FERC staff issued its Final Report on Price Manipulation in Western Markets, addressing a number of issues. In its report, the FERC
staff indicated that it appears a majority of public utility entities, and some non-public utilities, engaged in some of the above-referenced trading strategies during the two-year review period. The FERC staff also recommended that the FERC issue
orders requiring that Dynegy and 36 other market participants be required to show cause why their activities did not violate the Cal ISO and Cal PX tariffs. Potential penalties for violation of the tariff could include disgorgement of
unjust profits from activities found to be in violation of the tariff. Many of these allegations have already been raised and were answered in large part in our March 2003 FERC filing. We intend to defend against them vigorously.



As a part of its March report, FERC also directed the staff to conduct an
investigation into the physical withholding of power in California from May 1, 2000 through June 21, 2001. In August 2003, Dynegy and approximately 100 other companies were served with data requests by FERC staff. In issuing this notice of
investigation, FERC indicated that such Notice should not be interpreted to mean that FERC staff had found any conclusive evidence of withholding, but only that the staff had not concluded its review of Dynegy and other companies. Dynegy has
provided and continues to provide complete and accurate responses to such data requests.



In October 2003, FERC issued two orders addressing various issues raised in Petitions for Rehearing filed by Dynegy and other parties, relating to previous refund orders (including the aforementioned March 2003 order)
issued by FERC. We are currently evaluating if those orders will have any material impact on our operations.



In April 2003, the FERC issued an order adopting recommendations in its staffs March 2003 report that Dynegy and ten other companies be required to
submit information with respect to internal processes for reporting trading data to publications that publish energy indicesspecifically, that the employees involved in manipulations, or attempted manipulations, of the published indices have
been disciplined; that the company has a clear code of conduct in place for reporting price information; that all trade data reporting is done by an entity within the company that does not have a financial interest in the published indices
(preferably the chief risk officer); and that the company is cooperating fully with any government agency investigating its past reporting practices. We have complied and intend to continue complying with these requirements. Pursuant to the April
2003 order, we filed a written response indicating that we have ceased supplying price data to trade publications and are otherwise complying with the order.



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In September 2003, Dynegy and 265 other energy companies were required to respond to a survey from
FERC concerning the reporting of energy trade data covering trading activities for the period January 2002 through September 2003. The survey generally sought to elicit information on reporting of energy prices to publicly available energy indices
and the internal policies with respect to such reporting. We submitted our response to the survey in October 2003.



In October 2003, Dynegy Power Marketing, Inc. and subsidiaries of West Coast Power filed a Petition for Review in the United States Circuit Court of
Appeals for the District of Columbia Circuit, challenging numerous FERC orders relating to Dynegys refund liability and similar matters arising out of various energy transactions in California and elsewhere in the West for the period May 2000
to June 2001. Dynegy is unable to predict when the case will be heard or when a decision will be issued.



In May 2002, the FERC issued requests for information to all sellers of wholesale electricity or ancillary services in the WECC and to all sellers of
natural gas in the WECC or Texas, seeking information with respect to whether those sellers engaged in wash, round-trip or sale/buyback transactions during 2000-2001. We responded to each of these requests. Based
on our investigation to date, we believe that our trading practices are consistent with applicable law and tariffs. We will continue to cooperate fully with these investigations. See SEC Settlement below for a discussion of our
settlement with the SEC regarding, among other things, our previous round-trip energy trades with CMS Energy.



In August 2002, the FERC staff issued its preliminary report on its investigation into wash, roundtrip or sale/buyback
transactions. In the FERC staffs March 2003 Final Report on Price Manipulation in Western Markets, it recommended that the FERC establish specific rules banning any form of prearranged wash trading activities, but made no recommendations
regarding wash transactions specifically with respect to us.



Requests for similar information regarding the above-referenced trading strategies and wash trades with respect to electric power trading activities within the ERCOT were received from the PUCT in June 2002. We
responded to each of these requests. Based on our investigation to date, we believe that our trading practices are consistent with applicable law and tariffs. The PUCT has not issued findings on its investigation and we cannot predict with certainty
how the investigation will be resolved.



In September 2002,
California Public Utilities Commission President Loretta Lynch released a report indicating that Dynegy and five other energy firms did not produce all available power on days in which the State of California experienced power service interruptions
between November 1, 2000 and May 31, 2001. No mention is made of prosecuting the named firms in the report. However, the SEC and FERC have requested additional information and comment with respect to the report. In March 2003, the FERC staff issued
its analysis of the report and found that it was incomplete and overstated the amount of power withheld. The FERC staffs analysis further stated that there was no evidence that we withheld any material amounts of power or that we were
responsible for any service interruptions. The FERC subsequently asked for, and we submitted, data to demonstrate that we did not physically withhold power to influence prices.



Western Long-Term Contract Complaints. In February 2002, the California Public Utilities Commission and the
California Electricity Oversight Board filed complaints with the FERC asking that it void or reform power supply contracts between the CDWR and, among others, Dynegy Power Marketing Inc. The complaints allege that prices under the contracts exceed
just and reasonable prices permitted under the FPA. In June 2003 the FERC ruled that long-term contracts with the CDWR, including Dynegy Power Marketing Inc., were valid and would be upheld. However, that decision is subject to rehearing and appeal.



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In a related complaint, Kroger filed a complaint with the FERC in August 2002 asking that the four
wholesale contracts between DPM and AES New Energy, Inc., which provides retail service to Kroger, be declared void for their remaining terms, and that the FERC set just and reasonable rates for prior periods. Alternatively, Kroger asked that the
FERC allow for an annual review procedure to reset the contract prices. The complaint alleges that but for the dysfunctional California electricity markets, it would not have entered into the contracts for delivery of energy through December 2006.
In July 2003, Kroger and DPM reached a tentative settlement, subject to FERC approval, which was granted shortly thereafter. As a result of this settlement, we recorded a $30 million pre-tax, non-cash charge in our customer risk management segment
in the second quarter 2003, and we received approximately $110 million during the third quarter 2003 representing an accelerated payment under the terminated and restructured contracts, which were terminated in the third quarter 2003.



West Coast Power. Through our interest in West Coast Power, we
have credit exposure for past transactions to the Cal ISO and Cal PX, which primarily relied on cash payments from California utilities to in turn pay their bills. West Coast Power currently sells directly to the CDWR pursuant to a long-term sales
agreement.



At September 30, 2003, our portion of the
receivables owed to West Coast Power by the Cal ISO and Cal PX approximated $201 million. Management is continually assessing our exposure, as well as our exposure through West Coast Power, relative to our California receivables and establishes and
maintains reserves as necessary. Our share of the total reserve taken by West Coast Power at September 30, 2003 and December 31, 2002 was approximately $201 million.



Enron Trade Credit Litigation. As a result of Enrons bankruptcy filing, we recognized in our fourth
quarter 2001 financial statements a pre-tax charge related to our net exposure for commercial transactions with Enron. As of December 31, 2002, our net exposure to Enron, inclusive of certain liquidated damages and other amounts relating to the
termination of the transactions, was previously determined to approximate $84 million and was calculated by setting off approximately $230 million owed from various Dynegy entities to various Enron entities against approximately $314 million owed
from various Enron entities to various Dynegy entities. The master netting agreement between us and Enron and the valuation of the commercial transactions covered by the agreement, which valuation is based principally on the parties assessment
of market prices for such period, remain subject to dispute by Enron with respect to which there have been negotiations between the parties. These negotiations have focused on the scope of the transactions covered by the master netting agreement and
the parties valuations of those transactions. If any disputes cannot be resolved by the parties, the agreements call for arbitration. We have instituted arbitration proceedings against those Enron parties not in bankruptcy and have filed a
motion with the Bankruptcy Court requesting that we be allowed to proceed to arbitration against those Enron parties that are in bankruptcy. The Enron parties have responded by opposing our request to enforce the arbitration requirement and filing
an adversary proceeding against us. Both the opposition to the arbitration request and the adversary proceeding allege that the master netting agreement should not be enforced and that the Enron companies should recover approximately $230 million
from us. We have disputed such allegations and are vigorously defending our position regarding the setoff rights provided for in the master netting agreement, although no ruling has been made by the Bankruptcy Court. The Bankruptcy Court ordered the
disputes to non-binding mediation that occurred in September 2003, but the parties did not reach a settlement. If the setoff rights are modified or disallowed, either by agreement or otherwise, the amount available for Dynegy entities to set off
against sums that might be due Enron entities could be reduced materially; in fact, we could be required to pay to Enron the full amount that it claims to be owed. It is not possible to predict with certainty whether we will incur any liability in
connection with these disputes. However, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.



Trans-Elect Litigation. In October 2003, Trans-Elect, Inc. and Illinois Electric Transmission Company, LLC
filed suit against Illinois Power Company in the Northern District of Illinois requesting specific performance and estoppel, and claiming damages as a result of breach of contract and lost profits. These causes of action allegedly



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arise from Illinois Powers termination of an asset purchase and sale agreement entered into by the parties in October 2002. Under the terms of the
agreement, Illinois Power agreed to sell its transmission assets to Trans-Elect if, on or before July 7, 2003, the agreement received the required FERC, ICC, SEC and Hart-Scott Rodino approvals. As of July 7, 2003, the agreement had not been
approved by, among other entities, the FERC and, as a result, Illinois Power terminated the agreement in accordance with its terms on July 8, 2003. Trans-Elect claims that Illinois Power breached the agreement by failing to use its best
efforts to obtain the required approvals and/or to negotiate an alternate agreement that could be approved. We have until November 17, 2003 to respond to the plaintiffs complaint.



We deny these claims, in that we believe we complied with the terms of the
agreement, and intend to defend against them vigorously. It is not possible to predict with certainty whether we will incur any liability or estimate the damages, if any, that might be incurred in connection with this lawsuit. However, we do not
believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition or results of operations.



Severance Arbitrations. Dynegy Inc.s former CEO, Chuck Watson, former President, Steve Bergstrom, and
former CFO, Rob Doty, have each filed for arbitration pursuant to the terms of their employment/severance agreements. In each case, the parties disagree as to the amounts that may be owed pursuant to their respective agreements. These former
officers have made arbitration claims that seek payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. These agreements are subject to interpretation and Dynegy maintains that the amounts owed are substantially
lower than the amounts sought. In particular, the severance agreement with Mr. Bergstrom provides that the amounts identified in the agreement are not due him if material financial restatements have occurred or allegations of wrongdoing are made
against him by a state or federal law enforcement agency. We have recorded reserves in the event these arbitrations are decided adversely to Dynegy. At present, these arbitrations are scheduled to commence in March 2004 (Bergstrom) and June 2004
(Doty and Watson). We previously disclosed that in April 2003 we made a payment to the IRS of approximately $6 million associated with a tax obligation incurred by Mr. Watson in relation to a May 2002 stock option exercise. In October 2003, we made
a similar payment in the amount of approximately $2 million on Mr. Watsons behalf. It is intended that these tax payments will be offset against other payments, if any, determined to be owed to Mr. Watson as a result of the ongoing arbitration
proceedings between the parties.



Modesto
Litigation. In August 1998, the Modesto Irrigation District filed a lawsuit against PG&E and Destec Energy, Inc. (now known as Dynegy Power Corp.), which was previously acquired by Dynegy, in federal court for the Northern District of
California, San Francisco division. The lawsuit alleges violations of federal and state antitrust laws and state law tort and breach of contract claims against Destec relating to a power sale and purchase arrangement with the plaintiff in the City
of Pittsburg, California. While the plaintiffs pleadings indicate that it cannot measure its alleged damages with specificity, it has indicated that the actual damages sought from PG&E and Destec may exceed $25 million. Plaintiff also
seeks a trebling of any portion of damages related to its antitrust claims. After the District Court dismissed the plaintiffs antitrust claims in August 1999 and refused to assert pendent jurisdiction over the state law claims, the plaintiff
filed an appeal with the Ninth Circuit Court of Appeals and re-filed its state claims in state court. Plaintiff then agreed to execute a tolling agreement on the state law claims and to dismiss the state court case until the federal appeal was
decided. Plaintiff subsequently filed in the state court a request for dismissal, which the court granted.



Although PG&E filed a Chapter 11 bankruptcy proceeding in April 2001, the automatic stay applicable in the proceeding was lifted to permit the Ninth
Circuit to decide the pending appeal. In December 2002, the Ninth Circuit reversed the District Courts order dismissing the plaintiffs antitrust claims. In October 2003, we entered into settlement negotiations with the plaintiff, and in
November 2003, we entered into an agreement to settle the



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plaintiffs claims for $250,000. We will pay this settlement amount to the plaintiff when the terms of the settlement are finalized, which we anticipate
will occur in the fourth quarter 2003 or the first quarter 2004.



Farnsworth Litigation. In August 2002, Bradley Farnsworth filed a lawsuit against us in Texas state district court claiming breach of contract and that he was demoted and ultimately fired from the position of Controller for
refusing to participate in illegal activities. Specifically, Mr. Farnsworth alleges, in the words of his amended complaint, that certain of our former executive officers requested that he shave or reduce for accounting purposes the
forward price curves associated with the natural gas business in the United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a reduction in our mark-to-market losses. He also claims that Project Alpha and the
round-trip trades provide evidence to support his theory that these same former executive officers were engaged in a conspiracy to manipulate Dynegys financial results and statements. Mr. Farnsworth, who seeks unspecified actual and exemplary
damages and other compensation, also alleges that he is entitled to a termination payment under his employment agreement equal to 2.99 times the greater of his average base salary and incentive compensation for the highest three calendar years
preceding termination or his base salary and target bonus amount for the year of termination (currently estimated at a range of approximately $700,000 to $1,200,000). We believe that we have meritorious defenses against these claims and intend to
defend against them vigorously. Dynegy filed a motion for summary judgment on all claims in early October 2003, and the case is set for trial in January 2004. Although we have recorded a reserve with respect to this litigation, we do not believe
that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations and cash flows.



Apache Litigation. In May 2002, Apache Corporation filed suit in Harris County, Texas district court against
Versado as purchaser and processor of Apaches gas, and against DMS as operator of the Versado assets in New Mexico. The suit, which followed an Apache audit of Versados books and records relating to the parties commercial
transactions, originally sought approximately $3.9 million in damages. Under an agreed court order, Versado analyzed the results of the Apache audit and voluntarily paid approximately $1.35 million to Apache in the third quarter of 2002. Apache has
since amended its petition to allege Versado still owes it a total of more than $9 million. These new claims include allegations that Versado engages in sham transactions with affiliates, which result in Versado not receiving fair market
value when it sells gas and liquids. They also allege, among other things, that the formula for calculating the amount Versado receives from its buyers of gas and liquids is flawed since it is based on gas price indexes that these same affiliates
are alleged to have manipulated by providing false price information to the index publisher. Versado intends to defend against these claims vigorously and believes it has meritorious defenses. In May 2003, we filed a motion for partial summary
judgment relating to lost gas and related matters. The Court granted substantially all of our motions in September 2003. Trial on the remaining items will likely occur in the first quarter 2004, but the Court has not set a firm trial date. Although
we have recorded a reserve with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations and cash flows.



Sierra Pacific Litigation. In April 2003, Sierra
Pacific Resources and Nevada Power Company filed suit against various sellers of natural gas, including some of our subsidiaries, in the United States District Court for the District of Nevada and, in July 2003, filed an amended petition in the
action. In the suit, plaintiffs claim that they purchased natural gas from us to produce electricity for their customers at artificially high prices based on published index prices at the California-Arizona border market. Plaintiffs claim that we
were part of a conspiracy to restrict natural gas transmission capacity on the El Paso pipeline system, which in turn raised the California border price. Plaintiffs allege, although without specificity, that we withheld capacity from the market in
concert with El Paso and that there was an illicit agreement between the other defendants, El Paso and us to decrease output and raise prices in violation of the Nevada Unfair Trade Practices Act. Plaintiffs seek an award of unspecified
treble damages with respect to these claims based on the alleged excess natural gas costs they incurred.



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Plaintiffs further allege that we intentionally misrepresented natural gas prices and volumes to
trade publications that compile and report index prices in an effort to induce plaintiffs to enter into contracts for the purchase of natural gas at artificially high prices, as well as associated hedging transactions, and that Nevada Power did in
fact rely on the misinformation suffering damage as a result of such reliance. Plaintiffs further claim that we conspired with El Paso to provide this false information, and that our misconduct constitutes fraud and violates Nevadas
Racketeering Influenced Corrupt Organizations Act. Plaintiffs seek an award of unspecified treble damages with respect to these claims.



In September 2003, we filed a motion to dismiss the claims, and the plaintiffs are expected to respond in November 2003. We are analyzing these claims and
intend to defend against them vigorously. It is not possible to predict with certainty whether we will incur any liability or to estimate the range of possible loss, if any, that we might incur in connection with this lawsuit. However, we do not
believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Other Index Pricing Litigation. In addition to the Sierra Pacific suit described above, we and DMT were named
as defendants in April 2003 in a third-party complaint in a lawsuit originally initiated by Nelson Brothers, LLC against Cherokee Nitrogen in Alabama state court. The underlying suit relates to an agreement between Cherokee and Nelson Brothers
pursuant to which Cherokee allegedly agreed to supply ammonium nitrate to Nelson Brothers and to use its commercially reasonable efforts to reduce its supply costs. When Nelson Brothers sued Cherokee under their agreement, Cherokee filed a
third-party complaint alleging that it purchased natural gas from DMT based on index pricing and, citing the December 2002 settlement with the CFTC, that the index prices used were artificially inflated by DMT due to fraudulent and inaccurate
reporting to index services, which resulted in higher costs that it passed on to Nelson Brothers. Cherokee claims that DMT is liable to it for alleged overcharges and seeks actual and punitive damages in unspecified amounts. We filed a motion
to dismiss this action on grounds of FERC preemption, which motion is set for hearing in December 2003. We believe we have meritorious defenses to these claims and intend to defend against them vigorously. It is not possible to predict with
certainty whether we will incur any liability or to estimate the range of possible loss, if any, that we might incur in connection with this lawsuit. However, we do not believe that any liability we might incur as a result of this litigation would
have a material adverse effect on our financial condition, results of operations or cash flows.



Cornerstone Propane Partners. In August 2003, Cornerstone Propane Partners, L.P. filed a putative class action in the United States District
Court for the Southern District of New York, naming, among the approximately 40 defendants, Dynegy Marketing & Trade, DHI and Dynegy Inc. The complaint alleges that during the class period from January 1, 2000 to December 31, 2002, defendants
unlawfully manipulated the prices of natural gas futures and options contracts traded on the New York Mercantile Exchange through, among other things, deliberately reporting inaccurate, misleading and false trading information to industry trade
publications that compile and publish indices of natural gas prices. In addition, plaintiff alleges that defendants engaged in a variety of trades, including wash trades, whose sole purpose was to create the perception of increased liquidity and
demand for natural gas. We responded to plaintiffs complaint on November 11, 2003.



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



Triad Energy Litigation. In March 2003, Triad Energy Resources
Corp. and five other alleged representatives of two plaintiffs classes filed a putative antitrust class action against NiSource Inc. and other defendants, including Dynegy, in the United States District Court for the District of Columbia. The
plaintiffs purport to represent classes of purchasers, marketers, wholesalers, managers, sellers and shippers of natural gas that



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allegedly were damaged by an illegal gas scheme devised by three federally regulated interstate pipeline systems: Columbia Gas Transmission Corporation,
Columbia Gulf Transmission Company, and The Cove Point LNG Limited Partnershipall of which now are owned by NiSource, and certain shippers on these pipelines.



The complaint alleges violations of the federal antitrust laws and common law tortious interference with contractual and
business relations. It alleges that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate in violation of FERC regulations and, in return, received percentages of the profits
reaped by the marketing affiliate. The complaint also alleges that certain shippers, including us, having learned of the Columbia arrangements, demanded and received similar preferential storage and transportation services that were not available to
all shippers.



Although this alleged scheme was the subject of
a FERC order issued in October 2000, which order required the Columbia companies to pay $27.5 million to certain customers of Columbia Gas and Columbia Gulf, plaintiffs claim that the FERC order did not remedy the competitive injury to plaintiffs
caused by the scheme. The complaint seeks aggregate damages of approximately $1.716 billion (divided approximately $1.034 billion and $682 million between two plaintiffs classes). Under the federal antitrust laws, damages are subject to
trebling. We are analyzing these claims and intend to defend against them vigorously. In October 2003, the court granted defendants motion to dismiss for lack of jurisdiction and allowed time for the plaintiff to amend its complaint. The
plaintiff has since filed a motion to voluntarily dismiss its complaint and indicated an intent to refile in a proper jurisdiction. It is not possible to predict with certainty whether we will incur any liability or to estimate the damages, if any,
that we might incur in connection with this lawsuit.



Maxus Litigation. In June 2002, DMS, as successor to Natural Gas Clearinghouse, the defendant in the trial below, argued its appeal in the case of Natural Gas Clearinghouse v. Midgard Energy, formerly known as Maxus
Exploration Co. This appeal was made in response to an adverse judgment received in the District Court of Potter County, Texas in April 2001. In the lower court, DMS was found liable for failing to deliver processable wet gas to a
processing plant in Oklahoma owned by Maxus and DMSs third party action against Transok Inc. for causing it to breach the processing contract was decided adversely to us. The judgment was appealed and, in May 2003, was upheld in part. We
thereafter filed an expedited writ with the Texas Supreme Court seeking further review. We have established a reserve in connection with this matter, although we do not believe that any liability we might incur would have a material adverse effect
on our financial condition, results of operations and cash flows.



Alleged Marketing Contract Defaults. We have posted collateral to support a substantial portion of our obligations in our customer risk management business, including our obligations under some of our power tolling
arrangements. While we have been working with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power
LLC regarding a mutually acceptable amount of collateral in support of our obligations under our power tolling arrangements with either of these two parties. Although we are current on all contract payments to these counterparties, we previously
received a notice of default from each such party with regard to collateral. Despite receiving these notices, all parties are continuing to perform and we have fulfilled our economic commitments under these contracts. Our average annual capacity
payments under these two arrangements approximate $75 million and $63 million, respectively, and the contracts extend through 2014 and 2012, respectively. If these two parties were successfully to pursue claims that we defaulted on these contracts,
they could declare a termination of their respective contracts, which provide for termination payments based on the agreed mark-to-market value of the contracts. Because of the effects of changes in commodity prices on the mark-to-market value of
these contracts, as well as the likelihood that we would differ with our counterparties as to the estimated value of these contracts, we cannot predict with any degree of certainty the amounts of termination payments that could be required under
these two contracts. Disputes relating to these two contracts, if resolved against us, could materially adversely affect our financial condition, results of operations and cash flows.



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In addition, we are involved in disputes with some of our other counterparties relating to contracts
with respect to which we were unable to agree on mutually acceptable collateral or other adequate assurance. We intend to defend against these claims vigorously and, while we could be required to post additional amounts of collateral, we do not
expect that any liability we might incur in connection with these disputes will materially adversely affect our financial condition, results of operations or cash flows.



U.S. Attorney Investigations. The U.S. Attorneys office in Houston has commenced an investigation of our
actions relating to Project Alpha, round-trip trades with CMS Energy and our gas trade reporting practices. We have produced documents and witnesses for interviews in connection with this investigation. Six of our natural gas traders were dismissed
in October 2002 for violating our Code of Business Conduct after an ongoing internal investigation conducted by our Audit and Compliance Committee in collaboration with independent counsel discovered that inaccurate information regarding natural gas
trades had been reported to various energy industry publications. In January 2003, one of our former natural gas traders was indicted in Houston on three counts of knowingly causing the transmission of false trade reports used to calculate the index
price of natural gas and four counts of wire fraud. In August 2003, however, several of these counts were dismissed as unconstitutional. The U.S. Attorneys office has filed a motion asking the court to reconsider its decision, and the court
has not yet ruled on that motion.



In June 2003, three former
Dynegy employees were indicted on charges of conspiracy, securities fraud, mail and wire fraud related to the Project Alpha transaction. Subsequently, two of such former employees pleaded guilty to conspiracy to commit securities fraud. Trial on the
indictment against the third employee commenced on November 3, 2003. We are cooperating fully with the U.S. Attorneys office in its continuing investigation of both of these matters and cannot predict the ultimate outcome of these
investigations.



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



Nicor Energy Investigations. We
own a 50% interest in Nicor Energy, a joint venture with Nicor Inc. that marketed retail gas and electricity in the Midwest. During the first quarter 2003, substantially all of the operations of Nicor Energy were sold, and we substantially
liquidated the company in the second quarter 2003. We historically provided gas and electricity to Nicor Energy for resale to its retail customers; however, we ceased providing gas to Nicor Energy in March 2003 in connection with our exit from
third-party marketing and trading and ceased providing electricity to Nicor Energy in the second quarter 2003 in connection with its assignment of our wholesale electricity contracts to the purchasers of its retail electricity business. In March
2003, Nicor Inc. publicly announced that it expects the SEC to bring civil charges against Nicor Energy based on alleged violations of standard financial reporting relating to unbilled revenues and unrecorded liabilities, including fraud and
maintaining false books and records. The U.S. Attorney for the Northern District of Illinois has also notified Nicor Energy that it is conducting an inquiry on these same matters, and that a grand jury is also reviewing these matters. We intend to
cooperate with these investigations and cannot predict their ultimate outcomes.



Nicor Inc. previously revealed irregularities in accounting at Nicor Energy. We reflected a $5.6 million pre-tax charge in the fourth quarter 2001 relating to our investment in Nicor Energy as a result of these
matters.



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 Inc. and its ERISA affiliates. We have cooperated with the Department of Labor
throughout this investigation, which remains



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ongoing. As of this date, the investigation has focused on a review of plan documentation, plan reporting and disclosure, plan recordkeeping, plan
investments and investment options, plan fiduciaries and third-party service providers, plan contributions and other operational aspects of the plans. We have not yet received the Department of Labors definitive findings resulting from its
investigation.



Enron Merger Termination
Litigation. Dynegy and DHI were sued in December 2001 by Enron and Enron Transportation Services Co. in the United States Bankruptcy Court for the Southern District of New York, Adversary Proceeding No. 01-03626 (AJG). Enron claimed that
Dynegy materially breached the Merger Agreement dated November 9, 2001 between Enron and Dynegy and related entities by wrongfully terminating that Agreement on November 28, 2001. Enron also claimed that we wrongfully exercised our option to take
ownership of Northern Natural under an Option Agreement dated November 9, 2001. Enron sought damages in excess of $10 billion and declaratory relief against Dynegy for breach of the Merger Agreement. Enron also sought unspecified damages against
Dynegy and DHI for breach of the Option Agreement.



In August
2002, we entered into an agreement with Enron to settle this lawsuit. Under the terms of the settlement agreement, we agreed to pay Enron $25 million, $10 million of which was paid to Enron upon approval of the settlement agreement by the Bankruptcy
Court, with the remaining $15 million escrowed until approval of the settlement becomes final. In addition, we agreed with Enron to exchange mutual releases of any and all claims related to the terminated merger and to dismiss the related
litigation. We also agreed not to pursue any claims for working capital adjustments relating to the acquisition of Northern Natural. The terms of the settlement were subsequently approved by the Bankruptcy Court. Following an appeal and subsequent
court proceedings, Enrons claims were dismissed with prejudice.



Ann C. Pearl and Joel Getzler also filed a suit against Dynegy and DHI in the United States District Court for the Southern District of New York. Plaintiffs filed the lawsuit as a purported class action on behalf of all persons or entities
that owned Enron common stock as of November 28, 2001. A similar suit was filed by Bernard D. Shapiro and Peter Strub in the 129th Judicial District Court for Harris County, Texas. Plaintiffs in each case alleged that they were intended third-party
beneficiaries of the Merger Agreement dated November 9, 2001 among Enron, Dynegy and related entities. Plaintiffs claimed that we materially breached the Merger Agreement by, among other things, wrongfully terminating that agreement. Plaintiffs also
claimed that we breached the implied covenant of good faith and fair dealing. Plaintiffs sought unspecified damages and other relief. Enron moved for an order from the Bankruptcy Court in the Southern District of New York directing that the Pearl
and Shapiro plaintiffs be enjoined from prosecuting their actions and that their actions be immediately dismissed.



In April 2003, we executed a settlement agreement with the former Enron shareholder plaintiffs relating to the purported class action lawsuits described
above. Pursuant to the settlement agreement, which was approved by the court in September 2003, we agreed to pay $6 million to settle the claims asserted on behalf of the class of all Enron shareholders who held Enron stock at the time the merger
was terminated. We previously deposited the $6 million into escrow with the court and, provided the courts ruling approving the settlement agreement is not appealed, this amount will be paid to the plaintiffs in December 2003, when the
settlement is final. We have a unilateral right to terminate the settlement agreement if any class members opt out of the settlement class.



Telstra Litigation. In January 2002, Telstra Corporation, Ltd. and Telstra Wholesale Inc., which we collectively refer to as Telstra, filed
suit in Delaware Chancery Court against DynegyConnect, L.P., a limited partnership in which Dynegy acquired a combined 80% interest, as well as some of our other affiliates. DynegyConnect is a vehicle established by us to participate in the U.S.
telecommunications business. Telstra Wholesale originally acquired the remaining 20% interest in DynegyConnect pursuant to a limited partnership agreement that was executed in October 2000 and details the partners rights and obligations. Under
the agreement, Telstra Wholesale was granted a put option permitting it to require Dynegy or its designee, at any time on or before



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September 20, 2002, to purchase its 20% partnership interest for a purchase price equal to the value of Telstra Wholesales capital account in
DynegyConnect, subject to certain adjustments. The plaintiffs brought this action in connection with Telstra Wholesales attempted exercise of this put option. The plaintiffs alleged breach of contract and bad faith, among other things, in
connection with the valuation of Telstra Wholesales capital account and, as a result, the put option purchase price, as well as the administration of the partnership. The plaintiffs sought approximately $50 million plus interest in damages
together with fees and other litigation expenses. Previously, Minority Interest on our condensed consolidated balance sheets included amounts relating to Telstra Wholesales investment in DynegyConnect, which amounts equaled the fair value of
Telstra Wholesales put option. During the fourth quarter 2002, based on the status of the litigation, this Minority Interest liability was reclassified to a current liability, which reclassification had no impact on net income, and we accrued
an additional $15 million reserve.



In March 2003, the parties
agreed to settle this lawsuit. Pursuant to the terms of the settlement agreement, we agreed to acquire Telstra Wholesales minority interest in DynegyConnect effective as of September 19, 2001 in exchange for $45 million in cash, $10 million of
which was paid in March 2003 and the remaining $35 million of which was paid in April 2003.



SEC Settlement. In September 2002, we announced a settlement with the SEC of allegations made in connection with the previously disclosed investigation relating to Project Alpha and round-trip
electricity trades with CMS Energy. In the settlement, the SEC found that we engaged in securities fraud in connection with our disclosures and accounting for Project Alpha, and negligently included materially misleading information about the
round-trip energy trades with CMS Energy in two press releases we issued in early 2002. In settlement of the SECs enforcement action, Dynegy, without admitting or denying the SECs findings, agreed to the entry of a cease-and-desist order
and to pay a $3 million penalty in a related civil suit filed in the United States District Court in Houston, Texas. We are continuing to cooperate with the SECs ongoing investigation of other parties related to Project Alpha. In June 2003,
the SEC instituted civil proceedings against three former Dynegy employees for conduct related to the Project Alpha transaction.



Note 10Regulatory Issues



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



Note 11Segment Information



As reflected in this report, we have changed our reportable segments. In
2002, we reported results for the following four business segments:



| |  | Wholesale Energy Network, or WEN;
| | - | ---------------------------------



| |  | Dynegy Midstream Services, or DMS;
| | - | ----------------------------------



| |  | Transmission and Distribution, or T&D; and
| | - | ------------------------------------------



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| |  | Dynegy Global Communications, or DGC.
| | - | -------------------------------------



Beginning January 1, 2003, we are reporting our operations in the following segments:



| |  | Power generation, or GEN;
| | - | -------------------------



| |  | Natural gas liquids, or NGL;
| | - | ----------------------------



| |  | Regulated energy delivery, or REG; and
| | - | --------------------------------------



| |  | Customer risk management, or CRM.
| | - | ---------------------------------



Prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business,
then referred to as the WEN segment. Most, but not all, of the WEN third-party purchase and sale contracts were held by a subsidiary which is currently included within the CRM segment. Under this business model, the net fair value of most of
GENs generation capacity, forward sales and related trading positions were sold to the CRM segment monthly at an internally determined transfer price. The internal transfer price was primarily comprised of the option value of generation
capacity and executed forward sales contracts based on then-current forward prices of power and fuel. GEN intersegment revenues for the three- and nine-month periods ended September 30, 2002 reflect this internal transfer price and do not represent
amounts actually received for power sold to third parties. As such, the GEN intersegment revenues for the three- and nine-month periods ended September 30, 2002 do not include the effect of intra-month market price volatility. The CRM segment
recorded net unaffiliated revenue from these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment.



In connection with our exit from the third-party marketing and trading business, individual contracts within the former WEN
segment were identified on January 1, 2003 as either GEN contracts, as they were determined to be a part of our continuing operations, or CRM contracts. Under this new business segment model, CRM continues to transact with third parties on behalf of
GEN for contracts which were identified as GEN contracts, as well as new transactions executed on behalf of GEN but for which CRM is the legal party to the third-party purchase and sale contract. CRM continues to record net unaffiliated revenue from
these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment. However, rather than purchasing such capacity, forward sales and related trading positions from GEN at an
internally determined transfer price, pricing between CRM and GEN is set at the actual amount received or paid for the purchases and sales to the third parties. Therefore, GEN intersegment revenues for the three- and nine-month periods ended
September 30, 2003 include the effects of intra-month market price volatility.



Prior to January 1, 2003, consolidated revenue associated with the retail power business represented energy trading activity that was recorded on a net basis. The GEN segment purchased from the CRM segment a portion
of the physical power that was used to fill these retail power sales contracts. The revenues from retail power sales were presented gross in GEN unaffiliated revenues, with the corresponding power purchases from the CRM segment presented in GEN
intersegment revenues. Beginning January 1, 2003, pursuant to the rescission of EITF Issue 98-10, retail power sales are presented gross in consolidated revenue. Any purchases of physical power by the GEN segment from the CRM segment are classified
as cost of sales in the GEN segment and are presented in CRM intersegment revenues. These differences affect the comparability of the results for the three- and nine-month periods ended September 30, 2003 and 2002.



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For the Interim Periods Ended September 30, 2003 and 2002



Revenues from third-party sales in which GEN is the legal party to the third-party sales contracts
are presented gross in GEN unaffiliated revenues for the three- and nine-month periods ended September 30, 2003 and 2002.



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



Prior to January 1, 2003, our natural gas liquids operations comprised our
Dynegy Midstream Services segment. Beginning January 1, 2003, these operations comprise the NGL segment. Additionally, prior to January 1, 2003, we reported our Illinois Power utility operations and, for the first three quarters of 2002 prior to its
sale, the operations of Northern Natural in our Transmission and Distribution segment. Beginning January 1, 2003, our Illinois Power utility operations comprise the REG segment. Results associated with the former DGC segment are included in
discontinued operations due to the sale of our communications businesses. Reportable segment information for the three- and nine-month periods ended September 30, 2003 and 2002 is presented below.



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

(in millions)



|                                                                  |  | GEN |       |   | NGL |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|----------------------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | ----- | - |  | --------------------- | ----- | - | ----- | -
|Unaffiliated revenues:                                            |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                          |  | $   | 65    |   |     | $ | 620   |     |  | $ | 394   |   |  | $                     | 352   |   |       | $
|Other                                                             |  |     |      |   |     |   | 3     |     |  |   |      |   |  |                       | (49   | ) |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     | 65    |   |     |   | 623   |     |  |   | 394   |   |  |                       | 303   |   |       |  
|Intersegment revenues                                             |  |     | 410   |   |     |   | 58    |     |  |   | 8     |   |  |                       | (301  | ) |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Total revenues                                                    |  | $   | 475   |   |     | $ | 681   |     |  | $ | 402   |   |  | $                     | 2     |   |       | $
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |  
|Depreciation and amortization                                     |  | $   | (48   | ) |     | $ | (19   | )   |  | $ | (30   | ) |  | $                     |      |   |       | $
|                                                                  |  |     |       |   |     |  
|Operating income (loss)                                           |  | $   | 77    |   |     | $ | 31    |     |  | $ | 64    |   |  | $                     | (26   | ) |       | $
|Earnings (losses) from unconsolidated investments                 |  |     | 51    |   |     |   | 2     |     |  |   |      |   |  |                       | (2    | ) |       |  
|Other items, net                                                  |  |     | 1     |   |     |   | (2    | )   |  |   |      |   |  |                       | 4     |   |       |  
|Interest expense                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |  
|Income from continuing operations before taxes                    |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Income tax provision                                              |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Income from continuing operations                                 |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |  
|Income on discontinued operations, net of taxes                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Net income                                                        |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |  
|Identifiable assets:                                              |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                          |  | $   | 6,380 |   |     | $ | 1,679 |     |  | $ | 5,408 |   |  | $                     | 2,357 |   |       | $
|Other                                                             |  |     |      |   |     |   |      |     |  |   |      |   |  |                       | 297   |   |       |  
|                                                                  |  |     |       |   |     |  
|Unconsolidated investments                                        |  |     | 573   |   |     |   | 95    |     |  |   |      |   |  |                       |      |   |       |  
|                                                                  |  |     |       |   |     |  
|Capital expenditures and investments in unconsolidated affiliates |  |     | (24   | ) |     |   | (11   | )   |  |   | (33   | ) |  |                       |      |   |       |  



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Dynegys Segment Data for the Quarter Ended September 30, 2002

(in millions)



|                                                                  |  | GEN |       |   | NGL |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|----------------------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | ----- | - |  | --------------------- | ----- | - | ----- | -
|Unaffiliated revenues:                                            |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                          |  | $   | 311   |   |     | $ | 574   |     |  | $ | 396   |   |  | $                     | (72   | ) |       | $
|Other                                                             |  |     | 1     |   |     |   | 130   |     |  |   |      |   |  |                       | (42   | ) |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     | 312   |   |     |   | 704   |     |  |   | 396   |   |  |                       | (114  | ) |       |  
|Intersegment revenues                                             |  |     | 99    |   |     |   | 39    |     |  |   | 6     |   |  |                       | 88    |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Total revenues                                                    |  | $   | 411   |   |     | $ | 743   |     |  | $ | 402   |   |  | $                     | (26   | ) |       | $
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Depreciation and amortization                                     |  | $   | (47   | ) |     | $ | (22   | )   |  | $ | (39   | ) |  | $                     | (7    | ) |       | $
|Goodwill impairment                                               |  |     | (549  | ) |     |   |      |     |  |   |      |   |  |                       | (348  | ) |       |  
|Impairment and other charges                                      |  |     |      |   |     |   |      |     |  |   |      |   |  |                       | (25   | ) |       |  
|                                                                  |  |     |       |   |     |  
|Operating income (loss)                                           |  | $   | (495  | ) |     | $ | 29    |     |  | $ | 72    |   |  | $                     | (482  | ) |       | $
|Earnings (losses) from unconsolidated investments                 |  |     | (112  | ) |     |   | 3     |     |  |   |      |   |  |                       | (10   | ) |       |  
|Other items, net                                                  |  |     | (14   | ) |     |   | (9    | )   |  |   | (3    | ) |  |                       | (16   | ) |       |  
|Interest expense                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss from continuing operations before taxes                      |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Income tax benefit                                                |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss from continuing operations                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss on discontinued operations, net of taxes                     |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Net loss                                                          |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Identifiable assets:                                              |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                          |  | $   | 6,922 |   |     | $ | 1,955 |     |  | $ | 3,593 |   |  | $                     | 7,989 |   |       | $
|Other                                                             |  |     | 104   |   |     |   | 25    |     |  |   |      |   |  |                       | 3,032 |   |       |  
|                                                                  |  |     |       |   |     |  
|Unconsolidated investments                                        |  |     | 600   |   |     |   | 116   |     |  |   |      |   |  |                       |      |   |       |  
|                                                                  |  |     |       |   |     |  
|Capital expenditures and investments in unconsolidated affiliates |  |     | (73   | ) |     |   | (31   | )   |  |   | (52   | ) |  |                       |      |   |       |  



50



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



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

(in millions)



|                                                                   |  | GEN |       |   | NGL |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|------------------------------------------------------------------ |  | --- | ----- | - | --- | - | ----- | --- |  | - | ----- | - |  | --------------------- | ----- | - | ----- | -
|Unaffiliated revenues:                                             |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                           |  | $   | 286   |   |     | $ | 2,217 |     |  | $ | 1,170 |   |  | $                     | 697   |   |       | $
|Other                                                              |  |     |      |   |     |   | 3     |     |  |   |      |   |  |                       | (46   | ) |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     | 286   |   |     |   | 2,220 |     |  |   | 1,170 |   |  |                       | 651   |   |       |  
|Intersegment revenues                                              |  |     | 940   |   |     |   | 193   |     |  |   | 22    |   |  |                       | (790  | ) |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Total revenues                                                     |  | $   | 1,226 |   |     | $ | 2,413 |     |  | $ | 1,192 |   |  | $                     | (139  | ) |       | $
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Depreciation and amortization                                      |  | $   | (138  | ) |     | $ | (60   | )   |  | $ | (91   | ) |  | $                     | (1    | ) |       | $
|                                                                   |  |     |       |   |     |  
|Operating income (loss)                                            |  | $   | 176   |   |     | $ | 121   |     |  | $ | 158   |   |  | $                     | (348  | ) |       | $
|Earnings from unconsolidated investments                           |  |     | 135   |   |     |   | 7     |     |  |   |      |   |  |                       |      |   |       |  
|Other items, net                                                   |  |     | 4     |   |     |   | (12   | )   |  |   |      |   |  |                       | 27    |   |       |  
|Interest expense                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss from continuing operations before taxes                       |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Income tax benefit                                                 |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss from continuing operations                                    |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss on discontinued operations, net of taxes                      |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Cumulative effect of change in accounting principles, net of taxes |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Net loss                                                           |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Identifiable assets:                                               |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                           |  | $   | 6,380 |   |     | $ | 1,679 |     |  | $ | 5,408 |   |  | $                     | 2,357 |   |       | $
|Other                                                              |  |     |      |   |     |   |      |     |  |   |      |   |  |                       | 297   |   |       |  
|                                                                   |  |     |       |   |     |  
|Unconsolidated investments                                         |  |     | 573   |   |     |   | 95    |     |  |   |      |   |  |                       |      |   |       |  
|                                                                   |  |     |       |   |     |  
|Capital expenditures and investments in unconsolidated affiliates  |  |     | (117  | ) |     |   | (36   | )   |  |   | (101  | ) |  |                       |      |   |       |  



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Dynegys Segment Data for the Nine Months Ended September 30, 2002

(in millions)



|                                                                   |  | GEN |       |   | NGL |   |       | REG |  |   | CRM   |   |  | Other andEliminations |       |   | Total |  
|------------------------------------------------------------------ |  | --- | ----- | - | --- | - | ----- | --- |  | - | ----- | - |  | --------------------- | ----- | - | ----- | -
|Unaffiliated revenues:                                             |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                           |  | $   | 472   |   |     | $ | 1,801 |     |  | $ | 1,113 |   |  | $                     | 92    |   |       | $
|Other                                                              |  |     | 4     |   |     |   | 722   |     |  |   |      |   |  |                       | (138  | ) |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     | 476   |   |     |   | 2,523 |     |  |   | 1,113 |   |  |                       | (46   | ) |       |  
|Intersegment revenues                                              |  |     | 634   |   |     |   | 115   |     |  |   | 27    |   |  |                       | (137  | ) |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Total revenues                                                     |  | $   | 1,110 |   |     | $ | 2,638 |     |  | $ | 1,140 |   |  | $                     | (183  | ) |       | $
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Depreciation and amortization                                      |  | $   | (117  | ) |     | $ | (63   | )   |  | $ | (113  | ) |  | $                     | (15   | ) |       | $
|Goodwill impairment                                                |  |     | (549  | ) |     |   |      |     |  |   |      |   |  |                       | (348  | ) |       |  
|Impairment and other charges                                       |  |     | (11   | ) |     |   | (5    | )   |  |   | (7    | ) |  |                       | (44   | ) |       |  
|Operating income (loss)                                            |  | $   | (376  | ) |     | $ | 83    |     |  | $ | 168   |   |  | $                     | (809  | ) |       | $
|Earnings (losses) from unconsolidated investments                  |  |     | (50   | ) |     |   | 10    |     |  |   | (1    | ) |  |                       | (25   | ) |       |  
|Other items, net                                                   |  |     | (29   | ) |     |   | (20   | )   |  |   | (3    | ) |  |                       | (29   | ) |       |  
|Interest expense                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss from continuing operations before taxes                       |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Income tax benefit                                                 |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss from continuing operations                                    |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Loss on discontinued operations, net of taxes                      |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Cumulative effect of change in accounting principles, net of taxes |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Net loss                                                           |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Identifiable assets:                                               |  |     |       |   |     |   |       |     |  |   |       |   |  |                       |       |   |       |  
|Domestic                                                           |  | $   | 6,922 |   |     | $ | 1,955 |     |  | $ | 3,593 |   |  | $                     | 7,989 |   |       | $
|Other                                                              |  |     | 104   |   |     |   | 25    |     |  |   |      |   |  |                       | 3,032 |   |       |  
|Unconsolidated investments                                         |  |     | 600   |   |     |   | 116   |     |  |   |      |   |  |                       |      |   |       |  
|Capital expenditures and investments in unconsolidated affiliates  |  |     | (483  | ) |     |   | (84   | )   |  |   | (124  | ) |  |                       | (18   | ) |       |  



Note 12Pension Plan Assets



As a result of general declines in interest rates,
projected plan obligations at year-end are expected to continue to be greater than the market value of pension plan assets. If any of our pension plans are underfunded at year-end 2003 by a greater amount than at year-end 2002, we have two
alternatives. The first alternative is to contribute cash to the plan in an amount equal to the underfunded amount. The second alternative is to establish a liability equal to the underfunded amount with the offset being an after-tax reduction in
stockholders equity. Determination of any underfunded amount will be made at year-end 2003, and will be dependent on the actual return on pension assets for 2003, the discount rate assumptions, which depend on year-end interest rates, and
actual participant numbers.



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002



Note 13Subsequent Event



On October 31, 2003, we entered into a purchase agreement to sell substantially all of the assets and liabilities of
Illinois Power, which currently comprises our regulatory energy delivery reporting segment, to a newly formed subsidiary of Exelon. The assets included in the transaction consist of approximately 40,000 miles of electric transmission and
distribution lines, more than 750 miles of natural gas transmission pipe and 7,600 miles of natural gas distribution lines. Under the terms of the purchase agreement, which has been approved by each companys board of directors, the Exelon
subsidiary will acquire Illinois Powers assets and liabilities for $2.225 billion. The purchase price includes:



| |  | the assumption by Exelon of all of Illinois Powers debt, estimated to be approximately $1.8 billion at closing;
| | - | ----------------------------------------------------------------------------------------------------------------



| |  | approximately $275 million of cash, subject to working capital adjustments; and
| | - | -------------------------------------------------------------------------------



| |  | a $150 million promissory note, which bears interest at 5 percent per annum, is payable quarterly, matures in December 2010 and is subject to mandatory prepayment or extension upon
the occurrence of specified events, including those relating to upgrades of our credit ratings and contingent environmental liabilities retained by Illinois Power. Should one of these specified prepayment events occur prior to the closing, the
promissory note would not be issued and we would receive the related $150 million in cash at closing.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The consummation of the sale is conditioned on, among other things:



| |  | the elimination of the obligation to Illinois Power under the $2.3 billion intercompany note between Illinois Power and our subsidiary, Illinova Corporation;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the receipt of all regulatory and other consents and approvals as specified in the purchase agreement, including approvals from the Illinois Commerce Commission (ICC), the Federal
Energy Regulatory Commission (FERC), the Securities and Exchange Commission (SEC), and other governmental and regulatory agencies; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the passage of legislation amending the Public Utilities Act section relating to the ICC approval for the proposed sale.
| | - | ------------------------------------------------------------------------------------------------------------------------



This proposed legislation currently calls for the ICC to consider the sale
transaction and proposed rate plan in a single proceeding and render a decision on both issues in a nine-month review process. The proposed rate plan contemplates a rate increase beginning in 2007. The proposed legislation, which was introduced in
the Illinois General Assembly during its November veto session which ends on November 20, 2003, provides for an immediate effective date if passed by the vote of at least three-fifths of each house of the General Assembly. If the legislation passes
by a three-fifths super-majority vote in the November veto session and is promptly signed into law by the Governor, then it would become effective in late November. If the legislation becomes effective, a petition would be filed with the ICC in
December, which would start the nine-month review with a decision expected in September 2004. Filings with FERC and the SEC are expected to be made around the same time as the filing of the petition with the ICC. Rulings by FERC and the SEC are
currently anticipated within a few months following the ICCs decision. Pending these state and federal approvals, the sale is expected to close in the fourth quarter of 2004. Approval of the legislation by less than a three-fifths
super-majority would delay its effective date, as well as the filings with the ICC, FERC and SEC, until July 2004, and delay the decision by the ICC until early 2005.



53



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DYNEGY INC.



NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)



(Unaudited)



For the Interim Periods Ended September 30, 2003 and 2002





Since the submission of
the proposed legislation, various consumer groups and others in Illinois have voiced their opposition. As a result, the language contained in the proposed legislation has changed and may continue to change throughout the approval process.
Additionally, on November 3, the People of the State of Illinois, by and through Lisa Madigan, Attorney General of the State of Illinois, the Cook County States Attorney Office, the Citizens Utility Board and others, filed a petition at the
ICC seeking an investigation by the ICC into Illinois Powers financial condition. The stated purpose of the request is to assist the General Assembly in determining whether to pass the proposed legislation. An initial hearing in this matter
before an Administrative Law Judge has been set for November 14, 2003. It is not possible to determine the outcome of this proceeding or when it will be decided. Moreover, we cannot assure you that the proposed legislation will be approved by the
General Assembly.



The purchase agreement may be terminated
upon the occurrence of certain events, including:



| |  | if the closing shall not have occurred on or before December 31, 2004; or
| | - | -------------------------------------------------------------------------



| |  | if the above-described Illinois legislation does not become effective within 60 days of the end of the legislative session of the Illinois General Assembly scheduled to begin in
January 2004.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In a related agreement that is
conditioned upon the closing of the transaction, we have contracted to sell 3,100 MW of generating capacity and 2,900 MW of generating capacity and energy to an Exelon subsidiary for six years beginning in January 2005. The capacity, which will be
provided by our coal-fired baseload facilities in Illinois, natural gas-fired peaking facilities throughout the region and our Kendall tolling contract, will be used by Exelon to meet its customer demand. Under this power purchase agreement, Exelon
will purchase approximately 2,900 MW of capacity and energy from Dynegys peaking facilities and the Kendall tolling arrangement. Also as part of the power purchase agreement, Exelon will purchase 3,100 MW of capacity only from our baseload
coal fleet. We will dispatch and sell the energy from these coal assets into the Illinois wholesale marketplace. It is anticipated that this arrangement will be in place concurrently with the termination of our power purchase agreement with Illinois
Power and the closing of the transaction.



We will use the cash
proceeds from the transaction, if consummated, to reduce our debt. As a result of this agreement, we will perform a goodwill impairment analysis in accordance with SFAS No. 142 during the fourth quarter 2003. We are unable to assess the
recoverability of the $381 million goodwill balance associated with our REG reporting unit at this time, as the recoverability will be based on our October 31, 2003 balance sheet, which is not yet finalized. However, we believe it is probable that
we will record a partial impairment of goodwill during the fourth quarter 2003 associated with this analysis. Upon recognition of this impairment charge, the net assets associated with our REG business will be reflected at fair value. In addition,
in accordance with SFAS No. 144, we will record a charge for the anticipated costs, including taxes, associated with this transaction. Transaction related costs are currently estimated to total approximately $50 million. Following the completion of
our goodwill impairment analysis and final estimation of transaction-related costs, we will publicly disclose the amount of the fourth quarter 2003 charge.



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DYNEGY INC.



MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS



For the Interim Periods Ended September 30, 2003 and 2002





Item 2MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS



The following discussion should be read together with
the unaudited condensed consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Form 10-K/A.



We are a holding company and conduct substantially all of our business
operations through our subsidiaries. Our three operating energy businesses are engaged in power generation, natural gas liquids and regulated energy delivery. Our power generation business owns or leases approximately 13,000 MW of net generating
capacity in the United States. Our power generation fleet is diversified by facility type (base load, intermediate and peaking), fuel source and geographic location. Our natural gas liquids business owns natural gas gathering and processing assets
located in key producing areas of Louisiana, New Mexico and Texas. This business also owns integrated assets used to fractionate, store, terminal, transport, distribute and market natural gas liquids. These assets are generally connected to and
supplied by our and third parties natural gas gathering and processing assets and are located in Mont Belvieu, Texas, the hub of the U.S. natural gas liquids business, and West Louisiana. Our regulated energy delivery business is comprised of
our Illinois Power subsidiary. Illinois Power serves more than 590,000 electricity customers and nearly 415,000 natural gas customers in Illinois. Please read Note 13Subsequent Event for a discussion of our recent agreement to sell
substantially all of Illinois Powers assets and liabilities to Exelon for $2.225 billion.



We have been restructuring our company since the fourth quarter 2002 in response to various issues that affected Dynegy and the energy industry generally.
In carrying out our restructuring, we have disposed of our communications business and made significant progress in our planned exit from the customer risk management, or CRM, business. We also have sold other non-core assets and businesses,
including our U.K. storage and global liquids businesses and approximately 240 MW of non-strategic domestic and international power generation investments, and significantly reduced our capital expenditures. Most recently, we executed an agreement
to sell substantially all of Illinois Powers assets and liabilities to Exelon for $2.225 billion.



LIQUIDITY AND CAPITAL RESOURCES



Overview



Since the filing of our second
quarter 2003 Form 10-Q on August 14, 2003, we have continued our efforts to restructure our company and to improve our liquidity position. In October 2003, we consummated a $300 million private placement offering of second priority senior secured
notes by DHI. We used net proceeds from this offering, which is described in more detail below, together with approximately $46 million of cash on hand, to prepay $364 million of 2005 debt maturities. This offering followed our August 2003 offerings
of nearly $1.7 billion of second priority senior secured notes by DHI and convertible subordinated debentures by Dynegy, the proceeds of which were used to reduce our 2005 and 2006 debt maturities and to facilitate the restructuring of the $1.5
billion in Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a subsidiary of ChevronTexaco. As a result of these transactions, our debt maturities through 2007 are as follows: $41 million (fourth quarter 2003); $326
million (2004); $259 million (2005); $130 million (2006); and $270 million (2007). While this restructuring activity extended a significant portion of our near-term obligations, we have incurred additional interest expense as a result of the new
debt issuances, and our future results of operations will be impacted by this added expense, as well as the restrictive covenants contained in the related agreements.



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We also have continued our exit from the CRM business. As a result, we have further reduced our
collateral obligations relating to this business. Please read Collateral Obligations below for further details.



In November 2003, we announced an agreement to sell substantially all of Illinois Powers assets and liabilities to Exelon for $2.225 billion. The
consummation of the transaction, which is conditioned on the receipt of required regulatory approvals, is expected in the fourth quarter 2004. If consummated, Exelon will assume Illinois Powers debt, which is expected to approximate $1.8
billion at closing, and the $2.3 billion intercompany note between Illinova and Illinois Power would be eliminated. We will use the cash proceeds of $275 million, together with the proceeds to be received under a $150 million promissory note, to
further reduce our outstanding indebtedness. Please read Note 13Subsequent Event for further discussion.



Refinancing and Restructuring Transactions



Beginning in August 2003, we consummated a series of refinancing and restructuring transactions comprised of the following:



| |  | Issuance by DHI of $1.75 billion of second priority senior secured notes in two private placement transactions, the first in August 2003 and the second in October 2003, at a
weighted average interest rate of 9.71% and a weighted average yield to maturity of 9.65%, which notes are secured on a second priority basis by substantially the same collateral that secures the obligations under DHIs credit facility, which
consists of a substantial portion of the available assets and stock of our direct and indirect subsidiaries, excluding Illinois Power;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Issuance by Dynegy of $225 million of convertible subordinated debentures in a private placement transaction at an interest rate of 4.75%, which debentures are convertible into
Dynegys Class A common stock and guaranteed on a senior unsecured basis by DHI;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | A cash tender offer and related consent solicitation for all of DHIs outstanding 8.125% Senior Notes due 2005, 63⁄4% Senior Notes due 2005 and 7.450% Senior Notes due 2006,
pursuant to which we purchased approximately $282 million of the $300 million 8.125% Senior Notes due 2005, approximately $150 million of the $150 million 63⁄4% Senior Notes due 2005 and approximately $177 million of the $200 million 7.450%
Senior Notes due 2006;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Restructuring of the $1.5 billion in Series B preferred stock previously held by a ChevronTexaco subsidiary, pursuant to which the Series B preferred stock was exchanged for $225
million in cash, $225 million principal amount of Dynegys Junior Unsecured Subordinated Notes due 2016 and 8 million shares of Dynegys Series C Mandatorily Redeemable Convertible Preferred Stock due 2033 (liquidation preference $50 per
share); and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Amendments to DHIs restructured credit facility to permit the above-referenced transactions.
| | - | ---------------------------------------------------------------------------------------------



We used the net proceeds from the securities offerings described above, together with approximately $300 million of cash on
hand and $40 million in returned pre-payments from ChevronTexaco, to make the $225 million Series B preferred stock restructuring payment, to purchase the DHI senior notes in the tender offer and to otherwise reduce our 2005 debt maturities as
follows:



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



| |  | Prepay in full the $360 million Term B loan outstanding under DHIs restructured credit facility;
| | - | -------------------------------------------------------------------------------------------------



| |  | Prepay in full the $696 million of debt outstanding under the Black Thunder secured financing; and
| | - | --------------------------------------------------------------------------------------------------



| |  | Prepay in full the $170 million capital lease obligation associated with our CoGen Lyondell power generating facility.
| | - | ----------------------------------------------------------------------------------------------------------------------



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For a more complete description of these transactions, please read Note 6DebtRefinancing.



As a result of these transactions, we have refinanced
approximately $2.0 billion of debt that previously matured through 2006, while maintaining a strong liquidity position as further described below under Liquidity Sources. However, the pre-payment of the debt above resulted in
accelerated charges during the third quarter 2003 of approximately $20 million, pre-tax, of unamortized financing costs and the settlement value of the associated interest-rate hedge instruments, and will result in similar charges of approximately
$3 million during the fourth quarter 2003. We incurred debt issuance costs aggregating approximately $63 million in connection with these transactions, which amounts have been capitalized and will be amortized over the term of the related
transactions.



We are also subject to the more restrictive
covenants that are contained in the related transaction agreements. Specifically, these covenants limit our ability to receive payments from DHI, for the purpose of paying dividends on our common stock and otherwise, limit DHIs ability to
incur additional indebtedness for other than refinancing purposes and require that a significant portion of proceeds from specified asset sales and equity issuances be used to pay down outstanding indebtedness. Our future results of operations may
be significantly affected by our ability to execute our business and financial strategies within the confines of these restrictive covenants.



Liquidity Sources



Since the end of the second quarter 2003, we have continued to maintain a strong liquidity position, averaging total available liquidity of approximately
$1.4 billion through November 5, 2003. The following table summarizes our consolidated credit capacity and liquidity position at December 31, 2002, September 30, 2003 and November 5, 2003:



|                                                              |  | December 31,2002 |       |   | September 30,2003 |   |       | November 5,2003 | 
|------------------------------------------------------------- |  | ---------------- | ----- | - | ----------------- | - | ----- | --------------- | 
|                                                              |  | (in millions)    |      
|Total Credit Capacity                                         |  | $                | 1,400 |   |                   | $ | 1,100 | (2)             | 
|Outstanding Loans                                             |  |                  | (228  | ) |                   |   |      |                 | 
|Outstanding Letters of Credit Under Revolving Credit Facility |  |                  | (872  | ) |                   |   | (353  | )               | 
|                                                              |  |                  |       |   |                   |   |       |                 | 
|Unused Borrowing Capacity                                     |  |                  | 300   |   |                   |   | 747   |                 | 
|Cash                                                          |  |                  | 757   |   |                   |   | 688   | (3)             | 
|Liquid Inventory (1)                                          |  |                  | 258   |   |                   |   |      |                 | 
|                                                              |  |                  |       |   |                   |   |       |                 | 
|Total Available Liquidity                                     |  | $                | 1,315 |   |                   | $ | 1,435 | (5)             | 
|                                                              |  |                  |       |   |                   |   |       |                 | 

---

|(1) | Amounts reflected for 2003 periods do not include liquid inventory, as we have sold the natural gas inventories that comprised that item and converted them to cash.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Reflects the conversion of $200 million of credit capacity under the former DHI revolving credit facilities into the Term A loan in connection with the April 2003 restructuring of
such facilities, as well as the May 2003 payment of the final $100 million then outstanding under Illinois Powers termed out revolving credit facility.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Reflects the use of approximately $260 million of cash on hand on August 11, 2003, in addition to the proceeds from the refinancing and restructuring transactions consummated on
such date, for the prepayment of certain outstanding indebtedness as further described in Refinancing and Restructuring Transactions above.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | Reflects the use of approximately $46 million of cash on hand on October 15, 2003, in addition to the proceeds from the follow-on debt offering consummated on such date, for the
prepayment of certain outstanding indebtedness as further described in  Refinancing and Restructuring Transactions above.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) | Includes approximately $23 million and $49 million, respectively, of liquidity at Illinois Power.
|--- | -------------------------------------------------------------------------------------------------



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Liquidity Uses



During the first nine months of 2003, significant uses of liquidity included the following:



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



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



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



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



| |  | Funding of $62 million in payments under the Black Thunder secured financing; and
| | - | ---------------------------------------------------------------------------------



| |  | Funding of $55 million in payments under the ABG Gas Supply financing.
| | - | ----------------------------------------------------------------------



Since September 30, 2003, significant uses of liquidity have included funding of a $6 million payment under the ABG Gas Supply financing.



In addition, in August and October 2003, we used the approximately $2.0
billion in proceeds we received from the aforementioned refinancing and restructuring transactions, together with cash on hand, to:



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



| |  | Prepay in full the $360 million Term B loan outstanding under DHIs restructured credit facility;
| | - | -------------------------------------------------------------------------------------------------



| |  | Purchase approximately $609 million of DHIs previously outstanding 2005/2006 public notes and to pay consent fees in connection with the tender offer and consent solicitation
for such notes;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | Prepay the $170 million capital lease obligation associated with our CoGen Lyondell power generating facility;
| | - | --------------------------------------------------------------------------------------------------------------



| |  | Fund the $225 million cash payment to a ChevronTexaco subsidiary under the Series B preferred stock restructuring; and
| | - | ----------------------------------------------------------------------------------------------------------------------



| |  | Pay related transaction fees and expenses.
| | - | ------------------------------------------



Collateral Obligations



The following table summarizes our consolidated collateral postings to third parties by operating division at December 31, 2002, September 30, 2003 and
November 5, 2003:



|      |  | December 31,2002 |       | September 30,2003 |   | November 5,2003
|----- |  | ---------------- | ----- | ----------------- | - | ---------------
|      |  | (in millions)   
|GEN   |  | $                | 168   |                   | $ | 221            
|CRM   |  |                  | 806   |                   |   | 199            
|NGL   |  |                  | 166   |                   |   | 145            
|REG   |  |                  | 28    |                   |   | 20             
|Other |  |                  | 48    |                   |   | 27             
|      |  |                  |       |                   |   |                
|Total |  | $                | 1,216 |                   | $ | 612            
|      |  |                  |       |                   |   |                



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During the first nine months of 2003, we reduced our total collateral obligations by $604 million. This
reduction primarily related to decreases in collateral associated with our CRM business.



As described in Note 6DebtRevolvers and Commercial Paper above, we incur a 0.15% fronting fee upon the issuance of letters of credit under our
restructured credit facility. A letter of credit fee is also payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. To the extent practicable, we intend to use cash on
hand, as opposed to letters of credit, to satisfy our future collateral obligations.



As described above, we recently announced an agreement to sell substantially all of Illinois Powers assets and liabilities to Exelon for $2.225 billion. In a related agreement that is conditioned upon the
closing of the transaction, we contracted to sell 3,100 MW of generating capacity and 2,900 MW of generating capacity and energy to an Exelon subsidiary for six years beginning in 2005. Under that agreement, we would be required to post $25 million
in collateral in January 2005, which amount will increase to $75 million over the first seven months of the agreement, decreasing to $5 million by November 2010. The parties are in discussions regarding the structure of their relationship relative
to management of the supply of fuel to the gas-fired generating facilities to be covered by the agreement. We could incur additional collateral obligations of up to $25 million depending on the outcome of these discussions and various other factors,
including commodity prices.



Disclosure of Financial Obligations and
Contingent Financial Commitments



We have incurred various
financial obligations and commitments in the normal course of our operations and financing activities. Financial 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. Financial commitments represent contingent obligations, which become payable only if
certain pre-defined events occur, such as financial guarantees.



Our financial obligations and commitments have changed since December 31, 2002, with respect to which information is included in our Form 10-K/A. The following summarizes the most significant changes.



Long-term Debt. As discussed more fully in Note
6DebtRevolvers and Commercial Paper, we restructured our principal credit facility in April 2003. Subsequently, in August 2003, we amended our principal credit facility, issued more than $1.6 billion in second priority senior secured
notes and convertible subordinated debentures and used a portion of the proceeds, together with cash on hand, to pay down certain obligations due in 2005 and 2006. Finally, in October 2003, we again amended our principal credit facility, issued $300
million in additional second priority senior secured notes in a follow-on offering and used the proceeds, together with cash on hand, to repay certain other obligations due in 2005. As a result, our debt maturities through 2007 are as follows: $41
million (fourth quarter 2003), $326 million (2004); $617 million (2005) (excluding the $358 million in 2005 maturities previously paid upon consummation of our October 2003 DHI follow-on notes offering); $130 million (2006); and $270 million (2007).
Please read Note 6Debt for a tabular presentation of these debt maturities.



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The following table depicts our consolidated third-party debt obligations, including our DNE leveraged
lease and our Tilton lease obligations, and the extent to which they are secured as of December 31, 2002, September 30, 2003 and September 30, 2003, as adjusted:



|                                       |  | December 31,2002 |        |   | September 30,2003 |   |       | September 30,2003, asadjusted (1)
|-------------------------------------- |  | ---------------- | ------ | - | ----------------- | - | ----- | ---------------------------------
|                                       |  | (in millions)   
|First Secured Obligations              |  |                  |        |   |                   |   |       |                                  
|Dynegy Holdings Inc.                   |  | $                | 2,440  |   |                   | $ | 1,322 |                                  
|Dynegy Inc.                            |  |                  | 360    |   |                   |   | 194   |                                  
|Illinois Power                         |  |                  | 2,092  |   |                   |   | 1,987 |                                  
|                                       |  |                  |        |   |                   |   |       |                                  
|Total First Secured Obligations        |  |                  | 4,892  |   |                   |   | 3,503 |                                  
|Second Secured Obligations             |  |                  |       |   |                   |   | 1,450 |                                  
|Unsecured Obligations                  |  |                  | 2,266  |   |                   |   | 2,171 |                                  
|                                       |  |                  |        |   |                   |   |       |                                  
|Subtotal                               |  |                  | 7,158  |   |                   |   | 7,124 |                                  
|                                       |  |                  |        |   |                   |   |       |                                  
|Preferred Obligations                  |  |                  | 1,711  |   |                   |   | 411   |                                  
|                                       |  |                  |        |   |                   |   |       |                                  
|Total Obligations                      |  | $                | 8,869  |   |                   | $ | 7,535 |                                  
|                                       |  |                  |        |   |                   |   |       |                                  
|Less: DNE Lease Financing              |  |                  | (746   | ) |                   |   | (769  | )                                
|Less: Preferred Obligations            |  |                  | (1,711 | ) |                   |   | (411  | )                                
|Other (2)                              |  |                  | (97    | ) |                   |   | (43   | )                                
|                                       |  |                  |        |   |                   |   |       |                                  
|Total Notes Payable and Long-term Debt |  | $                | 6,315  |   |                   | $ | 6,312 |                                  
|                                       |  |                  |        |   |                   |   |       |                                  

---

|(1) | Adjusted to reflect the impact of the follow-on notes offering, prepayment of the outstanding amount under our Term B Loan and the retirement of the CoGen Lyondell generation
facility capital lease, all of which occurred in October 2003.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Consists of discounts and premiums on debt (totaling $16 million and $28 million at December 31, 2002 and September 30, 2003, respectively) and the difference between the carrying
value of the Tilton obligation (zero and $66 million at December 31, 2002 and September 30, 2003, respectively) and the ultimate obligation of $81 million.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Series B Preferred Stock. As discussed more fully in Note 6DebtChevronTexaco Series B Preferred
Stock Restructuring and Note 7Related Party Transactions, on July 28, 2003, we entered into an agreement with ChevronTexaco to exchange the $1.5 billion of Series B preferred stock previously held by a ChevronTexaco subsidiary for $225 million
in cash, $225 million of newly issued Dynegy Junior Unsecured Subordinated Notes due 2016 and $400 million of newly issued Dynegy Series C convertible preferred stock. As part of the Series B preferred stock restructuring, we also renegotiated
certain prepayment arrangements with ChevronTexaco such that ChevronTexaco returned to us approximately $40 million in pre-payments relating to our commodity purchase obligations and converted our prepayment obligation from thirty days to seven
days.



Capacity Payments. As discussed in Note
2Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSouthern Power Tolling Arrangements, in May 2003 we paid $155 million to terminate our three power tolling arrangements with
Southern Power. As a result of these terminations, we have eliminated our obligation to make $1.7 billion in capacity payments over the next 30 years.



Capital Expenditures



In connection with our restructuring, we have also undertaken various efforts to tightly manage costs and capital expenditures. With respect to capital
expenditures, we spent approximately $259 million for the nine months ended September 30, 2003 as follows (in millions):



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|GEN   |  | $ | 117
|----- |  | - | ---
|NGL   |  |   | 36 
|REG   |  |   | 101
|Other |  |   | 5  
|      |  |   |    
|Total |  | $ | 259
|      |  |   |    



Capital spending in
our GEN segment primarily consisted of routine capital maintenance, as well as approximately $39 million on the Rolling Hills facility. Capital spending in our NGL segment primarily related to routine capital maintenance and well-connects. Capital
spending in our REG segment primarily related to projects intended to maintain system reliability.



We expect capital expenditures for all of 2003 will approximate $360 million, including approximately $60 million relating to Rolling Hills, which was
completed in the second quarter 2003. This is a significant reduction from the approximately $947 million in capital expenditures incurred in 2002 and reflects our efforts to improve our capital efficiency without compromising the operational
integrity of our facilities.



Dividends on Preferred and Common Stock



Beginning with the third quarter 2002, our Board of
Directors elected to cease payment of a dividend on our common stock. Payments of dividends for subsequent periods will be at the discretion of the Board of Directors, but we do not foresee reinstating the dividend in the near term. We have,
however, continued to make the required dividend payments on our outstanding trust preferred securities. Please read Managements Discussion and Analysis of Financial Condition and Results of OperationsBank Restructuring
beginning on page 42 of our Form 10-K/A and DHI Second Priority Senior Secured Notes above for a discussion of the dividend limitations contained in our restructured credit facility and second priority senior secured notes
indenture.



There was no cash dividend required to be paid on
the Series B preferred stock issued to ChevronTexaco in November 2001. Because of ChevronTexacos discounted conversion option, we accreted an implied preferred stock dividend over the redemption period, as required by GAAP. Please read
Item 8, Financial Statements and Supplementary Data, Note 13Redeemable Preferred Securities beginning on page F-61 of our Form 10-K/A for further discussion of this non-cash implied dividend. As more fully described in Note
7Related Party Transactions, we have restructured the Series B preferred stock. In conjunction with the restructuring, we recognized a gain of approximately $1.2 billion as a preferred stock dividend in the third quarter 2003.



As more fully described in Note 6DebtChevronTexaco Series B
Preferred Stock Restructuring, we accrue dividends on our Series C convertible preferred stock at a rate of 5.5% per annum. We accrued $3 million in dividends during the three and nine months ended September 30, 2003. We did not make any dividend
payments on the Series C convertible preferred stock during the three and nine months ended September 30, 2003.



Illinois Power Liquidity



Illinois Power has a significant amount of leverage, including quarterly payments of approximately $22 million due on its transitional funding trust
notes. Illinois Power is required to make these quarterly payments on its transitional funding trust notes through 2008 and, pursuant to its notice of intent to exercise the purchase option, has a payment of $81 million due on its Tilton lease
financing in the third quarter 2004. Pursuant to a sublease with DMG, it is planned that DMG will pay the $81 million due on the Tilton lease and take possession of the facility by the third quarter 2004. Because Illinois Power has no revolving
credit facility and no access to the commercial paper markets, it relies on cash on hand, cash from liquidity initiatives and cash flows from operations, including interest payments under its $2.3 billion intercompany note receivable from Illinova,
to satisfy its debt obligations and to otherwise operate its business. In December 2002, Illinois Power closed on a private offering of $550 million of mortgage bonds, $150 million of which were issued in January 2003 following approval from the
Illinois Commerce Commission. A portion of the proceeds were used to repay Illinois Powers $300 million term loan (including the final payment of $100 million on May 2, 2003) and to replenish liquidity used to pay a $96 million mortgage bond
maturity in July 2002. The remaining proceeds from this offering, together with a portion of the



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below-described interest payments on the intercompany note receivable, were used to fund Illinois Powers mortgage bond maturities of $100 million in
August 2003 and $90 million in September 2003.



On July 31,
2003, Dynegy made an interest payment of approximately $100 million on its $2.3 billion intercompany note payable to Illinova, which in turn made an interest payment of approximately $100 million on its $2.3 billion intercompany note payable to
Illinois Power. In September and October 2003, Dynegy made additional interest payments of approximately $71 million and $28 million, respectively, to Illinova, which in turn paid Illinois Power. The intercompany notes contain substantially similar
interest payment provisions, and semi-annual interest payments of approximately $86 million are due to Illinois Power on April 1 and October 1 of each year. The above-described interest payments represent accrued interest on the note for the months
of April-September 2003 and prepaid interest for the months of October 2003-May 2004.



Given its inability to generate sufficient cash flows to satisfy its capital expenditure requirements and other obligations, for the near term, Illinois Power will continue to rely on a support commitment by Dynegy in
order to satisfy its obligations. Dynegys restructured credit agreement, which matures in February 2005, permits prepayments of principal on the intercompany note up to $200 million, but does not restrict the prepayment of interest thereon.
Additionally, the indenture governing DHIs second priority senior secured notes permits payments of principal on the intercompany note up to $450 million or to the extent that a fixed change coverage ratio of 2:1 is satisfied. The indenture
also permits the prepayment of interest thereon up to twelve months at any one time.



Please read Note 13Subsequent Event for a discussion of our recent agreement to sell substantially all of Illinois Powers assets and liabilities to Exelon for $2.225 billion.



Conclusion



We recently completed a series of long-term refinancing and restructuring transactions that included private placement
offerings of nearly $2.0 billion in DHI second priority senior secured notes and Dynegy convertible subordinated debentures. We used the net proceeds from these offerings, together with cash on hand, to repay approximately $2.0 billion in 2005 and
2006 debt maturities. We also made a $225 million cash payment to ChevronTexaco as part of the Series B preferred stock restructuring. By consummating the Series B preferred stock restructuring, we believe that we have eliminated the uncertainty
surrounding the Series B preferred stock, thereby creating the potential for future equity issuances, the proceeds of which would be used to reduce outstanding indebtedness or other obligations in furtherance of our efforts to develop a capital
structure that is more closely aligned with the cash-generating potential of our asset-based businesses.



By effectively extending the maturity dates of these obligations, together with the prior restructuring of our credit facilities that were scheduled to
expire in April and May 2003, we believe that we have provided our company with sufficient capital resources to meet our debt obligations and provide collateral support for our ongoing asset businesses and our continued exit from third-party
marketing and trading through at least 2004. Thereafter, our $1.1 billion revolving credit facility is scheduled to mature in February 2005, and our ability to address that maturity is critical to our future financial success. Our success and future
financial condition will also depend on our ability to execute the remainder of our exit from the CRM business successfully, particularly the tolling arrangements, and to produce adequate operating cash flows from our continuing asset-based
businesses to meet our debt and commercial obligations, including a substantial increase in interest expense and our capacity payment obligations under the tolling arrangements.



Our ability to generate cash flow from our businesses will be impacted by the success of our ongoing efforts to manage
operating costs and capital expenditures. As part of these efforts, in early 2003 we launched our value creation project, an initiative focused on identifying opportunities to improve our operational efficiencies and transition to a more
flexible operating model. In connection with our value creation project, in October 2003 we entered into an agreement with Accenture Ltd. under which Accenture will assist us in reducing our costs across key support functions, including information
technology, procurement, human resources and financial systems. In addition, with respect to fuel procurement, our Baldwin, Wood River, Hennepin and Havana power generation facilities burn coal from mines located in Wyoming, Montana, Colorado and
Utah. These facilities represent approximately 85% of our coal-fired power generation. We currently arrange for the transportation of coal to these



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facilities under coal transportation agreements that expire at the end of December 2003. We are currently in negotiations
with qualified rail transportation providers to replace these services effective January 2004 at rates more favorable than those we currently pay.



Our future financial condition will also be affected by our ability to consummate the proposed sale of substantially all of Illinois Powers assets
and liabilities to Exelon, which sale would reduce our consolidated indebtedness by approximately $1.8 billion and provide up to $425 million of proceeds to use for further debt reduction. Please read Note 13Subsequent Event for further
discussion. Please also read Factors Affecting Future Results of Operations and Uncertainty of Forward-Looking Statements and Information for additional factors that could impact our future operating results and financial
condition.



FACTORS AFFECTING FUTURE RESULTS OF OPERATIONS



Our results of operations during the remainder of 2003
and beyond may be significantly affected by the following factors, among others:



| |  | the level of earnings and cash flows from our asset-based businesses, which are subject to the effect of changes in commodity prices, particularly for power, natural gas, natural
gas liquids and other fuels and, to a lesser extent, the spark spread between power and natural gas prices and the fractionation spread between natural gas and natural gas liquids prices, and the rates charged in our regulated energy delivery
business;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the effect of varying demands for specific types of our natural gas liquids products upon our short term natural gas liquids inventories, resulting in subsequent, short term
exposure to changes in commodity prices;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the effects of a material decrease in natural gas production as a result of depressed commodity prices upon the supply of natural gas available to our NGL facilities;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the effects of competition on the results of operations from our asset-based businesses;
| | - | ----------------------------------------------------------------------------------------



| |  | the effects of changes in weather and prevailing economic conditions on wholesale and retail demand for our power, natural gas and natural gas liquids and our transmission and
distribution services;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our ability to complete our exit from the CRM business and the costs associated with this exit, including our capacity payment obligations under the tolling arrangements;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our ability to operate our asset-based businesses within the confines of the increased borrowing rates and more restrictive covenants contained in our restructured credit agreement
and the DHI second priority senior secured notes indenture;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the effects of the proposed sale of Illinois Power to Exelon;
| | - | -------------------------------------------------------------



| |  | our ability to fund or obtain financing for working capital, capital expenditures and general corporate purposes and to otherwise respond to economic downturns, competition and
other market pressures, given the various restrictions contained in our amended credit facility and second priority senior secured notes indenture;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | increased interest expense and the other effects of our restructured credit agreement, second priority senior secured notes, convertible subordinated debentures, junior notes and
Series C convertible preferred stock; and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | the effects of ongoing litigation relating to, among other things, the western power and natural gas markets, shareholder claims and trade credit litigation, as well as the ongoing
regulatory investigations primarily relating to Project Alpha and our past trading practices.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Additionally, as further discussed in Note 1 to the unaudited condensed consolidated financial
statements, new accounting pronouncements have impacted our results of operations and will continue to do so in the future. Please read Uncertainty of Forward-Looking Statements and Information for additional factors that could impact
our future operating results.



RESULTS OF OPERATIONS



In this section, we discuss our results of operations, both on a
consolidated basis and by segment, for the three- and nine-month periods ended September 30, 2003 and 2002.



As reflected in this report, we have changed our reporting segments. In 2002, we reported results for the following four business segments:



| |  | Wholesale Energy Network, or WEN;
| | - | ---------------------------------



| |  | Dynegy Midstream Services, or DMS;
| | - | ----------------------------------



| |  | Transmission and Distribution, or T&D; and
| | - | ------------------------------------------



| |  | Dynegy Global Communications, or DGC.
| | - | -------------------------------------



Beginning January 1, 2003, we are reporting our operations in the following segments:



| |  | Power generation, or GEN;
| | - | -------------------------



| |  | Natural gas liquids, or NGL;
| | - | ----------------------------



| |  | Regulated energy delivery, or REG; and
| | - | --------------------------------------



| |  | Customer risk management, or CRM.
| | - | ---------------------------------



Other reported results include corporate overhead and our discontinued operations. Please see Note 2Dispositions, Contract Terminations and
Discontinued Operations to the unaudited condensed consolidated financial statements included in this report for a discussion of our discontinued operations. All corporate overhead included in other reported results was allocated to the four
operating segments prior to January 1, 2003.



As described in
Note 11Segment Information to the unaudited condensed consolidated financial statements included in this report, prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and
risk-management business, then referred to as the WEN segment. Most, but not all, of the WEN third-party purchase and sale contracts were held by a subsidiary which is currently included within the CRM segment. Under this business model, the net
fair value of most of GENs generation capacity, forward sales and related trading positions were sold to the CRM segment monthly at an internally determined transfer price. The internal transfer price was primarily comprised of the option
value of generation capacity and executed forward sales contracts based on then-current forward prices of power and fuel. GEN results for the three- and nine-month periods ended September 30, 2002 reflect this internal transfer price and do not
represent amounts actually received for power sold to third parties. As such, the GEN results for the three- and nine-month periods ended September 30, 2002 do not include the effect of intra-month market price volatility. The CRM segment recorded
results from these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment.



In connection with our exit from the third-party marketing and trading business, individual contracts within the former WEN segment were identified on
January 1, 2003 as either GEN contracts, as they were determined to be a part of our continuing operations, or CRM contracts. Under this new business segment model, CRM continues to transact with third parties on behalf of GEN for contracts which
were identified as GEN contracts, as well as new transactions executed on behalf of GEN but for which CRM is the legal party to the third-party purchase and sale



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contract. CRM continues to record results from these third-party contracts, together with all of its other third-party
marketing and trading positions unrelated to the GEN segment. However, rather than purchasing such capacity, forward sales and related trading positions from GEN at an internally determined transfer price, pricing between CRM and GEN is set at the
actual amount received or paid for the purchases and sales to the third parties. Therefore, GEN results for the three- and nine-month periods ended September 30, 2003 include the effects of intra-month market price volatility. These differences
should be considered when attempting to compare the results for the three- and nine-month periods ended September 30, 2003 and 2002.



Recent accounting pronouncements have affected our financial results, particularly those of our CRM business, so as to further reduce the comparability of
some of our historical financial data. For example, the rescission of EITF Issue 98-10, effective January 1, 2003, has reduced the number of contracts accounted for on a mark-to-market basis in the 2003 period as compared to the 2002 period. Please
read Cumulative Effect of Change in Accounting Principle below for further discussion.



For segment reporting purposes, all direct general and administrative expenses incurred by us on behalf of our subsidiaries are charged to the applicable
subsidiary as incurred. Other income (expense) items incurred by us on behalf of our subsidiaries are allocated directly to the four segments.



Three and Nine Months Ended September 30, 2003 and 2002



The following table provides summary financial data regarding our unaudited condensed consolidated results of operations for the three- and nine-month
periods ended September 30, 2003 and 2002, respectively:



Results of Operations



|                                                                   |  | Three Months Ended September 30, |      |   | Nine Months Ended September 30, |  
|------------------------------------------------------------------ |  | -------------------------------- | ---- | - | ------------------------------- | -
|                                                                   |  | 2003                             |      |   | 2002                            |  
|                                                                   |  | (in millions)                    |     
|Operating income (loss)                                            |  | $                                | 101  |   |                                 | $
|Earnings (losses) from unconsolidated investments                  |  |                                  | 51   |   |                                 |  
|Interest expense                                                   |  |                                  | (145 | ) |                                 |  
|Other items, net                                                   |  |                                  |     |   |                                 |  
|Income tax benefit (provision)                                     |  |                                  | (3   | ) |                                 |  
|                                                                   |  |                                  |      |   |                                 |  
|Income (loss) from continuing operations                           |  |                                  | 4    |   |                                 |  
|Income (loss) on discontinued operations, net of taxes             |  |                                  | 1    |   |                                 |  
|Cumulative effect of change in accounting principles, net of taxes |  |                                  |     |   |                                 |  
|                                                                   |  |                                  |      |   |                                 |  
|Net income (loss)                                                  |  | $                                | 5    |   |                                 | $
|                                                                   |  |                                  |      |   |                                 |  



Three Months Ended September 30,
2003 and 2002



Net Income (Loss). For the
quarter ended September 30, 2003, we recorded net income of $5 million, compared with a third quarter 2002 net loss of $1,651 million. After taking into consideration the $1,183 million and $(83) million preferred stock implied gain (dividend) for
the three months ended September 30, 2003 and 2002, respectively, diluted earnings per share for the quarter ended September 30, 2003 was $2.65 compared to a diluted loss per share of $4.71 for the quarter ended September 30, 2002. Please read Note
8Earnings (Loss) Per Share for a discussion of our third quarter 2003 earnings per share calculation.



The operating income of $101 million for the quarter ended September 30, 2003 reflects favorable commodity prices, which positively impacted our GEN
segment and the upstream portion of our NGL segment. REGs operating income was negatively affected period-over-period by lower weather-driven demand. Operating income in 2003 also reflects slightly increased depreciation and amortization
expense primarily associated with the expansion of our depreciable asset base period-over-period, including the completion of Rolling Hills. General and administrative expenses were lower period-over-period principally as a result of significantly
lower compensation



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costs, partially offset by higher professional fees in the 2003 period. The 2002 operating loss includes an $897 million
goodwill impairment in our GEN and CRM segments, as well as a $25 million impairment associated with the write-off of our investment in Dynegydirect, our former on-line trading platform.



Earnings (Losses) from Unconsolidated Investments. Our earnings (losses) from unconsolidated investments were
approximately $51 million in the third quarter 2003, compared to $(119) million in 2002. The increase period-to-period primarily reflects impairments recognized in the third quarter 2002 on our generation investments of $144 million and on our
technology investments of $12 million. In addition, during 2003 we realized higher margins from West Coast Power, a 50-50 joint venture through which we own our California power generation facilities, as a result of forward hedges previously put in
place in connection with the execution of the West Coast PowerCDWR contract.



Interest Expense. Interest expense totaled $145 million for the three-month period ended September 30, 2003, compared to $83 million for the 2002 period. The significant increase period-to-period is
attributable to higher average interest rates on borrowings. In addition, 2002 interest expense does not include interest expense allocated to our discontinued businesses. Finally, 2003 interest expense includes approximately $20 million of
accelerated amortization of debt issuance costs associated with indebtedness that was repaid as part of our August 2003 refinancing transactions and the settlement value of the associated interest rate hedge instruments. The higher interest rates
resulted from the restructuring of our credit facility in April 2003 and the refinancing in August 2003, with respect to which such rates and fees are higher than those contained in our previous facility. Please read Note 6Debt above and
Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesBank Restructuring beginning on page 42 of our Form 10-K/A for further discussion.



Other Items, Net. Other items, net consists of other income and
expense items, net, minority interest income (expense) and accumulated distributions associated with trust preferred securities in the unaudited condensed consolidated statements of operations. Other items, net totaled zero and $42 million in
expense for the three-month periods ended September 30, 2003 and 2002, respectively. In 2002, we recognized a charge of $25 million in other items, net, related to the settlement of litigation brought by Enron as a result of our terminated merger,
$4 million of which was subsequently reclassified to discontinued operations.



Income Tax Benefit (Provision). We reported an income tax provision of $3 million for the quarter ended September 30, 2003, compared to an income tax benefit of $87 million for the 2002 period. The 2003
effective rate of 43 percent was increased from statutory rates primarily as a result of state income taxes and book income and losses in jurisdictions with varying tax rates. The tax benefit in the 2002 period resulted from the combination of book
income and losses in jurisdictions with varying tax rates, the realization of permanent differences and significant goodwill impairment charges for which there was no tax basis, and therefore, no associated tax benefit.



Discontinued Operations. Discontinued operations include
Northern Natural, our global liquids business, our U.K. natural gas storage assets, our U.K. CRM business and our communications business. The third quarter 2003 income of $1 million is comprised of $5 million in after-tax income on the
communications business offset by $3 million in after-tax losses associated with U.K. CRM and the U.K. natural gas storage assets and $1 million in after-tax losses from global liquids. The third quarter 2002 loss of $618 million is comprised of
$566 million in after-tax losses from Northern Natural, $32 million in after-tax losses associated with U.K. CRM, $29 million in after-tax losses from the communications business and $2 million in after-tax losses from global liquids offset by $11
million in after-tax income from the U.K. natural gas storage assets.



Significant Items. The following table sets forth significant pre-tax items affecting net income (loss) for the three months ended September 30, 2003 and 2002.



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|                                     |  | Three Months Ended September 30, 2003 |     
|------------------------------------ |  | ------------------------------------- | ----
|                                     |  | GEN                                   |     
|                                     |  | (in millions)                         |     
|Acceleration of financing costs      |  | $                                     |    
|                                     |  |                                       |     
|Total                                |  | $                                     |    
|                                     |  |                                       |     
|                                     | 
|                                     |  | Three Months Ended September 30, 2002 |     
|                                     |  | GEN                                   |     
|                                     |  | (in millions)                         |     
|Discontinued operations              |  | $                                     |    
|Goodwill impairment                  |  |                                       | (549
|Impairment of generation investments |  |                                       | (144
|Impairment of technology investments |  |                                       | (1  
|Enron settlement                     |  |                                       | (6  
|Write-off of Dynegydirect            |  |                                       |    
|                                     |  |                                       |     
|Total                                |  | $                                     | (700
|                                     |  |                                       |     



Nine Months Ended September 30,
2003 and 2002



Net Loss. For the nine-month
period ended September 30, 2003, we recorded a net loss of $138 million, compared with a net loss of $2,459 million for the nine-month period ended September 30, 2002. After taking into consideration the $1,018 million and $(248) million preferred
stock implied gain (dividend) for the nine months ended September 30, 2003 and 2002, respectively, diluted earnings per share for the nine-month period ended September 30, 2003 was $2.21 compared to a diluted loss per share of $7.42 for the
nine-month period ended September 30, 2002.



The operating loss
of $86 million for the nine months ended September 30, 2003 primarily reflects earnings from our GEN, NGL and REG segments, more than offset by charges incurred in our CRM segment, as well as a $50 million incremental litigation reserve recorded in
the second quarter 2003. The charges incurred in our CRM segment include a $133 million pre-tax charge related to the settlement of three power tolling arrangements with Southern Power, $125 million in mark-to-market losses incurred on contracts
associated with the Sithe Independence power tolling arrangement and a $30 million charge for a settlement agreement reached with Kroger related to four power supply agreements. These items were offset by higher period-over-period commodity prices,
which positively impacted our GEN and NGL segments, as well as weather-driven demand resulting in greater volumes produced and sold by GEN. REGs operating income was negatively impacted period-over-period by lower summer weather-driven sales,
partially offset by higher winter weather-driven sales. Operating loss also reflects increased depreciation and amortization expense primarily associated with the expansion of our depreciable asset base period-over-period, including the completion
of three generation facilities that were under construction during the first six months of 2002, as well as the completion of Rolling Hills in the second quarter 2003. General and administrative expenses were higher period-to-period principally as a
result of the $50 million second quarter 2003 litigation reserve and higher professional fees, offset by significantly lower compensation costs in the 2003 period. During the second quarter 2003, we recognized a pre-tax gain of approximately $12
million on the sale of our interest in Hackberry LNG Terminal LLC. The 2002 operating loss includes an $897 million goodwill impairment in our GEN and CRM segments, $31 million in restructuring costs incurred in the second quarter 2002 and a $25
million impairment associated with the write-off of our investment in Dynegydirect.



Earnings (Losses) from Unconsolidated Investments. Our earnings (losses) from unconsolidated investments were approximately $142 million in the 2003 period compared to $(66) million in 2002. The increase
period-to-period primarily reflects impairments recognized in the third quarter 2002 on our generation investments of $144 million, and on our technology investments of $12 million. In addition, during 2003, we realized higher realized margins from
West Coast Power, resulting from forward hedges previously put in place in connection with the execution of the West Coast Power-CDWR contract. Please read Segment DisclosuresPower Generation below for further discussion.



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Interest Expense. Interest expense totaled $364 million for the nine-month period ended
September 30, 2003, compared to $213 million for the 2002 period. The significant increase period-to-period primarily is attributable to higher average principal balances in the 2003 period compared to the 2002 period, higher average interest rates
on borrowings, increased amortization of debt issuance costs and higher letter of credit fees. Interest expense in the 2003 period includes approximately $24 million of pre-tax charges associated with accelerated amortization of previously incurred
financing costs and the settlement value of the associated interest rate hedge instruments. Finally, interest expense for 2002 does not include interest expense which was allocated to our discontinued businesses. The increase in principal balances
primarily resulted from substantially higher collateral postings in the second and third quarters of 2002, which, despite subsequent reductions, remained at levels above those outstanding during the first nine months of 2002. Please read
Liquidity and Capital ResourcesCollateral Obligations above for a discussion of the significant reductions in collateral postings, particularly with respect to our CRM business, since the end of the third quarter 2002. The
higher interest rates and letter of credit fees resulted from the restructuring of our credit facility in April 2003, with respect to which such rates and fees are higher than those contained in our previous facility. Please read Note 6Debt
above and Managements Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesBank Restructuring beginning on page 42 of our Form 10-K/A for further discussion.



Our interest expense during the remainder of 2003 and thereafter will
reflect our increased costs of borrowing. The Refinancing and the Series B Exchange will result in higher interest costs for the remainder of the year and thereafter, primarily as a result of higher average interest rates. Interest expense for the
remainder of 2003 will also reflect higher costs from Illinois Powers December 2002 and January 2003 issuances of mortgage bonds totaling $550 million, which bonds were issued at a 12% effective interest rate compared to Illinois Powers
average 2002 mortgage bond interest rate of 5.81%.



Other
Items, Net. Other items, net consists of other income and expense items, net, minority interest income (expense) and accumulated distributions associated with trust preferred securities in the unaudited condensed consolidated statements of
operations. Other items, net totaled $12 million in income and $81 million in expense for the nine-month periods ended September 30, 2003 and 2002, respectively. The change in these amounts primarily represents a $44 million increase in minority
interest income in the 2002 period, as well as the $21 million in charges related to the 2002 Enron settlement.



Income Tax Benefit. We reported an income tax benefit of $109 million for the nine-month period ended September 30, 2003, compared to an
income tax benefit of $169 million for the 2002 period. The 2003 effective rate of 37 percent was increased from statutory rates primarily as a result of state income taxes. The tax benefit in the 2002 period resulted from the combination of book
income and losses in jurisdictions with varying tax rates, the realization of permanent differences and significant goodwill impairment charges for which there was no tax basis, and therefore, no associated tax benefit.



Discontinued Operations. Discontinued operations include
Northern Natural, our global liquids business, our U.K. natural gas storage assets, our U.K. CRM business and our communications business. The loss of $6 million for the nine-month period ended September 30, 2003 is comprised of $12 million in
after-tax losses on operations of U.K. CRM and the U.K. natural gas storage assets and $2 million in after-tax losses from global liquids, offset by $8 million in after-tax income associated with the communications business. The 2002 loss of $1,100
million is comprised of $535 million in after-tax losses from the communications business, $544 million in after-tax losses from Northern Natural, $40 million in after-tax losses associated with U.K. CRM and $5 million in after-tax losses from
global liquids offset by $24 million in after-tax income from the U.K. natural gas storage assets.



Cumulative Effect of Change in Accounting Principles. As described in Note 1 to the unaudited condensed consolidated financial statements,
we reflected EITF Issue 02-03s rescission of EITF Issue 98-10 effective January 1, 2003 as a cumulative effect of change in accounting principle. The net impact was an after-tax benefit of $21 million. We also adopted SFAS No. 143 effective
January 1, 2003 and recognized an after-tax benefit of $34 million associated with its implementation. As described in Note 1 to the unaudited condensed consolidated financial statements, we adopted SFAS No. 142 effective January 1, 2002. In
connection with its adoption, we realized a



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cumulative effect loss of approximately $234 million associated with a write-down of goodwill in our discontinued communications business.



Significant Items. The following table sets forth significant
pre-tax items affecting net loss for the nine-months ended September 30, 2003 and 2002.



|                                                      |  | Nine Months Ended September 30, 2003 |   
|----------------------------------------------------- |  | ------------------------------------ | --
|                                                      |  | GEN                                  |   
|                                                      |  | (in millions)                        |   
|Southern Power settlement                             |  | $                                    |  
|Kroger settlement                                     |  |                                      |  
|Sithe power tolling contract                          |  |                                      |  
|Accrual of new legal reserve                          |  |                                      |  
|Acceleration of financing costs                       |  |                                      |  
|Gain on sale of Hackberry LNG                         |  |                                      |  
|Discontinued operations                               |  |                                      |  
|Cumulative effect of changes in accounting principles |  |                                      | 47
|                                                      |  |                                      |   
|Total                                                 |  | $                                    | 47
|                                                      |  |                                      |   





|                                                    | 
|--------------------------------------------------- | 
|                                                    | 
|                                                    | 
|                                                    | 
|Discontinued operations                             | 
|Goodwill impairment                                 | 
|Impairment of generation investments                | 
|Impairment of technology investments                | 
|Restructuring costs                                 | 
|Enron settlement                                    | 
|Other (1)                                           | 
|Cumulative effect of change in accounting principle | 
|                                                    | 
|Total                                               | 
|                                                    | 

---

|(1) | We recognized a pre-tax charge of approximately $25 million related to the write-off of our investment in Dynegydirect. We also recognized a pre-tax charge of approximately $5
million related to information technology equipment write-offs. Additionally, we incurred approximately $6 million of pre-tax charges associated with fees related to a voluntary action that we took that altered the accounting for certain lease
obligations. These amounts are included in Impairment and other charges.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Segment Disclosures



Non-GAAP Financial
Measures. Management uses Earnings Before Interest and Taxes, or EBIT, as one measure of financial performance of our business segments. EBIT is a non-GAAP financial measure and consists of operating income, earnings from
unconsolidated investments, other income and expenses, net, minority interest income (expense), accumulated distributions associated with trust preferred securities, discontinued operations and cumulative effect of change in accounting principles.
EBIT does not include interest expense or income taxes, each of which is evaluated on a consolidated level. Because we do not allocate interest expense and income taxes by segment, management believes that EBIT is a useful measurement of our
segments operating performance for investors. EBIT should not be considered an alternative to, or more meaningful than, net income or cash flows from operations as determined in accordance with GAAP. Our segment EBIT may not be comparable to
similarly titled measures used by other companies.



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Power Generation



|                                                     |  | Three Months Ended September 30,           |       |      | Nine Months Ended September 30, |      
|---------------------------------------------------- |  | ------------------------------------------ | ----- | ---- | ------------------------------- | -----
|                                                     |  | 2003                                       |       | 2002 |                                 |      
|                                                     |  | (in millions, except operating statistics) |      
|Total Operating Income (Loss)                        |  | $                                          | 77    |      | $                               | (495 
|Earnings (losses) from unconsolidated investments    |  |                                            | 51    |      |                                 | (112 
|Other items, net                                     |  |                                            | 1     |      |                                 | (14  
|Cumulative effect of change in accounting principles |  |                                            |      |      |                                 |     
|                                                     |  |                                            |       |      |                                 |      
|Earnings (Losses) Before Interest and Taxes          |  | $                                          | 129   |      | $                               | (621 
|                                                     |  |                                            |       |      |                                 |      
|Operating Statistics:                                |  |                                            |       |      |                                 |      
|Million megawatt hours generatedgross               |  |                                            | 11.2  |      |                                 | 11.8 
|Million megawatt hours generatednet                 |  |                                            | 10.5  |      |                                 | 11.0 
|Average natural gas priceHenry Hub ($/MMbtu) (1)    |  | $                                          | 4.88  |      | $                               | 3.19 
|Average on-peak market power prices ($/MW hour)      |  |                                            |       |      |                                 |      
|Cinergy                                              |  | $                                          | 39.21 |      | $                               | 33.47
|Commonwealth Edison                                  |  |                                            | 39.34 |      |                                 | 31.91
|Southern                                             |  |                                            | 44.02 |      |                                 | 33.69
|New YorkZone G                                      |  |                                            | 61.46 |      |                                 | 55.75
|ERCOT                                                |  |                                            | 43.42 |      |                                 | 30.14

---

|(1) | Calculated as the median gas price for each day during the period.
|--- | ------------------------------------------------------------------



Three-Month Periods Ended September 30, 2003 and 2002



GEN reported EBIT of $129 million for the three-month period ended September 30, 2003 compared to $(621) million for the same period in 2002. EBIT
consists of the following amounts reported by GEN for the periods presented: operating income (loss) of $77 million and $(495) million, respectively; earnings (losses) from unconsolidated investments of $51 million and $(112) million, respectively;
and other items, net of $1 million and $(14) million, respectively. Results for the third quarter 2003 benefited from favorable commodity prices in the markets we serve. However, these benefits were offset by reduced demand in all regions other than
the Northeast resulting from milder than usual weather. Net electric power produced and sold was 10.5 million MW hours for the third quarter 2003, which represented a 4.5 percent decrease from 2002. Net MW hours generated in the Midwest in the third
quarter 2003 were 5.7 million, compared to 5.8 million during the third quarter 2002. In the Northeast, net MW hours generated in the third quarter 2003 were 1.8 million, compared to 0.9 million for the same period in 2002. The increase in the
Northeast resulted from significantly more production hours at our Roseton facility because of its ability to switch its fuel source to oil from natural gas and the pricing differences between oil and natural gas relative to power.



Given compressed natural gas spark spreads and overcapacity in the generation
marketplace, we expected break-even performance from our peaking generation facilities in 2003. Earnings from peaking generation facilities may include both capacity sales and energy sales components. The earnings from our peaking generation
facilities for the third quarter 2003 were better than we expected because summer capacity sales were greater than expected, which more than offset reduced energy sales resulting from compressed natural gas spark spreads and lower production hours.



GENs reported operating income for the third quarter
2003 also includes approximately $4.8 million in losses related to forward purchases and sales transactions that are recorded on a mark-to-market basis, as these transactions did not meet the criteria for hedge accounting under SFAS No. 133.
GENs third quarter 2002 results include approximately $3.5 million of mark-to-market income related to derivative contracts which did not qualify as hedges.



EBIT for the 2002 period also includes charges of $549 million for the impairment of goodwill.



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In the third quarter 2003, we recorded $51 million of earnings from unconsolidated investments, comprised
primarily of $37 million of earnings from our equity investment in West Coast Power. In the third quarter 2002, a $144 million impairment was recognized on our generation equity investments, including a $33 million impairment associated with our
West Coast Power investment. Excluding the impact of the impairment charge in 2002, earnings at West Coast Power were higher during 2003 due to higher realized margins resulting from forward hedges put in place in connection with the execution of
the West Coast Power-CDWR contract. Please read Item 1. BusinessSegment DiscussionPower Generation beginning on page 4 of our Form 10-K/A for further discussion of the West Coast Power-CDWR contract and the legal challenges
relating thereto.



In August and September 2003, we sold our
interests in the Frontier, Paris and Ferndale domestic projects located in Texas and Washington (aggregate net generating capacity of approximately 130 MW) and in two international projects located in Honduras and Pakistan (aggregate net generating
capacity of approximately 110 MW). Net proceeds associated with these sales were approximately $25 million. We recognized a net $1 million loss on these transactions.



Operating income for the three-month period ended September 30, 2002 reflects the sale to our CRM segment of the fair value
of GENs generation capacity, forward sales and related trading positions at an internally determined transfer price. For the three-month period ended September 30, 2003, operating income for the GEN segment reflects the sale of power to third
parties at market prices.



Nine-Month Periods Ended September 30, 2003 and
2002



GEN reported EBIT of $362 million for the nine-month
period ended September 30, 2003 compared to $(455) million for the same period in 2002. EBIT consists of the following amounts reported by GEN for the periods presented: operating income (loss) of $176 million and $(376) million, respectively;
earnings (losses) from unconsolidated investments of $135 million and $(50) million, respectively; other items, net of $4 million and $(29) million, respectively; and cumulative effect of change in accounting principle of $47 million and zero,
respectively. This segments results for the first nine months of 2003 reflected higher power prices as demand for power was higher in the Midwest and Northeast regions given colder than expected weather conditions during the first half of
2003. During the summer months, we experienced a reduced demand in power in all regions except the Northeast resulting from milder than usual weather. Net electric power produced and sold was 28.2 million MW hours for the first nine months of 2003,
which represented a 1 percent increase over the same period in 2002, primarily as a result of favorable winter weather conditions. Net MW hours generated in the Midwest and Northeast were 15.8 million and 4.3 million, respectively, for the first
nine months of 2003 compared to 14.9 million and 2.6 million, respectively, for the first nine months of 2002. Average on-peak prices in the Midwest and Northeast regions during the nine-month period ended September 30, 2003 increased 50 percent and
46 percent, respectively, from the corresponding prices for the nine-month period ended September 30, 2002. Results for the nine-month period ended September 30, 2003 also included a pre-tax charge of $15 million associated with a payment for the
early termination of an out-of-the-money power sales contract that was scheduled to expire on December 31, 2003.



Given compressed natural gas spark spreads and overcapacity in the generation marketplace, we expected breakeven performance from our peaking generation
facilities in 2003. Earnings from peaking generation facilities may include both capacity sales and energy sales components. The earnings from our peaking generation facilities for the nine months ended September 30, 2003 were better than we
expected because summer capacity sales were greater than expected, which more than offset reduced energy sales resulting from compressed natural gas spark spreads and lower production hours.



GENs reported operating income for the 2003 period also includes
approximately $3.6 million of mark-to-market income related to forward purchases and sales transactions which are recorded on a mark-to-market basis, as these transactions did not meet the criteria for hedge accounting under SFAS No. 133. GENs
results for the 2002 period include approximately $1.9 million of mark-to-market losses related to derivative contracts which did not qualify as hedges.



EBIT for the 2002 period includes charges of $549 million for the impairment of goodwill.



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In the nine months ended September 30, 2003, we recorded $135 million of earnings from unconsolidated
investments, comprised primarily of $102 million of earnings from our equity investment in West Coast Power. In the third quarter 2002, a $144 million impairment was recognized on our generation equity investments, including a $33 million impairment
associated with our West Coast Power investment. Excluding the impact of the impairment charge in 2002, earnings at West Coast Power were higher in the first nine months of 2003 due to higher realized margins resulting from forward hedges put in
place in connection with the execution of the West Coast Power-CDWR contract. Please read Item 1. BusinessSegment DiscussionPower Generation beginning on page 4 of our Form 10-K/A for further discussion of the West Coast
Power-CDWR contract and the legal challenges relating thereto.



In August and September 2003, we sold our interests in the Frontier, Paris and Ferndale domestic projects located in Texas and Washington (aggregate net generating capacity of approximately 130 MW) and in two international projects located
in Honduras and Pakistan (aggregate net generating capacity of approximately 110 MW). Net proceeds associated with these sales were approximately $25 million. We recognized a net $1 million loss on these transactions. Additionally, in the first
quarter 2003, we sold our interest in SouthStar Energy Services LLC for approximately $20 million and recognized a gain of approximately $1 million.



Operating income for the nine-month period ended September 30, 2002 reflects the sale to our CRM segment of the fair value of GENs generation
capacity, forward sales and related trading positions at an internally determined transfer price. For the nine-month period ended September 30, 2003, operating income for the GEN segment reflects the sale of power to third parties at market prices.



Power Generation Outlook



We expect that this segments future financial results will continue to
reflect a sensitivity to power prices, weather and other factors affecting generation demand, natural gas and other fuel prices (including, to a lesser extent, the spark spread, or price differential between natural gas and power), and
terms of contracts. We believe that our generation fleets fuel diversity will help mitigate the extent to which this segments future results are affected by changes in the spark spread. We also expect that this business will continue its
efforts to manage its price risk through the optimization of fuel procurement and the marketing of power generated from its assets. As part of our strategy of optimizing our assets, including agency and energy management agreements to which we are a
party, we enter into financial and other transactions, including forward hedge activities, relating to our generating capacity. We will also enter into sales of capacity from our generation assets, which can provide a revenue stream independent of
energy sales. This segments sensitivity to prices and our ability to manage this sensitivity is subject to a number of factors, including general market liquidity, particularly in forward years, our ability to provide necessary collateral
support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings. Other factors that could affect the prices at which transactions can be consummated and this segments results of
operations include transmission constraints, or the lack thereof, and governmental actions, excess generation capacity or supply shortages in the markets we serve. Please see Item 1. BusinessSegment DiscussionPower Generation
beginning on page 4 of our Form 10-K/A for a discussion of the effects of competition on this segments future results of operations.



Any events that negatively impact this segments significant long-term power sales agreements could likewise affect its future results of operations.
For example, equity earnings from West Coast Power are primarily derived from West Coast Powers long-term power sales contract with the CDWR. That contract, which runs through December 31, 2004, is the subject of various legal challenges. The
success of any such challenges could negatively impact this segments equity earnings from West Coast Power and, accordingly, results of operations for the periods affected.



Additionally, under an agreement conditioned upon the closing of the sale of substantially all of Illinois Powers
assets and liabilities to Exelon, we have contracted to sell 3,100 MW of generating capacity and 2,900 MW of generating capacity and energy to an Exelon subsidiary for six years beginning in January 2005. It is anticipated that this arrangement will
be in place concurrently with the termination of Dynegys power purchase agreement with Illinois Power, which expires in December 2004, and the closing of the transaction. Our failure to consummate the sale to Exelon and satisfy the condition
to the effectiveness of this agreement or to otherwise extend our current



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power purchase agreement with Illinois Power on substantially the same terms could also negatively impact this segments results of operations. Please
read Note 13Subsequent Event for a discussion of this agreement.





In August 2003, we reached an agreement to sell up to 500 MW of electricity capacity over a six-year period, with a five-year extension option, to
Georgia-based Cobb Electric Membership Corporation, the countrys second-largest electric membership corporation. The sale of capacity and energy will begin in January 2005 and is supported by the output from our 500 MW natural gas-fired
peaking facility in Franklin, Georgia.



We also are pursuing
additional sales of our ownership interests in a number of domestic and international generating projects that we consider non-strategic to this business. We generally hold ownership interests in these projects of 50% or less, which aggregates to
less than 700 MW of net generating capacity. Such projects contributed approximately $23 million to our results for the nine months ended September 30, 2003.



Natural Gas Liquids



|                                          |  | Three Months Ended September 30,           |       |   | Nine Months EndedSeptember 30, |  
|----------------------------------------- |  | ------------------------------------------ | ----- | - | ------------------------------ | -
|                                          |  | 2003                                       |       |   | 2002                           |  
|                                          |  | (in millions, except operating statistics) |      
|Operating Income:                         |  |                                            |       |   |                                |  
|Upstream                                  |  | $                                          | 31    |   |                                | $
|Downstream                                |  |                                            |      |   |                                |  
|                                          |  |                                            |       |   |                                |  
|Total Operating Income                    |  |                                            | 31    |   |                                |  
|Earnings from unconsolidated investments  |  |                                            | 2     |   |                                |  
|Other items, net                          |  |                                            | (2    | ) |                                |  
|Discontinued operations                   |  |                                            | (2    | ) |                                |  
|                                          |  |                                            |       |   |                                |  
|Earnings Before Interest and Taxes        |  | $                                          | 29    |   |                                | $
|                                          |  |                                            |       |   |                                |  
|Operating Statistics:                     |  |                                            |       |   |                                |  
|Natural gas processing volumes (MBbls/d): |  |                                            |       |   |                                |  
|Field plants                              |  |                                            | 61.5  |   |                                |  
|Straddle plants                           |  |                                            | 23.4  |   |                                |  
|                                          |  |                                            |       |   |                                |  
|Total natural gas processing volumes      |  |                                            | 84.9  |   |                                |  
|                                          |  |                                            |       |   |                                |  
|Fractionation volumes (MBbls/d)           |  |                                            | 186.8 |   |                                |  
|Natural gas liquids sold (MBbls/d)        |  |                                            | 276.1 |   |                                |  
|Average commodity prices:                 |  |                                            |       |   |                                |  
|Crude oilWTI ($/Bbl)                     |  | $                                          | 30.45 |   |                                | $
|Natural gasHenry Hub ($/MMbtu) (1)       |  | $                                          | 4.97  |   |                                | $
|Natural gas liquids ($/Gal)               |  | $                                          | 0.51  |   |                                | $
|Fractionation spread ($/MMBtu) (2)        |  | $                                          | 0.95  |   |                                | $

---

|(1) | Calculated as the average of the first of the month prices for the period.
|--- | --------------------------------------------------------------------------

|(2) | Calculated as the average daily fractionation spread for the period.
|--- | --------------------------------------------------------------------



Three-Month Periods Ended September 30, 2003 and 2002



NGL reported EBIT of $29 million for the three-month period ended September 30, 2003 compared to $20 million for the same period in 2002. EBIT consists of
the following amounts reported by NGL for the periods presented: operating income of $31 million and $29 million, respectively; earnings from unconsolidated investments of $2 million and $3 million, respectively; other items, net of $(2) million and
$(9) million, respectively; and discontinued operations of $(2) million and $(3) million, respectively.



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Upstream operating income increased period-over-period primarily as a result of higher natural gas and
natural gas liquids prices, which caused significantly increased processing plant margins at our plants that are not materially impacted by fractionation spread risk. Total volumes of liquids produced at our field plants increased 9 percent
period-over-period primarily due to increased production in the highly active drilling area in North Texas. Our straddle plant volumes were much lower period-to-period because of the low fractionation spread, which resulted in our decision to
by-pass unprofitable gas or to shut-down plants that are subject to significant fractionation spread risk.



In our downstream business, volumes fractionated declined 17 percent period-to-period as a direct result of the reduced liquids recovery from both our own
and third-party gas processing plants resulting from the low fractionation spread. In addition, demand by our petrochemical customers for lighter natural gas liquids, predominantly ethane, propane and mixtures of ethane and propane, has been
significantly reduced due to the lack of supply caused by reduced liquid recoveries and the concomitant increase in the price of such lighter natural gas liquids. An additional factor adversely affecting volumes fractionated is the expansion of Mont
Belvieu fractionation capacity beyond the availability of raw natural gas liquid supplies by some of our competitors over the last few years. The resulting competition for raw natural gas liquids supply has driven down the fees charged for
fractionation service in the Mont Belvieu area. As a result of such competition and customers concerns relating to our liquidity and non-investment grade credit status, we were unable to renew one of our long-term fractionation agreements
during the second quarter 2003. Subsequently, we have reduced our fees for fractionation services. Even at these lower fractionation fees, we both continue to make a margin providing such services, and generate additional margins in our other
downstream operations. In our wholesale marketing operations, profits were lower due to reduced propane sales and refinery services volumes, which were somewhat offset by the impact of higher liquids prices on our refinery services percentage of
netback contracts. Natural gas liquids marketing results declined slightly from prior period levels as a result of reduced overall market liquidity and customer concerns relating to our liquidity and non-investment grade credit status.
Downstream operating income for the three months ended September 30, 2002 also includes income of approximately $8 million related to our Canadian crude business, which was sold in August 2002. Our total marketed volumes declined from
approximately 482,000 barrels per day to approximately 276,000 barrels per day due to reduced domestic marketing opportunities and the divestiture of our global liquids business, effective January 1, 2003. The global liquids business sold an average
of 89,000 barrels per day in the third quarter of 2002.



Nine-Month Periods
Ended September 30, 2003 and 2002



NGL reported EBIT of
$113 million for the nine-month period ended September 30, 2003 compared to $65 million for the same period in 2002. EBIT consists of the following amounts reported by NGL for the periods presented: operating income of $121 million and $83 million,
respectively; earnings from unconsolidated investments of $7 million and $10 million, respectively; other items, net of $(12) million and $(20) million, respectively; and discontinued operations of $(3) million and $(8) million, respectively.



Upstream operating income increased period-over-period
primarily as a result of higher natural gas and natural gas liquids prices, which caused significantly increased processing plant margins at our plants that are not materially impacted by fractionation spread risk. Total volumes of liquids produced
at our field plants increased 8 percent period-over-period primarily due to increased production in the highly active drilling area in North Texas. Our straddle plant volumes were much lower period-to-period because of the low fractionation spread,
which resulted in our decision to by-pass unprofitable gas or to shut-down some of our plants that are subject to significant fractionation spread risk.



In our downstream business, volumes available for fractionation declined 18 percent period-to-period as a direct result of the reduced liquids recovery
from both our own and from third-party gas processing plants. In addition, demand by our petrochemical customers for lighter natural gas liquids, predominantly ethane, propane and mixtures of ethane and propane, has been significantly reduced due to
the lack of supply caused by reduced liquid recoveries and the concomitant increase in the price of such lighter natural gas liquids. An additional factor adversely affecting volumes fractionated is the expansion of Mont Belvieu fractionation
capacity beyond the availability of raw natural gas liquid supplies by some of our competitors over the last few years. The resulting competition for raw natural gas liquids supply has driven down the fees charged for fractionation service in the
Mont Belvieu area. As a result of such competition and customers concerns relating to our liquidity and non-



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investment grade credit status, we were unable to renew one of our long-term fractionation agreements during the second quarter 2003. Subsequently, we have
reduced our fees for fractionation services. Even at these lower fractionation fees, we both continue to make a margin providing such services, and generate additional margins in our other downstream operations. In our wholesale marketing
operations, profits were higher due to margin increases resulting from the impact of higher commodity prices on our percentage of netback contracts with our refinery services customers and weather-driven propane sales in the first quarter. Natural
gas liquids marketing results declined from prior period levels as a result of reduced overall market liquidity and customer concerns relating to our liquidity and non-investment grade credit status. Downstream operating income for the nine months
ended September 30, 2002 also includes income of approximately $18 million related to our Canadian crude business, which was sold in August 2002. Our marketed volumes declined from approximately 520,000 barrels per day to approximately 305,000
barrels per day due to reduced domestic marketing opportunities and the divestiture of our global liquids business, effective January 1, 2003. The global liquids business sold an average of 102,000 barrels per day in the first nine months of 2002.



NGL Outlook



Recent crude prices have averaged, and are expected to continue to average,
approximately $30 per barrel. Domestic natural gas prices are higher than historical levels averaging approximately $5.00 per MMBtu. Our upstream volumes under percentage of proceeds and percentage of liquids contracts will continue to benefit from
these relatively higher prices. However, liquids production from both our own and third-party natural gas processing plants that are exposed to keep whole economics will continue to be exposed to depressed fractionation spreads, even at these
relatively high commodity prices. As a result, we expect a continued reduction in the natural gas liquids that supply our fractionation, storage and distribution infrastructure. Industry-wide propane inventories are currently at the historical five
year average levels. Keep whole economics refers to arrangements under which a processor extracts natural gas liquids and returns to the producer volumes of merchantable natural gas containing the same Btu content as the unprocessed
natural gas that was delivered to the processor for processing. The processor retains the natural gas liquids as its fee for processing and must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus
that are removed through processing so that the producer is kept whole.



Drilling rig rates for natural gas throughout our core processing areas in New Mexico, West Texas, North Texas and offshore Louisiana continue to increase, consistent with natural gas prices that have been
consistently in the $5.00-6.00 per MMBtu range.



Despite
operational challenges caused by our non-investment grade credit ratings and a lack of market liquidity, NGL was able to meet its contractual obligations in its wholesale marketing business during the first nine months of 2003. Despite significant
competition, most of our customers generally are choosing to renew their contracts with us as they reach their current term. In the second quarter 2003, we lost one long term agreement for fractionation services in Mont Belvieu primarily due to our
unwillingness to provide such services at a fee that was unacceptable to us. While we have not experienced significant turnover in customer contracts as a result of our non-investment grade credit ratings, we have been required to provide collateral
or other adequate assurance of our obligations under the renewed contracts.



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Regulated Energy Delivery



|                                                    |  | Three Months EndedSeptember 30,            |       |      | Nine Months EndedSeptember 30, |      
|--------------------------------------------------- |  | ------------------------------------------ | ----- | ---- | ------------------------------ | -----
|                                                    |  | 2003                                       |       | 2002 |                                |      
|                                                    |  | (in millions, except operating statistics) |      
|Operating Income                                    |  | $                                          | 64    |      | $                              | 72   
|Earnings (losses) from unconsolidated investments   |  |                                            |      |      |                                |     
|Other items, net                                    |  |                                            |      |      |                                | (3   
|Discontinued operations                             |  |                                            |      |      |                                | (586 
|Cumulative effect of change in accounting principle |  |                                            |      |      |                                |     
|                                                    |  |                                            |       |      |                                |      
|Earnings Before Interest and Taxes                  |  | $                                          | 64    |      | $                              | (517 
|                                                    |  |                                            |       |      |                                |      
|Operating Statistics:                               |  |                                            |       |      |                                |      
|Electric sales in kWh                               |  |                                            |       |      |                                |      
|Residential                                         |  |                                            | 1,766 |      |                                | 1,832
|Commercial                                          |  |                                            | 1,208 |      |                                | 1,231
|Industrial                                          |  |                                            | 1,561 |      |                                | 1,667
|Transportation of customer-owned electricity        |  |                                            | 642   |      |                                | 622  
|Other                                               |  |                                            | 105   |      |                                | 98   
|                                                    |  |                                            |       |      |                                |      
|Total electric sales                                |  |                                            | 5,282 |      |                                | 5,450
|                                                    |  |                                            |       |      |                                |      
|Gas sales in Therms                                 |  |                                            |       |      |                                |      
|Residential                                         |  |                                            | 18    |      |                                | 18   
|Commercial                                          |  |                                            | 10    |      |                                | 11   
|Industrial                                          |  |                                            | 16    |      |                                | 24   
|Transportation of customer-owned gas                |  |                                            | 48    |      |                                | 47   
|                                                    |  |                                            |       |      |                                |      
|Total gas delivered                                 |  |                                            | 92    |      |                                | 100  
|                                                    |  |                                            |       |      |                                |      
|Cooling degree daysActual (1)                      |  |                                            | 773   |      |                                | 1,006
|Cooling degree days10 year rolling average         |  |                                            | 850   |      |                                | 860  
|Heating degree daysActual (2)                      |  |                                            | 88    |      |                                | 29   
|Heating degree days10 year rolling average         |  |                                            |      |      |                                |     



---

|(1) | A Cooling Degree Day (CDD) represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in our region. The CDDs for a
period of time are computed by adding the CDDs for each day during the period.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | A Heating Degree Day (HDD) represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in our region. The HDDs for a
period of time are computed by adding the HDDs for each day during the period.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Three-Month Periods Ended September 30, 2003 and 2002



EBIT for the REG segment was $64 million for the three-month period ended September 30, 2003 compared to $(517) million for the same period in 2002. EBIT consists of the following amounts reported by REG for the
periods presented: operating income of $64 million and $72 million, respectively; earnings from unconsolidated investments of zero for both comparative periods, respectively; other items, net of zero and $(3) million, respectively; and discontinued
operations of zero and $(586) million, respectively. Results were negatively impacted in 2003 by cooler than normal summer weather throughout REGs service territory, which caused decreases in residential and commercial electricity sales
volumes. Operating expenses for 2003 increased primarily due to higher insurance related claims expense and an increase in legal reserves as a result of additional activity during the quarter partially offset by operating efficiency gains. Lower
regulatory asset amortization in 2003 resulted from the additional regulatory asset amortization that was recorded late in 2002. EBIT for the three months ended September 30, 2002 also includes a loss from discontinued operations of approximately
$586 million related to Northern Natural, which was sold in August 2002.



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Nine-Month Periods Ended September 30, 2003 and 2002



EBIT for the REG segment was $155 million for the nine-month period ended
September 30, 2003 compared to $(385) million for the same period in 2002. EBIT consists of the following amounts reported by REG for the periods presented: operating income of $158 million and $168 million, respectively; earnings (losses) from
unconsolidated investments of zero and $(1) million, respectively; other items, net of zero and $(3) million, respectively; discontinued operations of zero and $(549) million, respectively; and cumulative effect of change in accounting principle of
$(3) million and zero, respectively. Results were negatively impacted in 2003 by cooler than normal spring and summer weather partially offset by colder than normal winter weather, which caused net decreases in residential and commercial electricity
sales volumes and increases in residential and commercial gas sales volumes. In 2002, revenues from the sale of electricity were positively affected by the reversal of a contingent liability related to the resolution of a billing dispute with a
large wholesale electric customer. In addition, 2003 revenues attributable to the sale of electricity to residential customers were negatively impacted by a five percent rate reduction effective May 1, 2002. Operating expenses for 2003 increased
primarily due to higher insurance related claims expense and an increase in legal reserves as a result of additional activity during the third quarter 2003, partially offset by operating efficiency gains. Lower regulatory asset amortization in 2003
resulted from the additional regulatory asset amortization that was recorded late in 2002. EBIT for the nine months ended September 30, 2002 also includes a loss from discontinued operations of approximately $549 million related to Northern Natural,
which was sold in August 2002.



REG Outlook



Future results of operations for the REG segment may be affected, either
positively or negatively, by regulatory actions (with respect to rates or otherwise), general economic conditions, weather, the demand for power and natural gas in Illinois, utilization of competitive alternate service providers by its customers and
financing costs. The effects of the REG segment on our consolidated results of operations will be significantly impacted by our ability to consummate the proposed sale of substantially all of Illinois Powers assets and liabilities to Exelon.
Please read Note 13Subsequent Event for further discussion of this proposed transaction.



Customer Risk Management



|                                                    |  | Three Months EndedSeptember 30, |     |   | Nine Months EndedSeptember 30, |  
|--------------------------------------------------- |  | ------------------------------- | --- | - | ------------------------------ | -
|                                                    |  | 2003                            |     |   | 2002                           |  
|                                                    |  | (in millions)                   |    
|Operating Loss                                      |  | $                               | (26 | ) |                                | $
|Losses from unconsolidated investments              |  |                                 | (2  | ) |                                |  
|Other items, net                                    |  |                                 | 4   |   |                                |  
|Discontinued operations                             |  |                                 | (6  | ) |                                |  
|Cumulative effect of change in accounting principle |  |                                 |    |   |                                |  
|                                                    |  |                                 |     |   |                                |  
|Loss Before Interest and Taxes                      |  | $                               | (30 | ) |                                | $
|                                                    |  |                                 |     |   |                                |  



Three-Month Periods Ended September
30, 2003 and 2002



CRM reported EBIT of $(30) million for
the three-month period ended September 30, 2003 compared to $(542) million for the same period in 2002. EBIT consists of the following amounts reported by CRM for the periods presented: operating loss of $26 million and $482 million, respectively;
losses from unconsolidated investments of $(2) million and $(10) million, respectively; other items, net, of $4 million and $(16) million, respectively; and discontinued operations of $(6) million and $(34) million, respectively.



Results in the third quarter of 2003 were adversely affected by losses
associated with capacity payments on the remaining tolling arrangements which exceeded the realized margin from the related sales of electricity. Total capacity payments impacting EBIT for the third quarter 2003 were approximately $59 million.
During the third quarter, we were able to terminate contracts with absolute positions of 1.5 MW and 157.2 Bcf with counterparties, resulting in a net loss of $3.5 million.



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EBIT for the 2002 period includes charges of $348 million for the impairment of goodwill.



During the three-month period ended September 30, 2002, the CRM segment was
actively managed as part of our ongoing strategy and its results included, in part, settlement with third parties of physical power and other trading positions purchased from our GEN segment at an internally determined transfer price. Please see
Note 11 to the accompanying unaudited condensed consolidated financial statements for further discussion.



Nine-Month Periods Ended September 30, 2003 and 2002



CRM reported EBIT of $(295) million for the nine-month period ended September 30, 2003 compared to $(886) million for the same period in 2002. EBIT consists of the following amounts reported by CRM for the periods
presented: operating loss of $348 million and $809 million respectively; losses from unconsolidated investments of zero and $(25) million, respectively; other items, net, of $27 million and $(29) million, respectively; discontinued operations of
$(17) million and $(23) million, respectively; and cumulative effect of change in accounting principle of $43 million and zero, respectively.



Results associated with this business benefited primarily from sales of natural gas in storage which had previously been recorded at fair value (see Note
1 to the unaudited condensed consolidated financial statements for additional details) more than offset by the following pre-tax losses: $133 million associated with the settlement of power tolling arrangements with Southern Power, for which we paid
$155 million; $30 million associated with the settlement of power supply agreements with Kroger, for which we received approximately $110 million; and a $125 million mark-to-market loss on contracts associated with the Sithe Independence power
tolling arrangement. In addition, results include losses associated with capacity payments on remaining tolling arrangements.



EBIT for the 2002 period includes charges of $348 million for the impairment of goodwill.



During the nine-month period ended September 30, 2002, the CRM segment was actively managed as part of our ongoing strategy
and its results included, in part, settlement with third parties of physical power and other trading positions purchased from our GEN segment at an internally determined transfer price. Please see Note 11 to the accompanying unaudited condensed
consolidated financial statements for further discussion.



CRM Outlook



Our CRM business future results of operations will
be significantly impacted by our ability to execute our exit strategy. We continue to pursue opportunities to assign or renegotiate the terms of many of our contractual obligations related to this business, including some of our power tolling
arrangements. In April 2003, we reached an agreement in principle with Southern Power to terminate three power tolling arrangements among Dynegy, Southern Power and our respective affiliates covering an aggregate of 1,100 MW. Under the terms of the
agreement, we paid Southern Power $155 million to terminate these arrangements. The terminations resulted in approximately $89 million of collateral being returned to us and eliminated our obligation to make $1.7 billion in payments due to Southern
Power over the next 30 years.



If we do not renegotiate or
terminate the remaining five power tolling arrangements to which we remain a party, we will be required to pay an aggregate amount of approximately $1.9 billion in capacity payments under the related agreements through 2014. After applying a
LIBOR-based discount rate, the total of these capacity payments approximates $1.6 billion. Our capacity payments for the remainder of 2003 are $42 million. In the current pricing environment, these power tolling arrangements will continue to
negatively impact our earnings and cash flow. Even if we do renegotiate or terminate some of these arrangements, we could be required to pay a significant amount of cash relating to any such renegotiation or termination.



In addition, we have posted collateral to support a substantial portion of
our obligations in this business, including approximately $40 million at September 30, 2003 posted in connection with our power tolling arrangements. While we have been working with various counterparties to provide mutually acceptable collateral or



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other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and
Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral. Although we are current on all contract payments to these counterparties, we previously received a notice of default from each such party with regard to collateral.
Despite receiving these notices, all parties are continuing to perform and we have fulfilled our economic commitments under these contracts. Our average annual capacity payments under these two arrangements approximate $75 million and $63 million,
respectively, and the contracts extend through 2014 and 2012, respectively. If these counterparties were successful in pursuit of claims that we defaulted on these contracts, they could declare a termination of these contracts, which would provide
for termination payments based on the mark-to-market value of the contracts.



While we generally have been successful in satisfying customer collateral requirements, we are involved in disputes with some of our counterparties relating to contracts with respect to which we were unable to agree
on mutually acceptable collateral or other adequate assurance. There is also risk that we may be unable to agree with some of our other counterparties on mutually acceptable forms and amounts of adequate assurance or other collateral, resulting in
additional disputes and related expenses. We intend to defend against these claims vigorously and, while we could be required to post additional amounts of collateral, we do not expect that any liability we might incur in connection with these
disputes will materially adversely affect our financial condition, results of operations or cash flows.



Cash Flow Disclosures



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



|                                                       |  | For the Nine Months Ended September 30, 2003
|------------------------------------------------------ |  | --------------------------------------------
|                                                       |  | GEN                                         
|                                                       |  | (in millions)                               
|Operating Cash Flows Before Changes in Working Capital |  | $                                           
|Changes in Working Capital                             |  |                                             
|                                                       |  |                                             
|Net Cash Provided by (Used in) Operating Activities    |  | $                                           
|                                                       |  |                                             



Operating Cash
Flow. Cash flow from operating activities totaled $934 million for the nine-month period ended September 30, 2003 compared to $262 million reported in the same 2002 period. Adjustments to net income were greater in the 2002 period, primarily
due to an $897 million goodwill impairment in our GEN and CRM segments, $699 million of impairment and other charges in the nine months ended September 30, 2002, a $586 million loss on the sale of Northern Natural and a $234 million impairment of
goodwill for the communications business related to the adoption of SFAS No. 142 in the first quarter 2002. Additional adjustments from the 2002 to 2003 period included the following:



| |  | Adjustment for (Earnings) losses from unconsolidated investments, net of cash distributions, decreased by approximately $218 million. The decrease primarily results from the $144
million impairment of GEN investments and $31 million in impairments of technology investments recorded in 2002;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Risk-management activities produced a $378 million adjustment, compared to an adjustment of $527 million in the 2002 period. Adjustments in both years primarily represent
mark-to-market losses in excess of net cash realized for settled contracts; and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Deferred income taxes are a $119 million benefit for the nine months ended September 30, 2003, compared to a benefit of $414 million in the same 2002 period, producing a $295
million decreased adjustment.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Changes in working capital had a positive impact of $507 million on cash flow from operations for the
nine months ended September 30, 2003. Our CRM segment recognized positive changes in working capital cash flows of $575 million. These cash flows primarily consist of approximately $250 million in reductions in prepayments in our US and UK CRM
businesses, due to the wind-down of such businesses, and proceeds of approximately $120 million related to the sale of natural gas inventory in the first quarter 2003. The remaining cash flows primarily relate to net cash collections due to the
wind-down of our CRM businesses.



Other and Eliminations
positive changes in working capital cash flows of $43 million primarily consist of a $110 million tax refund received in March 2003, partially offset by a $45 million litigation payment in the second quarter 2003 and other miscellaneous items.



Our GEN, REG and NGL segments negative changes in
working capital cash flows of $111 million primarily consist of inventory builds in our REG and NGL segment, as well as an increase in prepayments in the NGL segment.



Capital Expenditures and Investing Activities. Cash used in investing activities during the nine-month period
ended September 30, 2003 totaled $202 million. Capital spending of $259 million was primarily comprised of $117 million, $101 million and $36 million in the GEN, REG and NGL segments, respectively, primarily representing improvements to the existing
asset base. The capital spending for the GEN segment includes approximately $39 million spent on the construction of Rolling Hills, with respect to which commercial operation began in June 2003. Proceeds from asset sales primarily include $20
million in proceeds from the sale of SouthStar and $20 million in proceeds from the sale of Hackberry LNG Terminal LLC, offset by $10 million in cash outflows associated with the sale of our European communications business. Finally, proceeds from
the sale of unconsolidated investments totaled approximately $25 million.



Cash provided by investing activities in the first nine months of 2002 totaled $350 million. Capital expenditures and investments in unconsolidated affiliates of $810 million primarily relate to the construction and
improvement of power generation assets and investments associated with technology infrastructure. The business acquisitions cash outflows of $20 million relate to the acquisition of Northern Natural, net of cash acquired. These cash outflows were
offset by $1,105 million in proceeds primarily from the sales of Northern Natural and the Hornsea UK Storage facility. Other investing activities include proceeds from the sale of Northern Natural bonds.



Financing Activities. Cash used in financing activities during
the nine-month period ended September 30, 2003 totaled $808 million. During the nine months ended September 30, 2003, we repaid $128 million, net, under our revolving credit facilities. Long-term debt proceeds, net of issuance costs, for the nine
months ended September 30, 2003 consisted of $1,608 million associated with the August 2003 refinancing, $142 million from the delayed issuance of $150 million in Illinois Power 11.5% Mortgage Bonds due 2010 and $159 million from the Term A Loan
drawn in connection with the April 2, 2003 credit facility restructuring. In addition, in connection with the August 2003 refinancing, we made a $225 million cash payment to ChevronTexaco. Repayments of long-term debt totaled $2,352 million for the
nine months ended September 30, 2003 and consisted of the following:



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



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



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



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



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



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



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



80



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



| |  | Funding of $62 million in payments under the Black Thunder secured financing;
| | - | -----------------------------------------------------------------------------



| |  | Funding of $55 million in payments under the ABG Gas Supply financing;
| | - | ----------------------------------------------------------------------



| |  | Purchase of $5 million of Illinova senior notes on the open market; and
| | - | -----------------------------------------------------------------------



| |  | Funding of $2 million in payments on the junior notes.
| | - | ------------------------------------------------------



Net cash provided by financing activities was $101 million during the first nine months of 2002. We received $205 million in cash proceeds related to
ChevronTexacos January 2002 purchase of approximately 10.4 million shares of Class B common stock pursuant to its preemptive rights under our shareholder agreement. Capital stock proceeds also include $24 million of cash inflows associated
with cash received from senior management associated with a December 2001 private placement of shares of our Class A common stock. During the nine-month period ended September 30, 2002, dividends of $40 million were paid to the holders of Class A
common stock and $15 million was paid to the holder of Class B common stock. In March 2002, Illinova consummated a tender offer pursuant to which it paid $28 million in cash for approximately 73 percent of the then-outstanding shares of Illinois
Powers preferred stock. Net long-term debt proceeds consisted primarily of the February 2002 issuance by DHI of 8.75% senior notes due February 2012 and proceeds from borrowings incurred by ABG Gas Supply.



Repayments of long-term borrowings consisted of the following:



| |  | $66 million in transitional funding notes relating to Illinois Power;
| | - | ---------------------------------------------------------------------



| |  | $90 million relating to the April 2002 purchase of Northern Naturals senior unsecured notes due 2005;
| | - | ------------------------------------------------------------------------------------------------------



| |  | $73 million in principal payments related to the Black Thunder financing;
| | - | -------------------------------------------------------------------------



| |  | $200 million relating to the July 2002 DHI 6.875% senior note repayment;
| | - | ------------------------------------------------------------------------



| |  | $96 million relating to the July 2002 IP mortgage bond repayment; and
| | - | ---------------------------------------------------------------------



| |  | $45 million in repayments by ABG Gas Supply.
| | - | --------------------------------------------



Net proceeds from short-term financing consisted of a $245 million cash advance for the anticipated sale of certain U.K. gas storage assets as well as
$192 million in financings secured by interests in two of our generating facilities. Restricted cash increased by $179 million, primarily due to cash received related to the sale of our Hornsea natural gas storage facility, which proceeds were
required to be used to repay a portion of the $245 million cash advance. Finally, we repaid commercial paper and borrowings under revolving credit lines for DHI and Illinois Power of $500 million, borrowed $60 million under IPs term loan and
drew upon $137 million under the Companys revolvers.



81



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RISK-MANAGEMENT DISCLOSURES



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



|                                                                                            |  | As of and for the Nine Months EndedSeptember 30, 2003 |     
|------------------------------------------------------------------------------------------- |  | ----------------------------------------------------- | ----
|                                                                                            |  | (in millions)                                         |     
|Balance Sheet Risk-Management Accounts                                                      |  |                                                       |     
|Fair value of portfolio at January 1, 2003                                                  |  | $                                                     | 363 
|Risk-management losses recognized through the income statement in the period, net (1)       |  |                                                       | (161
|Cash received related to risk-management contracts settled in the period, net (2)           |  |                                                       | (259
|Changes in fair value as a result of a change in valuation technique (3)                    |  |                                                       |    
|Non-cash adjustments and other (4)                                                          |  |                                                       | (52 
|                                                                                            |  |                                                       |     
|Fair value of portfolio at September 30, 2003                                               |  | $                                                     | (109
|                                                                                            |  |                                                       |     
|                                                                                            | 
|Income Statement Reconciliation                                                             |  |                                                       |     
|Risk-management losses recognized through the income statement in the period, net (1)       |  | $                                                     | (161
|Physical business recognized through the income statement in the period, net                |  |                                                       | (126
|Non-cash adjustments and other                                                              |  |                                                       | 4   
|                                                                                            |  |                                                       |     
|Net recognized operating loss                                                               |  | $                                                     | (283
|                                                                                            |  |                                                       |     
|                                                                                            | 
|Cash Flow Statement                                                                         |  |                                                       |     
|Cash received related to risk-management contracts settled in the period, net (2)           |  | $                                                     | 259 
|Estimated cash received related to physical business settled in the period, net             |  |                                                       | (126
|Timing and other, net (5)                                                                   |  |                                                       | (38 
|                                                                                            |  |                                                       |     
|Cash received during the period                                                             |  | $                                                     | 95  
|                                                                                            |  |                                                       |     
|                                                                                            | 
|Risk-Management cash flow adjustment for the nine-month period ended September 30, 2003 (6) |  | $                                                     | 378 
|                                                                                            |  |                                                       |     

---

|(1) | This amount consists primarily of $125 million in mark-to-market losses on contracts associated with the Sithe Independence power tolling arrangement and a $30 million
mark-to-market loss associated with the settlement of power supply agreements with Kroger.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | This amount consists primarily of the Kroger settlement of approximately $110 million and cash received due to the wind-down of our CRM business.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Our modeling methodology has been consistently applied.
|--- | -------------------------------------------------------

|(4) | This amount primarily consists of approximately $97 million of risk-management assets that were removed from the risk-management accounts at January 1, 2003 in conjunction with the
adoption of certain provisions of EITF Issue 02-03. This amount is offset primarily by changes in value associated with cash flow hedges.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) | This amount consists primarily of cash received in connection with the settlement of cash flow hedges.
|--- | ------------------------------------------------------------------------------------------------------

|(6) | This amount is calculated as Cash received during the period less Net recognized operating loss.
|--- | ----------------------------------------------------------------------------------------------------



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Risk-Management Asset and Liability Disclosures. The following tables depict the
mark-to-market value and cash flow components of our net risk-management assets and liabilities at September 30, 2003 and December 31, 2002:



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



|                   |  | Total         |      |   | 2003(2) |   |      | 2004 |  |   | 2005 |   |  | 2006 |     |   | 2007 |   |     | Thereafter | 
|------------------ |  | ------------- | ---- | - | ------- | - | ---- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- | 
|                   |  | (in millions) |     
|September 30, 2003 |  | $             | (143 | ) |         | $ | 4    |      |  | $ | (20  | ) |  | $    | (25 | ) |      | $ | (25 | )          | 
|December 31, 2002  |  |               | 363  |   |         |   | 250  |      |  |   | 24   |   |  |      | 52  |   |      |   | 27  |            | 
|                   |  |               |      |   |         |   |      |      |  |   |      |   |  |      |     |   |      |   |     |            | 
|Decrease (3)       |  | $             | (506 | ) |         | $ | (246 | )    |  | $ | (44  | ) |  | $    | (77 | ) |      | $ | (52 | )          | 
|                   |  |               |      |   |         |   |      |      |  |   |      |   |  |      |     |   |      |   |     |            | 

---

|(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, 2003 of $109 million on the unaudited condensed consolidated balance sheets include the $143
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, 2003 values in the September 30, 2003 row and January 1 to December 31, 2003 values in the December 31, 2002 row.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | The decreases in the Net Risk-Management Assets and Liabilities were impacted most significantly by the adoption of EITF Issue 02-03 (which resulted in a decrease of approximately
$97 million), the mark-to-market loss on contracts associated with the Sithe Independence power tolling arrangement (which resulted in a decrease of approximately $125 million), the receipt of approximately $110 million in cash associated with the
Kroger settlement and cash received associated with the wind-down of our CRM business.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Cash Flow Components of Net Risk-Management Asset



|                       |  | Nine MonthsEndedSeptember 30,2003 |     | Three MonthsEndedDecember 31,2003 |   | Total2003 |  | 2004 |     |  | 2005 |     |   | 2006 |   |     | 2007 |  |   | Thereafter |  
|---------------------- |  | --------------------------------- | --- | --------------------------------- | - | --------- |  | ---- | --- |  | ---- | --- | - | ---- | - | --- | ---- |  | - | ---------- | -
|                       |  | (in millions)                     |    
|September 30, 2003 (1) |  | $                                 | 259 |                                   | $ | 6         |  | $    | 265 |  | $    | (17 | ) |      | $ | (25 | )    |  | $ | (27        | )
|December 31, 2002      |  |                                   |     |                                   |   |           |  |      | 259 |  |      | 43  |   |      |   | 57  |      |  |   | 36         |  
|                       |  |                                   |     |                                   |   |           |  |      |     |  |      |     |   |      |   |     |      |  |   |            |  
|Increase (Decrease)    |  |                                   |     |                                   |   |           |  | $    | 6   |  | $    | (60 | ) |      | $ | (82 | )    |  | $ | (63        | )
|                       |  |                                   |     |                                   |   |           |  |      |     |  |      |     |   |      |   |     |      |  |   |            |  

---

|(1) | The cash flow values for 2003 reflect realized cash flows for the nine months ended September 30, 2003 and anticipated undiscounted cash inflows and outflows by contract based on
the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative
instruments designated as hedges.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The following
table provides an assessment of net contract values by year as of September 30, 2003, based on our valuation methodology.



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##### Table of Contents

Net Fair Value of Risk-Management Portfolio



|                           |  | Total         |      |   | 2003 |   | 2004 |  |   | 2005 |   |  | 2006 |     |   | 2007 |   |     | Thereafter | 
|-------------------------- |  | ------------- | ---- | - | ---- | - | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- | 
|                           |  | (in millions) |     
|Market Quotations (1)      |  | $             | (76  | ) |      | $ | 4    |  | $ | (20  | ) |  | $    | (25 | ) |      | $ | (8  | )          | 
|Prices Based on Models (2) |  |               | (67  | ) |      |   |     |  |   |     |   |  |      |    |   |      |   | (17 | )          | 
|                           |  |               |      |   |      |   |      |  |   |      |   |  |      |     |   |      |   |     |            | 
|Total                      |  | $             | (143 | ) |      | $ | 4    |  | $ | (20  | ) |  | $    | (25 | ) |      | $ | (25 | )          | 
|                           |  |               |      |   |      |   |      |  |   |      |   |  |      |     |   |      |   |     |            | 

---

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

|(2) | See discussion of our use of long-term models in Critical Accounting Policies beginning on page 74 in our Form 10-K/A.
|--- | ------------------------------------------------------------------------------------------------------------------------



UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION



This quarterly report 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.
Important factors that could cause a material difference in the actual results from the forward-looking statements are set forth elsewhere in this quarterly report. You can identify these statements by the fact that they do not relate strictly to
historical or current facts. They use words such as anticipate, estimate, project, forecast, plan, may, will, should, expect and other words
of similar meaning. In particular, these include, but are not limited to, statements relating to the following:



| |  | projected operating or financial results;
| | - | -----------------------------------------



| |  | expectations regarding capital expenditures, debt service and other payments;
| | - | -----------------------------------------------------------------------------



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



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



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



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



| |  | our ability to consummate the proposed sale of Illinois Power to Exelon; and
| | - | ----------------------------------------------------------------------------



| |  | our ability to complete our exit from the CRM business and the costs associated with this exit.
| | - | -----------------------------------------------------------------------------------------------



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



| |  | the timing and extent of changes in commodity prices, particularly for power, natural gas, natural gas liquids and other fuels and, to a lesser extent, the spark spread between
power and natural gas prices and the fractionation spread between natural gas and natural gas liquids prices;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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| |  | the effects of the proposed sale of Illinois Power;
| | - | ---------------------------------------------------



| |  | the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions, and our financial condition,
including our ability to satisfy our significant debt maturities;
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | developments in the western power and natural gas markets, including, but not limited to, governmental intervention, deterioration in the financial condition of our counterparties,
default on receivables due and adverse results in current or future investigations or litigation;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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



| |  | increased interest expense and the other effects of our restructured credit facilities and our recently issued second priority senior secured notes, convertible subordinated
debentures, junior notes and Series C preferred stock, including the security arrangements and/or restrictive covenants contained therein;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | our ability to manage capital expenditures and costs (including general and administrative expenses) tightly and to generate sustainable earnings and cash flow from our assets and
businesses;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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



| |  | general political conditions and developments in the United States and in foreign countries whose affairs affect our lines of business, particularly commodity prices, including any
extended period of war or conflict.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition,
there may be other factors that could cause our actual results to be materially different from the results referenced in the forward-looking statements. Many of these factors will be important in determining our actual future results. Consequently,
no forward-looking statement can be guaranteed. Our actual future results may vary materially from those expressed or implied in any forward-looking statements.



85



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



RECENT ACCOUNTING PRONOUNCEMENTS



See Note 1 to the unaudited condensed consolidated
financial statements for a discussion of recently issued accounting pronouncements affecting us. Specifically, we adopted the net presentation provisions of EITF Issue 02-03 in the third quarter 2002, and we adopted the provision within EITF Issue
02-03 that rescinds EITF Issue 98-10 effective January 1, 2003. We also adopted SFAS No. 143 effective January 1, 2003. We adopted SFAS No. 150 and EITF Issue 03-11 effective July 1, 2003.



CRITICAL ACCOUNTING POLICIES



Please read Critical Accounting Policies beginning on page 74 of
our Form 10-K/A for a complete description of our critical accounting policies, with respect to which there have been no material changes since the filing of our Form 10-K/A.



Item 3QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK



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



Daily and Average VaR for Risk-Management Portfolio



|                                                                 |  | September 30,2003 |   | December 31,2002
|---------------------------------------------------------------- |  | ----------------- | - | ----------------
|                                                                 |  | (in millions)    
|One Day VaR95% Confidence Level                                 |  | $                 | 5 |                 
|One Day VaR99% Confidence Level                                 |  | $                 | 7 |                 
|Average VaR for the Year-to-Date Period95% Confidence Level (1) |  | $                 | 7 |                 

---

|(1) | Average VaR is not available for 2002 due to the restatement of historical results.
|--- | -----------------------------------------------------------------------------------



Credit Risk. The following table represents our credit exposure at September 30, 2003 associated with the
mark-to-market portion of our risk-management portfolio, including the Sithe Independence power tolling arrangement, netted by counterparty.



Credit Exposure Summary



|                                |  | InvestmentGrade Quality |     | Non-InvestmentGrade Quality |   | Total
|------------------------------- |  | ----------------------- | --- | --------------------------- | - | -----
|                                |  | (in millions)          
|Type of Business:               |  |                         |     |                             |   |      
|Financial Institutions          |  | $                       | 151 |                             | $ |     
|Commercial/Industrial/End Users |  |                         | 45  |                             |   | 56   
|Utility and Power Generators    |  |                         | 22  |                             |   |     
|Oil and Gas Producers           |  |                         | 45  |                             |   | 6    
|Other                           |  |                         | 1   |                             |   |     
|                                |  |                         |     |                             |   |      
|Total                           |  | $                       | 264 |                             | $ | 62   
|                                |  |                         |     |                             |   |      



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Of the $62 million in credit exposure to non-investment grade counterparties, approximately 94% ($58
million) is collateralized or subject to other credit exposure protection, such as master netting agreements or accounts payable offsets.



Interest Rate Risk. The following table sets forth the daily and average VaR associated with the interest rate component of the
risk-management portfolio. We seek to manage our interest rate exposure through application of various hedging strategies. Hedging instruments executed to mitigate such interest rate exposure in the risk-management portfolio are included in the VaR
as of September 30, 2003 and December 31, 2002 and are reflected in the table below.



Daily and Average VaR on Interest Component of Risk-Management Portfolio



|                                                                 |  | September 30,2003 |     | December 31,2002
|---------------------------------------------------------------- |  | ----------------- | --- | ----------------
|                                                                 |  | (in millions)    
|One Day VaR95% Confidence Level                                 |  | $                 | 0.6 |                 
|Average VaR for the Year-to-Date Period95% Confidence Level (1) |  | $                 | 1.6 |                 

---

|(1) | Average VaR is not available for 2002 due to the restatement of historical results.
|--- | -----------------------------------------------------------------------------------



The decrease in One Day VaR is due to the wind down of the CRM business and the resulting decrease in the size of our
risk-management portfolio.



In addition to the risk-management
portfolio, we are exposed to fluctuating interest rates related to other variable rate financial obligations. Based on sensitivity analysis as of September 30, 2003, it is estimated that a one percentage point interest rate movement in the average
market interest rates (either higher or (lower)) over the twelve months ended September 30, 2004 would (decrease) increase income before taxes by approximately $7 million. Hedging instruments executed to mitigate such interest rate exposure are
included in the sensitivity analysis. The sensitivity analysis does not include any impact related to our October 2003 follow-on notes offering described elsewhere in this report.



Foreign Currency Exchange Rate Risk. The following table sets forth the daily and average foreign currency
exchange VaR. Hedging instruments executed to mitigate such foreign currency exchange exposure are included in the VaR as of September 30, 2003 and December 31, 2002 and are reflected in the table below.



Daily and Average Foreign Currency Exchange VaR



|                                                             |  | September 30,2003 |      | December 31,2002
|------------------------------------------------------------ |  | ----------------- | ---- | ----------------
|                                                             |  | (in millions)    
|One Day VaR95% Confidence Level                             |  | $                 | 0.04 |                 
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $                 | 0.30 |                 



The decrease in One
Day and Average VaR is due to the significant reduction in foreign activities in the first nine months of 2003.



87



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Derivative Contracts. The absolute notional financial contract amounts associated with our
commodity risk-management, interest rate and foreign currency exchange contracts were as follows at September 30, 2003 and December 31, 2002, respectively:



Absolute Notional Contract Amounts



|                                                                     |  | September 30,2003 |        | December 31,2002
|-------------------------------------------------------------------- |  | ----------------- | ------ | ----------------
|Natural Gas (Trillion Cubic Feet)                                    |  |                   | 3.235  |                 
|Electricity (Million Megawatt Hours)                                 |  |                   | 10.424 |                 
|Natural Gas Liquids (Million Barrels)                                |  |                   | 0.060  |                 
|Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)   |  | $                 | 25     |                 
|Fixed Interest Rate Received on Swaps (Percent)                      |  |                   | 5.706  |                 
|Cash Flow Hedge Interest Rate Swaps (In Millions of U.S. Dollars)    |  | $                 | 500    |                 
|Fixed Interest Rate Paid on Swaps (Percent)                          |  |                   | 3.458  |                 
|Interest Rate Risk-Management Contract (In Millions of U.S. Dollars) |  | $                 | 240    |                 
|Fixed Interest Rate Paid (Percent)                                   |  |                   | 6.700  |                 
|U.K. Pound Sterling (In Millions of U.S. Dollars)                    |  | $                 |       |                 
|Average U.K. Pound Sterling Contract Rate (In U.S. Dollars)          |  | $                 |       |                 
|Euro Dollars (In Millions of U.S. Dollars)                           |  | $                 |       |                 
|Average Euro Contract Rate (In U.S. Dollars)                         |  | $                 |       |                 
|Canadian Dollar (In Millions of U.S. Dollars)                        |  | $                 |       |                 
|Average Canadian Dollar Contract Rate (In U.S. Dollars)              |  | $                 |       |                 



Item 4CONTROLS AND PROCEDURES



Effective as of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of our establishment of a disclosure committee and the
various processes that were carried out under the direction of this committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by
the SEC. This evaluation also included consideration of our internal controls and procedures for the preparation of our consolidated financial statements. While we have previously identified internal control weaknesses, which are discussed below,
our evaluation indicated that these weaknesses did not impair the effectiveness of our overall disclosure controls and procedures.



Reference is made to Item 14. Controls and Procedures beginning on page 84 of our Form 10-K/A. In that section, we indicated that in
evaluating our internal controls in connection with the preparation of our Form 10-K/A we identified two reportable conditions that were considered to be material weaknesses under applicable accounting standards. The first such condition
related to the fact that inappropriate persons within our organization had access to record or revise entries in our accounting software system. The second such condition related to the process whereby accrued estimates of volumes bought, sold,
transported and stored in our natural gas marketing business were reconciled to the actual volumes. We also identified the measures we had taken toward remedying these conditions, as well as other initiatives being implemented with respect to our
system of internal controls generally.



During our most recent
evaluation undertaken in connection with the preparation of this quarterly report, we did not discover any additional reportable conditions with respect to our internal controls. Regarding the previously identified access condition, we completed the
implementation of a technical solution during the third quarter 2003 designed to reduce the access to our accounting system significantly. Additionally, for certain individuals with broader access rights, reporting tools will be employed to monitor
their specific activities.



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DYNEGY INC.



PART II. OTHER INFORMATION



Item 1LEGAL PROCEEDINGS



See Note 9 to the accompanying unaudited condensed consolidated financial statements for discussion of the material legal proceedings to which we are a party.



Item 6EXHIBITS AND REPORTS ON FORM 8-K



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



4.1

Statement of Resolution Establishing Series of Series C Convertible Preferred Stock of Dynegy Inc. (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q
for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.2

Exchange and Registration Rights Agreement (Preferred Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.2 to the
Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.3

Exchange and Registration Rights Agreement (Notes) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.3 to the Quarterly
Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.4

Amended and Restated Registration Rights Agreement (Common Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.4 to
the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.5

Amended and Restated Shareholder Agreement dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.5 to the Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.6

Indenture dated August 11, 2003 between Dynegy Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the
Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.7

Junior Unsecured Subordinated Note due 2016 in the principal amount of $225,000,000 issued on August 11, 2003 by Dynegy Inc. to Chevron U.S.A. Inc. (incorporated by reference to
Exhibit 4.7 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.8

Indenture dated as of August 11, 2003 among Dynegy Holdings Inc., the guarantors named therein, Wilmington Trust Company, as trustee, and Wells Fargo Bank Minnesota, N.A., as
collateral trustee, including the form of promissory note for each series of notes issuable pursuant to the Indenture (incorporated by reference to Exhibit 4.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of
Dynegy Inc., File No. 1-15659).4.9

Indenture dated August 11, 2003 between Dynegy Inc., Dynegy Holdings Inc. and Wilmington Trust Company, as trustee, including the form of debenture issuable pursuant to the
Indenture (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).4.10

Registration Rights Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein (incorporated by reference to Exhibit 4.10 to
the




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|       | 
|------ | 
|       | 
|       | 
|4.11   | 
|       | 
|4.12   | 
|       | 
|+ 10.1 | 
|       | 
|+ 10.2 | 
|       | 
|10.3   | 
|       | 
|10.4   | 
|       | 
|10.5   | 
|       | 
|10.6   | 
|       | 
|10.7   | 
|       | 
|10.8   | 
|       | 
|10.9   | 
|       | 
|10.10  | 
|       | 
|10.11  | 



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|      | 
|----- | 
|      | 
|      | 
|10.12 | 
|      | 
|10.13 | 
|      | 
|+31.1 | 
|      | 
|+31.2 | 
|      | 
|*32.1 | 
|      | 
|*32.2 | 

---

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

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



(b) Reports on Form 8-K of Dynegy Inc. filed for the third quarter 2003:



| | 1. | We filed a Current Report on Form 8-K on July 2, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | --------------------------------------------------------------------------------------------------------------------------



| | 2. | We filed a Current Report on Form 8-K on July 7, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | --------------------------------------------------------------------------------------------------------------------------



| | 3. | We filed a Current Report on Form 8-K on July 15, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | ---------------------------------------------------------------------------------------------------------------------------



| | 4. | We filed a Current Report on Form 8-K on July 18, 2003. Items 7 and 9 were reported and no financial statements were filed.
| | -- | ---------------------------------------------------------------------------------------------------------------------------



| | 5. | We filed a Current Report on Form 8-K on July 28, 2003. Items 5, 7 and 9 were reported and no financial statements were filed.
| | -- | ------------------------------------------------------------------------------------------------------------------------------



| | 6. | We filed a Current Report on Form 8-K on August 6, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | ----------------------------------------------------------------------------------------------------------------------------



| | 7. | We filed a Current Report on Form 8-K on August 12, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | -----------------------------------------------------------------------------------------------------------------------------



| | 8. | We filed a Current Report on Form 8-K on August 13, 2003. Items 7 and 12 were reported and no financial statements were filed.
| | -- | ------------------------------------------------------------------------------------------------------------------------------



| | 9. | We filed a Current Report on Form 8-K on August 26, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | -----------------------------------------------------------------------------------------------------------------------------



| | 10. | We filed a Current Report on Form 8-K on September 4, 2003. Items 7 and 9 were reported and no financial statements were filed.
| | --- | -------------------------------------------------------------------------------------------------------------------------------



| | 11. | We filed a Current Report on Form 8-K on September 29, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | --- | --------------------------------------------------------------------------------------------------------------------------------



| | 12. | We filed a Current Report on Form 8-K on September 30, 2003. Items 5, 7 and 9 were reported and no financial statements were filed.
| | --- | -----------------------------------------------------------------------------------------------------------------------------------



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| | 13. | We filed a Current Report on Form 8-K on October 2, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | --- | -----------------------------------------------------------------------------------------------------------------------------



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DYNEGY INC.



SIGNATURES



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



|      |  |                   |  |  |  |     |  | DYNEGY INC.                                                                                                                  
|----- |  | ----------------- |  |  |  | --- |  | -----------------------------------------------------------------------------------------------------------------------------
|      |  |                   |  | 
|Date: |  | November 12, 2003 |  |  |  | By: |  | /s/    NICK J.
CARUSO                                                                                                        
|      |  |                   |  |  |  |     |  | Nick J. Caruso Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal
Financial Officer)





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