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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-Q



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

For the quarterly period ended March 31, 2006



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

For the transition period from  to

Commission file number: 000-29311



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DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)



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|                         |  |                                     
|------------------------ |  | ------------------------------------
|Delaware                 |  | 94-3248415                          
|(State of incorporation) |  | (I.R.S. Employer Identification No.)

1000 Louisiana, Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 507-6400

(Registrants telephone number, including area code)



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

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



|Large | accelerated filer ̈Accelerated
filer ̈Non-accelerated filer  x
|----- | ------------------------------------------------------------

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

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



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DYNEGY HOLDINGS INC.

TABLE OF CONTENTS



|                              |  |                                                                                                                     |  |     
|----------------------------- |  | ------------------------------------------------------------------------------------------------------------------- |  | ----
|                              |  |                                                                                                                     |  | Page
|PART I. FINANCIAL INFORMATION |  |                                                                                                                    
|                              |  |                                                                                                                    
|                              |  | Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:                                                                |  |     
|                              |  |                                                                                                                    
|                              |  | Condensed Consolidated Balance Sheets:March 31, 2006 and December 31, 2005                                          |  | 5   
|                              |  | Condensed Consolidated Statements of Operations:For the three months ended March 31, 2006 and 2005                  |  | 6   
|                              |  | Condensed Consolidated Statements of Cash Flows:For the three months ended March 31, 2006 and 2005                  |  | 7   
|                              |  | Condensed Consolidated Statements of Comprehensive Income (Loss):For the three months ended March 31, 2006 and 2005 |  | 8   
|                              |  | Notes to Condensed Consolidated Financial Statements                                                                |  | 9   
|                              |  |                                                                                                                    
|                              |  | Item 2. MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS                       |  | 36  
|                              |  | Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK                                                  |  | 52  
|                              |  | Item 4. CONTROLS AND PROCEDURES                                                                                     |  | 54  
|                              | 
|PART II.
OTHER INFORMATION    |  |                                                                                                                    
|                              |  |                                                                                                                    
|                              |  | Item 1. LEGAL PROCEEDINGS                                                                                           |  | 57  
|                              |  | Item 1A. RISK FACTORS                                                                                               |  | 57  
|                              |  | Item 6. EXHIBITS                                                                                                    |  | 61  



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DEFINITIONS

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



|        |  |                                                                         
|------- |  | ------------------------------------------------------------------------
|ARB     |  | Accounting Research Bulletin                                            
|APB     |  | Accounting Principles Board                                             
|ARO     |  | Asset retirement obligation                                             
|Bcf/d   |  | Billion cubic feet per day                                              
|Cal ISO |  | The California Independent System Operator                              
|Cal PX  |  | The California Power Exchange                                           
|CDWR    |  | California Department of Water Resources                                
|CFTC    |  | Commodity Futures Trading Commission                                    
|CPUC    |  | California Public Utilities Commission                                  
|CRM     |  | Our customer risk management business segment                           
|DMG     |  | Dynegy Midwest Generation, Inc.                                         
|DMSLP   |  | Dynegy Midstream Services L.P.                                          
|DMT     |  | Dynegy Marketing and Trade                                              
|DNE     |  | Dynegy Northeast Generation                                             
|DPM     |  | Dynegy Power Marketing Inc.                                             
|EITF    |  | Emerging Issues Task Force                                              
|EPA     |  | Environmental Protection Agency                                         
|ERCOT   |  | Electric Reliability Council of Texas, Inc.                             
|ERISA   |  | The Employee Retirement Income Security Act of 1974, as amended         
|FASB    |  | Financial Accounting Standards Board                                    
|FERC    |  | Federal Energy Regulatory Commission                                    
|FIN     |  | FASB Interpretation                                                     
|FSP     |  | FASB Staff Position                                                     
|GAAP    |  | Generally Accepted Accounting Principles of the United States of America
|GEN     |  | Our power generation business                                           
|GEN-MW  |  | Our power generation business - Midwest segment                         
|GEN-NE  |  | Our power generation business - Northeast segment                       
|GEN-SO  |  | Our power generation business - South segment                           
|ISO     |  | Independent System Operator                                             
|KWyr   |  | Kilowatt year                                                           
|KWh     |  | Kilowatt hour                                                           
|LNG     |  | Liquefied natural gas                                                   
|LPG     |  | Liquefied petroleum gas                                                 
|MBbls/d |  | Thousands of barrels per day                                            
|Mcf     |  | Thousand cubic feet                                                     
|MISO    |  | Midwest Independent Transmission Operator, Inc.                         
|MMBtu   |  | Millions of British thermal units                                       
|MMCFD   |  | Million cubic feet per day                                              
|MW      |  | Megawatts                                                               
|MWh     |  | Megawatt hour                                                           
|NGL     |  | Our natural gas liquids business segment                                
|NOL     |  | Net operating loss                                                      
|NOV     |  | Notice of Violation issued by the EPA                                   
|NOx     |  | Nitrogen oxide                                                          
|NRG     |  | NRG Energy, Inc.                                                        
|NYISO   |  | New York Independent System Operator                                    
|NYSDEC  |  | New York State Department of Environmental Conservation                 
|POL     |  | Percentage of liquids                                                   
|POP     |  | Percentage of proceeds                                                  
|PRB     |  | Powder River Basin coal                                                 
|REG     |  | Our regulated energy delivery business segment                          
|RMR     |  | Reliability Must Run                                                    
|RTO     |  | Regional Transmission Organization                                      
|SEC     |  | U.S. Securities and Exchange Commission                                 
|SFAS    |  | Statement of Financial Accounting Standards                             



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|    |  |                                     
|--- |  | ------------------------------------
|SO2 |  | Sulfur dioxide                      
|SPE |  | Special Purpose Entity              
|SPN |  | Second Priority Senior Secured Notes
|VaR |  | Value at Risk                       
|VIE |  | Variable Interest Entity            



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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)



|                                                                                                            |  |               |        |   |                  |   |        |  
|----------------------------------------------------------------------------------------------------------- |  | ------------- | ------ | - | ---------------- | - | ------ | -
|                                                                                                            |  | March 31,2006 |        |   | December 31,2005 |  
|ASSETS                                                                                                      |  |               |        |   |                  |   |        |  
|Current Assets                                                                                              |  |               |        |   |                  |   |        |  
|                                                                                                            |  |              
|Cash and cash equivalents                                                                                   |  | $             | 1,315  |   |                  | $ | 1,301  |  
|Restricted cash                                                                                             |  |               |       |   |                  |   | 335    |  
|Accounts receivable, net of allowance for doubtful accounts of $101 and $101, respectively                  |  |               | 317    |   |                  |   | 598    |  
|Accounts receivable, affiliates                                                                             |  |               | 38     |   |                  |   | 61     |  
|Inventory                                                                                                   |  |               | 202    |   |                  |   | 203    |  
|Assets from risk-management activities                                                                      |  |               | 293    |   |                  |   | 667    |  
|Deferred income taxes                                                                                       |  |               | 24     |   |                  |   | 24     |  
|Prepayments and other current assets                                                                        |  |               | 83     |   |                  |   | 149    |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Total Current Assets                                                                                        |  |               | 2,272  |   |                  |   | 3,338  |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Property, Plant and Equipment                                                                               |  |               | 6,255  |   |                  |   | 6,160  |  
|Accumulated depreciation                                                                                    |  |               | (1,233 | ) |                  |   | (1,181 | )
|                                                                                                            |  |               |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                                          |  |               | 5,022  |   |                  |   | 4,979  |  
|Other Assets                                                                                                |  |               |        |   |                  |   |        |  
|Unconsolidated investments                                                                                  |  |               | 4      |   |                  |   | 267    |  
|Assets from risk-management activities                                                                      |  |               | 117    |   |                  |   | 197    |  
|Long-term accounts receivable, affiliates                                                                   |  |               | 673    |   |                  |   | 675    |  
|Deferred income taxes                                                                                       |  |               | 1      |   |                  |   | 3      |  
|Other long-term assets                                                                                      |  |               | 170    |   |                  |   | 160    |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Total Assets                                                                                                |  | $             | 8,259  |   |                  | $ | 9,619  |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                        |  |               |        |   |                  |   |        |  
|Current Liabilities                                                                                         |  |               |        |   |                  |   |        |  
|Accounts payable                                                                                            |  | $             | 233    |   |                  | $ | 501    |  
|Accounts payable, affiliates                                                                                |  |               | 1      |   |                  |   | 45     |  
|Accrued interest                                                                                            |  |               | 76     |   |                  |   | 112    |  
|Accrued liabilities and other current liabilities                                                           |  |               | 225    |   |                  |   | 616    |  
|Liabilities from risk-management activities                                                                 |  |               | 319    |   |                  |   | 700    |  
|Note payable to affiliate                                                                                   |  |               |       |   |                  |   | 120    |  
|Notes payable and current portion of long-term debt                                                         |  |               | 28     |   |                  |   | 29     |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Total Current Liabilities                                                                                   |  |               | 882    |   |                  |   | 2,123  |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Long-term debt                                                                                              |  |               | 3,075  |   |                  |   | 3,087  |  
|Long-term debt to affiliates                                                                                |  |               | 200    |   |                  |   | 200    |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Long-Term Debt                                                                                              |  |               | 3,275  |   |                  |   | 3,287  |  
|Other Liabilities                                                                                           |  |               |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                                 |  |               | 157    |   |                  |   | 295    |  
|Deferred income taxes                                                                                       |  |               | 260    |   |                  |   | 245    |  
|Other long-term liabilities                                                                                 |  |               | 333    |   |                  |   | 340    |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Total Liabilities                                                                                           |  |               | 4,907  |   |                  |   | 6,290  |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Commitments and Contingencies (Note 9)                                                                      |  |               |        |   |                  |   |        |  
|Stockholders Equity                                                                                        |  |               |        |   |                  |   |        |  
|Capital Stock, $1 par value, 1,000 shares authorized at March 31, 2006 and December 31, 2005, respectively. |  |               |       |   |                  |   |       |  
|Additional paid-in capital                                                                                  |  |               | 2,412  |   |                  |   | 2,412  |  
|Accumulated other comprehensive income, net of tax                                                          |  |               | 9      |   |                  |   | 4      |  
|Accumulated deficit                                                                                         |  |               | (101   | ) |                  |   | (119   | )
|Stockholders equity                                                                                        |  |               | 1,032  |   |                  |   | 1,032  |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Total Stockholders Equity                                                                                  |  |               | 3,352  |   |                  |   | 3,329  |  
|                                                                                                            |  |               |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                                  |  | $             | 8,259  |   |                  | $ | 9,619  |  
|                                                                                                            |  |               |        |   |                  |   |        |  

See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)



|                                                                                                     |  |                              |      |   |      |   |      |  
|---------------------------------------------------------------------------------------------------- |  | ---------------------------- | ---- | - | ---- | - | ---- | -
|                                                                                                     |  | Three Months Ended March 31, |     
|                                                                                                     |  | 2006                         |      |   | 2005 |  
|Revenues                                                                                             |  | $                            | 520  |   |      | $ | 448  |  
|Cost of sales, exclusive of depreciation shown separately below                                      |  |                              | (322 | ) |      |   | (317 | )
|Depreciation and amortization expense                                                                |  |                              | (57  | ) |      |   | (53  | )
|Impairment and other charges                                                                         |  |                              | (2   | ) |      |   | 1    |  
|General and administrative expenses                                                                  |  |                              | (51  | ) |      |   | (191 | )
|                                                                                                     |  |                              |      |   |      |   |      |  
|Operating income (loss)                                                                              |  |                              | 88   |   |      |   | (112 | )
|Earnings from unconsolidated investments                                                             |  |                              | 2    |   |      |   | 3    |  
|Interest expense                                                                                     |  |                              | (78  | ) |      |   | (75  | )
|Other income and expense, net                                                                        |  |                              | 15   |   |      |   |     |  
|                                                                                                     |  |                              |      |   |      |   |      |  
|Income (loss) from continuing operations before income taxes                                         |  |                              | 27   |   |      |   | (184 | )
|Income tax benefit (expense) (Note 12)                                                               |  |                              | (10  | ) |      |   | 59   |  
|                                                                                                     |  |                              |      |   |      |   |      |  
|Income (loss) from continuing operations                                                             |  |                              | 17   |   |      |   | (125 | )
|Income from discontinued operations, net of tax expense of $1 and $19, respectively                  |  |                              | 1    |   |      |   | 31   |  
|                                                                                                     |  |                              |      |   |      |   |      |  
|Income (loss) before cumulative effect of change in accounting principle                             |  |                              | 18   |   |      |   | (94  | )
|                                                                                                     |  |                              |      |   |      |   |      |  
|Cumulative effect of change in accounting principle, net of tax expense of $1 and zero, respectively |  |                              |     |   |      |   |     |  
|                                                                                                     |  |                              |      |   |      |   |      |  
|Net income (loss)                                                                                    |  | $                            | 18   |   |      | $ | (94  | )
|                                                                                                     |  |                              |      |   |      |   |      |  

See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



|                                                                                        |  |                              |       |   |      |   |      |  
|--------------------------------------------------------------------------------------- |  | ---------------------------- | ----- | - | ---- | - | ---- | -
|                                                                                        |  | Three Months Ended March 31, |      
|                                                                                        |  | 2006                         |       |   | 2005 |  
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                   |  |                              |       |   |      |   |      |  
|Net income (loss)                                                                       |  | $                            | 18    |   |      | $ | (94  | )
|Adjustments to reconcile net income (loss) to net cash flows from operating activities: |  |                              |       |   |      |   |      |  
|Depreciation and amortization                                                           |  |                              | 60    |   |      |   | 76   |  
|Impairment and other charges                                                            |  |                              | 2     |   |      |   | (1   | )
|Earnings from unconsolidated investments, net of cash distributions                     |  |                              | (2    | ) |      |   | (1   | )
|Risk-management activities                                                              |  |                              | (69   | ) |      |   | (32  | )
|Gain on sale of assets, net                                                             |  |                              | (1    | ) |      |   |     |  
|Deferred income taxes                                                                   |  |                              | 14    |   |      |   | (41  | )
|Legal and settlement charges                                                            |  |                              | 15    |   |      |   |     |  
|Other                                                                                   |  |                              | 2     |   |      |   | (15  | )
|Changes in working capital:                                                             |  |                              |       |   |      |   |      |  
|Accounts receivable                                                                     |  |                              | 308   |   |      |   | (140 | )
|Inventory                                                                               |  |                              | 10    |   |      |   | 25   |  
|Prepayments and other assets                                                            |  |                              | 59    |   |      |   | 37   |  
|Accounts payable and accrued liabilities                                                |  |                              | (757  | ) |      |   | 132  |  
|Changes in non-current assets                                                           |  |                              | (2    | ) |      |   | 1    |  
|Changes in non-current liabilities                                                      |  |                              | 2     |   |      |   | 12   |  
|                                                                                        |  |                              |       |   |      |   |      |  
|Net cash used in operating activities                                                   |  |                              | (341  | ) |      |   | (41  | )
|                                                                                        |  |                              |       |   |      |   |      |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                   |  |                              |       |   |      |   |      |  
|Capital expenditures                                                                    |  |                              | (18   | ) |      |   | (54  | )
|Proceeds from asset sales, net                                                          |  |                              | 205   |   |      |   |     |  
|Business acquisitions, net of cash acquired                                             |  |                              | (40   | ) |      |   |     |  
|Decrease in restricted cash                                                             |  |                              | 335   |   |      |   |     |  
|Affiliate transactions                                                                  |  |                              | 1     |   |      |   | (15  | )
|                                                                                        |  |                              |       |   |      |   |      |  
|Net cash provided by (used in) investing activities                                     |  |                              | 483   |   |      |   | (69  | )
|                                                                                        |  |                              |       |   |      |   |      |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                   |  |                              |       |   |      |   |      |  
|Repayments of borrowings                                                                |  |                              |      |   |      |   | (19  | )
|Borrowings (repayments) from (to) affiliate, net                                        |  |                              | (120  | ) |      |   | 50   |  
|Other financing, net                                                                    |  |                              | (8    | ) |      |   | 2    |  
|                                                                                        |  |                              |       |   |      |   |      |  
|Net cash provided by (used in) financing activities                                     |  |                              | (128  | ) |      |   | 33   |  
|                                                                                        |  |                              |       |   |      |   |      |  
|Net increase (decrease) in cash and cash equivalents                                    |  |                              | 14    |   |      |   | (77  | )
|Cash and cash equivalents, beginning of period                                          |  |                              | 1,301 |   |      |   | 245  |  
|                                                                                        |  |                              |       |   |      |   |      |  
|Cash and cash equivalents, end of period                                                |  | $                            | 1,315 |   |      | $ | 168  |  
|                                                                                        |  |                              |       |   |      |   |      |  

See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)



|                                                                                                         |  |                              |     |   |      |   |      |  
|-------------------------------------------------------------------------------------------------------- |  | ---------------------------- | --- | - | ---- | - | ---- | -
|                                                                                                         |  | Three Months Ended March 31, |    
|                                                                                                         |  | 2006                         |     |   | 2005 |  
|Net income (loss)                                                                                        |  | $                            | 18  |   |      | $ | (94  | )
|Cash flow hedging activities, net:                                                                       |  |                              |     |   |      |   |      |  
|Unrealized mark-to-market gains (losses) arising during period, net                                      |  |                              | 19  |   |      |   | (18  | )
|Reclassification of mark-to-market (gains) losses to earnings, net                                       |  |                              | (14 | ) |      |   | 12   |  
|                                                                                                         |  |                              |     |   |      |   |      |  
|Changes in cash flow hedging activities, net (net of tax benefit (expense) of ($3) and $4, respectively) |  |                              | 5   |   |      |   | (6   | )
|Foreign currency translation adjustments                                                                 |  |                              |    |   |      |   |     |  
|                                                                                                         |  |                              |     |   |      |   |      |  
|Other comprehensive income (loss), net of tax                                                            |  |                              | 5   |   |      |   | (6   | )
|                                                                                                         |  |                              |     |   |      |   |      |  
|Comprehensive income (loss)                                                                              |  | $                            | 23  |   |      | $ | (100 | )
|                                                                                                         |  |                              |     |   |      |   |      |  

See the notes to condensed consolidated financial statements.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods
Ended March 31, 2006 and 2005

Note 1Accounting Policies

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial
reporting as prescribed by the SEC. The year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These interim financial statements should be read
together with the consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2005, which we refer to as our Form 10-K.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal and recurring nature
that, in the opinion of management, are necessary for a fair statement of the results for the interim periods. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected
for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors. The preparation of the unaudited
condensed consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. These estimates and judgments also impact the nature and
extent of disclosure, if any, of our contingent liabilities. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their
publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously
available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are primarily used in (1) developing fair value assumptions, including estimates of future
cash flows and discount rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets, (4) assessing future tax exposure and the realization of tax assets,
(5) determining amounts to accrue for contingencies, guarantees and indemnifications and (6) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from any such estimates.
Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.

Asset Retirement
Obligations.At December 31, 2005, our ARO liabilities were $48 million for our GEN-MW segment and $8 million for our GEN-NE segment. These retirement obligations related to activities such as ash pond and landfill capping,
dismantlement of power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. We continue to follow the provisions for disclosure and accounting for these AROs
under SFAS No. 143, Asset Retirement Obligations. During the three months ended March 31, 2006 and 2005, there were no material additional AROs recorded or settled, and our accretion expenses and revisions to estimated cash
flows were not material. At March 31, 2006, our ARO liabilities were $49 million for our GEN-MW segment and $8 million for our GEN-NE segment.

Accounting Principles Adopted

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



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which revises SFAS No. 123. SFAS No. 123(R) requires all companies to expense the fair value of employee stock options
and other forms of stock-based compensation. We adopted SFAS No. 123(R) effective January 1, 2006, using the modified prospective transition method permitted under this pronouncement. Our cumulative effect of implementing this standard,
which consists entirely of a forfeiture adjustment, was less than $1 million after tax. The application of SFAS 123(R) had no material impact on the unaudited condensed consolidated statements of cash flows for the three months ended March 31,
2006, compared to amounts that would have been reported pursuant to our previous accounting.

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

Under SFAS No. 148s prospective method of transition, all stock options granted by Dynegy after January 1, 2003 are accounted for on a
fair value basis. Options granted by Dynegy prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Accordingly, for options granted by Dynegy prior to January 1, 2003, compensation expense is not reflected
for employee stock options unless they were granted at an exercise price lower than market value on the grant date. Dynegy has granted in-the-money options in the past, and we have recognized compensation expense over the applicable vesting periods.
No in-the-money stock options have been granted by Dynegy since 1999.

Had compensation cost for all stock options granted prior to 2003
been determined on a fair value basis consistent with SFAS No. 123, our net loss would not have been impacted for the three-month periods ended March 31, 2006 and 2005.

Dynegys share-based payments primarily consist of stock options and restricted stock awards. For stock options, we determine the fair value of each
stock option at the grant date using a Black-Scholes model, with the following weighted-average assumptions used for grants for the three months ended March 31, 2006 and 2005: dividends per quarter of zero; expected volatility (historical) of
48.8% and 84.1%, respectively; a risk-free interest rate of 5.1% and 4.2%, respectively based upon observed interest rates appropriate for the term of Dynegys employee stock options; and an expected option life of 10 years for options granted
prior to 2006 and 6 years for options granted during the first quarter 2006, which we calculate using the simplified methodology suggested by SAB 107. For restricted stock awards, we consider the fair value to be the closing price of the stock on
the grant date. We recognize the fair value of our share-based payments over the vesting periods of the awards, which is typically a three-year service period.

Dynegy has seven stock option plans in which we participate, all of which contain authorized shares of their Class A common stock. Each option granted is exercisable at a strike price, which ranges from $0.88 per
share to $57.95 per share for options currently outstanding. A brief description of each plan is provided below:



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



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005



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



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



| |  |  | Dynegy 1999 Long-Term Incentive Plan (LTIP).This annual compensation plan contains 6,900,000 authorized shares, has a 10-year term and expires in 2009.
All option grants are vested.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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

All of Dynegys option plans cease vesting for employees who are
terminated for cause. For voluntary and involuntary termination, disability, retirement or death, continued vesting and/or an extended period in which to exercise vested options may apply, dependent upon the terms of the grant agreement in which a
specific grant was awarded. It has been Dynegys practice to issue shares of common stock upon exercise of stock options generally from previously unissued shares. All options granted to employees vest immediately upon the occurrence of a
change in control in accordance with the terms of the applicable Severance Pay Plan.

In the first quarter of 2006, Dynegy granted
stock-based-compensation awards that cliff vest after three years based on its cumulative operating cash flows for 2006-2008. Compensation expense recorded in the first quarter related to these performance units was less than $1 million
and accrued in Other long-term liabilities in our unaudited condensed consolidated balance sheets.

During the first quarter 2006, Dynegy
entered into an exchange transaction with its Chairman and CEO, who also serves as our CEO. Under the terms of the transaction, the purpose of which was to address uncertainties created by proposed regulations issued in late 2005 pursuant to
Section 409A of the Internal Revenue Code, Dynegy cancelled all of the 2,378,605 stock options then held by its Chairman and CEO. As consideration for canceling these stock options, Dynegy granted its Chairman and CEO 967,707 stock options at
an exercise price of $4.88, which equaled the closing price of Dynegys Class A common stock on the date of grant, and agreed to make a cash payment of $5,565,187 based on the in-the-money value of the vested stock options that were
cancelled. This cash payment, which will accrue interest at 7.5% annually, will be made on January 15, 2007. The newly granted stock options have a term of 10 years, vest in three equal annual installments beginning on the first anniversary of
the grant date and are subject to earlier vesting upon a constructive termination, a termination without cause or a termination resulting from a change in control. We recorded a liability to reflect the agreed upon cash payment. We were not required
to record any incremental compensation expense in connection with the transaction.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

Options outstanding as of March 31, 2006 are summarized below:



|                                                       |  |         |   |  |                              |       |                                                   |     |                                      |   |    
|------------------------------------------------------ |  | ------- | - |  | ---------------------------- | ----- | ------------------------------------------------- | --- | ------------------------------------ | - | ---
|                                                       |  | Options |   |  | WeightedAverageExercisePrice |       | WeightedAverageRemainingContractualLife (inyears) |     | AggregateIntrinsicValue (inmillions)
|Outstanding at December 31, 2005                       |  | 9,122   |   |  | $                            | 12.62 |                                                   |     |                                      |   |    
|Granted                                                |  | 3,268   |   |  | $                            | 4.88  |                                                   |     |                                      |   |    
|Exercised                                              |  | (1,007  | ) |  | $                            | 3.46  |                                                   |     |                                      |   |    
|Forfeited or expired                                   |  | (2,477  | ) |  | $                            | 2.76  |                                                   |     |                                      |   |    
|                                                       |  |         |   |  |                              |       |                                                   |     |                                      |   |    
|Outstanding at March 31, 2006                          |  | 8,906   |   |  | $                            | 13.56 |                                                   | 6.6 |                                      | $ | 2.4
|                                                       |  |         |   |  |                              |       |                                                   |     |                                      |   |    
|Vested and unvested expected to vest at March 31, 2006 |  | 7,954   |   |  | $                            | 14.60 |                                                   | 6.2 |                                      | $ | 2.3
|Exercisable at March 31, 2006                          |  | 5,145   |   |  | $                            | 19.96 |                                                   | 4.3 |                                      | $ | 2.2

The weighted average grant-date fair value of options granted during the three months ended
March 31, 2006 and 2005 was $2.61 and $3.66, respectively. The total intrinsic value of options exercised for the three-month periods ended March 31, 2006 and 2005 was $3 million and zero, respectively.

Restricted stock activity for the three months ended March 31, 2006 was as follows:



|                               |  |                 |   |  |                                     |     
|------------------------------ |  | --------------- | - |  | ----------------------------------- | ----
|                               |  | Number ofShares |   |  | WeightedAverageGrant DateFair Value
|Nonvested at December 31, 2005 |  | 1,239           |   |  | $                                   | 4.40
|Granted                        |  | 1,311           |   |  | $                                   | 4.88
|Vested                         |  | (225            | ) |  | $                                   | 4.38
|Forfeited                      |  | (28             | ) |  | $                                   | 4.71
|                               |  |                 |   |  |                                     |     
|Nonvested at March 31, 2006    |  | 2,297           |   |  | $                                   | 4.67
|                               |  |                 |   |  |                                     |     

Compensation expense related to options granted and restricted stock awarded totaled $1 million
and $2 million for the quarters ended March 31, 2006 and 2005, respectively. Tax benefits for compensation expense related to options granted and restricted stock awarded totaled zero and $1 million for the quarters ended March 31, 2006
and 2005, respectively. We recognize compensation expense ratably over the vesting period of the respective awards. As of March 31, 2006, $14 million of total unrecognized compensation expense related to options granted and restricted stock
awarded is expected to be recognized over a weighted-average period of 2.7 years. The total fair value of shares vested during the three months ended March 31, 2006 and 2005 was $4 million and $2 million, respectively. We did not capitalize nor
use cash to settle any stock based compensation in the first quarter 2006.

Cash received from option exercises for the three months ended
March 31, 2006 was $4 million. The tax benefit realized from share-based payment awards totaled $1 million for the three months ended March 31, 2006.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

SFAS No. 154. In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections - A Replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS
No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the
unusual instance that the pronouncement does not include specific transition provisions. SFAS No. 154 requires retrospective application to prior periods financial statements of changes in accounting principle, unless it is impracticable to
determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS No. 154 are effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The
adoption of this standard on January 1, 2006 did not have a material effect on our results of operations, financial position or cash flows.

Note 2Acquisition

Rocky Road. On March 31, 2006, we completed our acquisition of NRGs 50%
ownership interest in Rocky Road Power LLC (Rocky Road), the entity that owns the Rocky Road power plant, a 364-megawatt natural gas-fired peaking facility near Chicago (of which we already owned 50%). We paid approximately $45 million for
NRGs ownership interest in Rocky Road. As a result of the acquisition, we became the primary beneficiary of the entity as provided under the guidance in FIN No. 46(R), and thus consolidated the assets and liabilities of the entity at
March 31, 2006. Please see Note 6  Unconsolidated Investments  Variable Interest Entities for further discussion.

Note
3Dispositions, Contract Terminations and Discontinued Operations

Dispositions and Contract Terminations

West Coast Power.On March 31, 2006, we completed our sale to NRG of our 50% ownership interest in WCP (Generation) Holdings LLC
(West Coast Power), a joint venture between us and NRG which has ownership in the West Coast Power power plants totaling approximately 1,800 megawatts in southern California, for approximately $205 million. We did not recognize a material gain or
loss on the sale. Pursuant to our divestiture of West Coast Power, we no longer maintain a significant variable interest in the entity as provided by the guidance in FIN No. 46(R). Please see Note 6  Unconsolidated Investments 
Variable Interest Entities for further discussion.

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

Discontinued Operations

As
part of our restructuring plan, we liquidated our U.K. CRM business in 2003. During 2005, we sold DMSLP, which comprised substantially all of the operations of our NGL segment. These transactions have been accounted for as discontinued operations
under SFAS No. 144, as further described below.

Natural Gas Liquids. On October 31, 2005, we completed the sale of
DMSLP, which comprised substantially all remaining operations of our NGL segment, to Targa Resources Inc. (Targa) and two of its subsidiaries for $2.44 billion in cash. At closing, we received $2.35 billion in cash proceeds. As of
March 31, 2006,



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

we received a substantial majority of the balance of the sales proceeds from Targa, which represented our cash collateral related to DMSLP. Targa assumed responsibility for approximately $47 million in letters of credit provided by us for
the benefit of DMSLP, and those letters of credit were all replaced by December 31, 2005.

Pursuant to SFAS No. 144, we are
reporting the results of NGLs operations as a discontinued operation. Accordingly, the results of operations of our NGL segment have been included in discontinued operations for all periods presented. EITF Issue 87-24, Allocation of
Interest to Discontinued Operations, requires that interest expense on debt that is required to be repaid upon the sale of DMSLP should be reclassified to discontinued operations. Therefore, interest expense on our former term loan and our
former generation facility debt was allocated to discontinued operations, as the respective debt instruments were paid upon the sale of DMSLP. Such interest expense, inclusive of amortization of debt issuance costs, totaled zero and $11 million for
the three months ended March 31, 2006 and 2005, respectively.

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

Other. We liquidated some of our
operations during 2003, including our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.

The following table summarizes information related to all of our discontinued operations, including the NGL operations discussed above:



|                                    |  |               |   |     |   |       |  |   |      
|----------------------------------- |  | ------------- | - | --- | - | ----- |  | - | -----
|                                    |  | U.K.CRM       |   | NGL |   | Total
|                                    |  | (in millions)
|Three Months Ended March 31, 2006   |  |               |   |     |   |       |  |   |      
|Income from operations before taxes |  | $             | 1 |     | $ | 1     |  | $ | 2    
|Income from operations after taxes  |  |               |  |     |   | 1     |  |   | 1    
|                                    |  |               |  
|Three Months Ended March 31, 2005   |  |               |   |     |   |       |  |   |      
|Revenues                            |  | $             |  |     | $ | 1,046 |  | $ | 1,046
|Income from operations before taxes |  |               | 4 |     |   | 46    |  | $ | 50   
|Income from operations after taxes  |  |               | 2 |     |   | 29    |  |   | 31   

In the first quarter 2005, we recognized $4 million of pre-tax income associated with U.K.
CRMs receipt of $4 million from a third party bankruptcy settlement.

Note 4Restructuring Charges

2005 Restructuring.In December 2005, in order to better align our corporate cost structure with a single line of business and as part of a
comprehensive effort to reduce on-going operating expenses, we implemented a restructuring plan (the 2005 Restructuring Plan). The 2005 Restructuring Plan resulted in a reduction of approximately 40 positions and was substantially
complete by March 31, 2006. We recognized a pre-tax charge, primarily in our Other segment of $11 million in the fourth quarter 2005. We recognized approximately $2 million of charges in the first quarter 2006, when transitional services were
completed by certain affected employees. These charges related entirely to severance costs.



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

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



|                              |  |   |     |  
|----------------------------- |  | - | --- | -
|Balance at December 31, 2005  |  | $ | 9   |  
|2006 adjustments to liability |  |   | 2   |  
|Cash payments                 |  |   | (10 | )
|                              |  |   |     |  
|Balance at March 31, 2006     |  | $ | 1   |  
|                              |  |   |     |  

2002 Restructuring.In October 2002, we announced a restructuring plan designed to
improve operational efficiencies and performance across our lines of business.

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



|                             |  |               |   |                                        |   |    |       |  |   |    |  
|---------------------------- |  | ------------- | - | -------------------------------------- | - | -- | ----- |  | - | -- | -
|                             |  | Severance     |   | Cancellation Fees and Operating Leases |   |    | Total | 
|                             |  | (in millions) |  
|Balance at December 31, 2005 |  | $             | 3 |                                        | $ | 15 |       |  | $ | 18 |  
|Cash payments                |  |               |  |                                        |   | (2 | )     |  |   | (2 | )
|                             |  |               |   |                                        |   |    |       |  |   |    |  
|Balance at March 31, 2006    |  | $             | 3 |                                        | $ | 13 |       |  | $ | 16 |  
|                             |  |               |   |                                        |   |    |       |  |   |    |  

We expect the $13 million accrual as of March 31, 2006 associated with cancellation fees and
operating leases to be paid by the end of 2007, when the leases expire.

Note 5Risk Management Activities and Accumulated Other Comprehensive
Income

The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in an
attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more fully described in Note 5Risk Management Activities and Financial Instruments beginning on page F-23 of our Form 10-K.

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

During the three months ended March 31, 2006, there was no 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 months ended March 31, 2005, we recorded a $4 million charge related to ineffectiveness from changes in fair value of hedge
positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three months ended March 31, 2006 and 2005, 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
March 31, 2006 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity and payments of interest, as



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

applicable to each type of hedge. Of this amount, after-tax losses of approximately $2 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 2007. The actual amounts that will be
reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.

Fair Value Hedges. We also enter into derivative instruments that qualify as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into floating-rate
debt. During the three months ended March 31, 2006 and 2005, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three months ended
March 31, 2006 and 2005, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

Net Investment Hedges in Foreign Operations. Although we have exited a substantial amount of our foreign operations, we have remaining investments in foreign subsidiaries, the net assets of which are exposed to currency
exchange-rate volatility. As of March 31, 2006, we had no net investment hedges in place.

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



|                                                   |  |                |     |   |                  |   |     |  
|-------------------------------------------------- |  | -------------- | --- | - | ---------------- | - | --- | -
|                                                   |  | March 31, 2006 |     |   | December 31,2005 |  
|                                                   |  | (in millions)  |    
|Cash flow hedging activities, net                  |  | $              | 3   |   |                  | $ | (2  | )
|Foreign currency translation adjustment            |  |                | 24  |   |                  |   | 24  |  
|Minimum pension liability                          |  |                | (18 | ) |                  |   | (18 | )
|                                                   |  |                |     |   |                  |   |     |  
|Accumulated other comprehensive income, net of tax |  | $              | 9   |   |                  | $ | 4   |  
|                                                   |  |                |     |   |                  |   |     |  

Note 6Unconsolidated Investments

A summary of our unconsolidated investments is as follows:



|                                 |  |                |   |                  |   |    
|-------------------------------- |  | -------------- | - | ---------------- | - | ---
|                                 |  | March 31, 2006 |   | December 31,2005
|                                 |  | (in millions) 
|Equity affiliates:               |  |                |   |                  |   |    
|GEN  MW                         |  | $              |  |                  | $ | 60 
|GEN  SO                         |  |                | 4 |                  |   | 207
|                                 |  |                |   |                  |   |    
|Total unconsolidated investments |  | $              | 4 |                  | $ | 267
|                                 |  |                |   |                  |   |    



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

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



|                 |  |                              |    |              |   |       |  |              |     |  |   |   
|---------------- |  | ---------------------------- | -- | ------------ | - | ----- |  | ------------ | --- |  | - | --
|                 |  | Three Months Ended March 31,
|                 |  | 2006                         |    | 2005        
|                 |  | Total                        |    | Equity Share |   | Total |  | Equity Share
|                 |  | (in millions)               
|Revenues         |  | $                            | 13 |              | $ | 7     |  | $            | 165 |  | $ | 67
|Operating income |  |                              | 3  |              |   | 2     |  |              | 11  |  |   | 4 
|Net income       |  |                              | 3  |              |   | 2     |  |              | 13  |  |   | 4 

Earnings from unconsolidated investments of $2 million for the three months ended March 31,
2006, include the $2 million above. Earnings from unconsolidated investments of $3 million for the three months ended March 31, 2005 include the $4 million above, offset by $1 million of earnings from NGL investments, which are included in
income from discontinued operations.

On March 31, 2006, we completed the sale to NRG of our 50% ownership interest in our
unconsolidated investment in West Coast Power as well as our acquisition of NRGs ownership interest in Rocky Road. As a result of the transactions, we received net cash proceeds of approximately $160 million from NRG. Under the terms of this
agreement, we did not recognize a material gain or loss on the sale of West Coast Power. For further discussion, please see Note 2Acquisition and Note 3Dispositions, Contract Terminations, and Discontinued OperationsDispositions
and Contract TerminationsWest Coast Power.

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

On March 31, 2006, we completed our acquisition of NRGs 50%
ownership interest in Rocky Road and the sale to NRG of our 50% ownership interest in West Coast Power. We paid approximately $45 million for NRGs ownership interest in Rocky Road and received approximately $205 million for our ownership
interest in West Coast Power, thus resulting in the receipt of net cash proceeds of approximately $160 million from NRG. Based on our acquisition of NRGs ownership interest in Rocky Road, we were required to reconsider whether we were the
primary beneficiary of Rocky Road. As we now own 100% of the outstanding equity interests in Rocky Road, we are subjected to a majority of the entitys expected losses and expected residual returns, and are therefore considered the primary
beneficiary of the entity. Thus, we consolidated the assets and liabilities of the entity at March 31, 2006, in accordance with the guidance provided in FIN No. 46(R), which requires that the assets and liabilities of the newly
consolidated entity be measured and recorded at their fair values on the date we became the primary beneficiary. Those assets and liabilities primarily consisted of $9 million of working capital, a $16 million intangible asset related to a contract
to provide capacity and energy, and $63 million of property, plant, and equipment at the facilitys location.

In conjunction with
acquiring the remaining outstanding equity interest in Rocky Road, we divested our interest in West Coast Power. Based on that transaction, we no longer maintain a significant variable interest in West Coast Power.

In July 2001, we entered into several agreements, including a power tolling agreement, a financial derivative instrument, an energy management agreement
and a natural gas supply agreement, with Sithe/Independence Power



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##### Table of Contents

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

Partners, L.P., which we refer to as Independence and, which owns and operates a 1,021 MW combined cycle gas-fired power generation facility near Scriba, New York. As a result of various contractual
arrangements into which this entity has entered, we have concluded that it is a VIE. However, as we do not absorb a majority of the expected losses or receive a majority of expected residual returns, we are not considered the primary beneficiary of
the entity. Our future obligations under these agreements, which represent our maximum exposure to loss, are approximately $665 million. On January 31, 2005, Dynegy completed the acquisition of ExRes SHC, Inc., or ExRes, the parent
company of Sithe Energies, Inc., which we refer to as Sithe Energies, and Independence. Please see Note 8Related Party Transactions for further discussion regarding this acquisition.

Note 7Debt

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

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

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

The Fourth
Senior Secured Credit Facility contains customary affirmative covenants and negative covenants and events of default. Subject to certain exceptions, we and our subsidiaries are subject to restrictions on incurring additional indebtedness,
limitations on capital expenditures and limitations on dividends and other payments in respect of capital stock. The Fourth Senior Secured Credit Facility also contains certain financial covenants,



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including (1) a covenant (measured at the last day of the fiscal quarter as specified below) that requires us and certain of our subsidiaries to maintain a ratio of secured debt to adjusted EBITDA no greater than 3.5:1 (June 30 and
September 30, 2006); 3.0:1 (December 31, 2006); 2.75:1 (March 31, 2007); 2.5:1 (June 30, 2007); 2.25:1 (September 30, 2007) and 2.0:1 (December 31, 2007 and thereafter) and (2) a covenant that requires us and certain of our subsidiaries to
maintain an interest coverage ratio as of the last day of the measurement periods ending June 30 and September 30, 2006 of no less than 1.4:1; ending December 31, 2006 of no less than 1.50:1; ending
March 31, June 30, September 30 and December 31, 2007 and March 31, 2008 of no less than 1.625:1, and ending June 30, 2008 and thereafter of no less than 1.75:1.

Second Priority Senior Secured Notes. On April 12, 2006, we completed a cash tender offer and consent solicitation (the SPN
Tender Offer), in which we purchased $150 million of our $225 million Second Priority Senior Secured Floating Rate Notes due 2008 (the 2008 Notes), substantially all of our $625 million 9.875% Second Priority Senior Secured Notes
due 2010 (the 2010 Notes) and all of our $900 million 10.125% Second Priority Senior Secured Notes due 2013 (the 2013 Notes and collectively with the 2008 Notes and the 2010 Notes, the Second
Priority Notes). In connection with the SPN Tender Offer, we amended the indenture under which the Second Priority Notes were issued, which eliminated or modified substantially all of the restrictive covenants, certain events of default and
related provisions and released certain liens securing the our obligations and the guarantors of the Second Priority Notes.

In the
aggregate, we purchased approximately $1,664 million of Second Priority Notes. Total cash paid to repurchase these notes, including consent fees and accrued interest, was $1,904 million. We expect to record a charge of approximately $225 million in
the second quarter 2006 associated with this transaction.

The remaining outstanding 2008 Notes and 2010 Notes are each redeemable at our
option in accordance with the terms of the indenture governing the Second Priority Notes.

Senior Unsecured Notes. On
April 12, 2006, we issued $750,000,000 aggregate principal amount of our 8.375% Senior Unsecured Notes due 2016 (the New Senior Notes) in a private offering (the Senior Notes Offering). The New Senior Notes are not
redeemable at our option prior to maturity. The New Senior Notes are our senior unsecured obligations and rank equal in right of payment to all of our existing and future senior unsecured indebtedness, and are senior to all of our existing and any
of our future subordinated indebtedness. The proceeds from the Senior Notes Offering, together with cash on hand, were used to fund the SPN Tender Offer discussed above.

Note 8Related Party Transactions

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

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



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Our transactions with ExRes include purchases of energy and capacity under a tolling arrangement, sales of natural gas and payments associated with a financial derivative instrument. During the three months ended
March 31, 2006 and 2005, we incurred costs of $53 million and $17 million, respectively, under these contracts. Additionally, during the three months ended March 31, 2006 and 2005, we sold an aggregate of $53 million and $31 million,
respectively, in natural gas to ExRes. The terms of these transactions are in accordance with the contractual agreements that were in place prior to Dynegys acquisition of ExRes. In addition to the contractual arrangements discussed above, we
pay all employee and payroll costs, as well as certain general and administrative costs, on behalf of ExRes, and they reimburse us for these costs. For the three months ended March 31, 2006 and 2005, we paid $1 million and $3 million,
respectively, of such costs on behalf of ExRes. As of March 31, 2006, we have a net outstanding affiliate receivable balance of $31 million from ExRes.

Exchange Transaction with Dynegys Chairman and CEO. On March 17, 2006, Dynegy entered into an exchange transaction with its Chairman and CEO, who also serves as our CEO. Under the terms of the
transaction, the purpose of which was to address uncertainties created by proposed regulations issued in late 2005 pursuant to Section 409A of the Internal Revenue Code, Dynegy cancelled all of the 2,378,605 stock options then held by its
Chairman and CEO. Please see Note 1Accounting PoliciesAccounting Principles AdoptedSFAS No. 123(R) for further discussion.

Note
9Commitments and Contingencies

Set forth below is a description of our material legal proceedings. In addition to the matters
described below, we are party to legal proceedings arising in the ordinary course of business. In managements opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of
operations or cash flows.

We record reserves for estimated losses from contingencies when information available indicates that a loss is
probable and the amount of the loss is reasonably estimable under SFAS No. 5, Accounting for Contingencies. For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably
estimated. Please see Note 2Accounting PoliciesContingencies, Commitments, Guarantees and Indemnifications beginning on page F-12 of our Form 10-K for further discussion of our reserve policies. Environmental reserves do not reflect
managements assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the amount of any reserves or potential
insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

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

Enron Trade Credit Litigation. Shortly before their bankruptcy filing in the fourth quarter 2001, we determined that we had net exposure to
Enron Corp. and its affiliates, including certain liquidated damages and other amounts relating to the termination of commercial transactions among the parties, of approximately $84 million. This exposure was calculated by setting off approximately
$230 million owed from Dynegy entities to Enron entities



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against approximately $314 million owed from Enron entities to Dynegy entities. The master netting agreement between Enron and Dynegy 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. Enron has claimed that the master netting agreement is unenforceable. If it prevails, our potential liability to Enron could be approximately
$216 million before interest, with as much as $220 million in unsecured Dynegy claims remaining to enforce against the bankruptcy estate. As required by the master netting agreement, we pursued resolution of this dispute through arbitration;
however, the Bankruptcy Court did not grant our motion, which was opposed by Enron, to permit arbitration with a non-bankrupt Enron entity. We then filed a motion with the Bankruptcy Court to allow us to proceed to discovery and trial in order to
determine the enforceability of the master netting agreement under the U.S. Bankruptcy Code. The Bankruptcy Court denied our motion and ordered us to mediate the dispute with Enron. The parties commenced mediation in November 2004, and have had
further discussions since that time, but no settlement has been reached. In April 2006, Enron requested that mediation be terminated; the mediator has recommended that the case be returned to the Bankruptcy Court.

If the setoff rights in the master netting agreement are modified or disallowed, either by agreement or otherwise, the amount available for our entities
to set off against sums that might be due Enron entities could be reduced materially. In fact, we could be required to pay to Enron the full amount that it claims to be owed, while we would be an unsecured creditor of Enron to the extent of our
claims. Given the size of the claims at issue, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows. We have recorded a reserve that we consider reasonable in connection with this
matter.

Gas Index Pricing Litigation. We and/or Dynegy are defending the following suits that claim damages resulting from
the alleged manipulation of gas index publications and prices by us and others: ABAG v. Sempra Energy et al. (filed in state court in November 2004); Ableman Art Glass v. Encana Corporation et al.(class action filed in federal court
in December 2004); Benschiedt(class action filed in state court in February 2004); Bustamante v. The McGraw Hill Companies et al. (class action filed in state court in November 2002); City and County of San Francisco v. Dynegy Inc.
et al.(filed in state court in July 2004); County of San Diego v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state court in July 2004); County of San Mateo v. Sempra Energy et al.(filed in state
court in December 2004); County of Santa Clara v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state court in July 2004); Fairhaven Power Company v. Encana Corp. et al. (class action filed in federal
court in September 2004); In re Natural Gas Commodity Litigation (class action filed in federal court in January 2004); Leggett v. Duke Energy et al. (class action filed in state court in January 2005); Multiut v. Dynegy Inc.(filed in federal court in December 2004); Nelson Brothers LLC v. Cherokee Nitrogen v. Dynegy Marketing and Trade and Dynegy Inc.(filed in state court in April 2003); Nurserymens Exchange v. Sempra Energy et al. (filed in
state court in October 2004); Older v. Dynegy Inc. et al.(filed in federal court in September 2004); Owens-Brockway v. Sempra Energy at al. (filed in state court in January 2005); Sacramento Municipal Utility District (SMUD) v.
Reliant Energy Services, et al.(filed in state court in November 2004);School Project for Utility Rate Reduction v. Sempra Energy et al.(filed in state court in November 2004);Sierra Pacific Resources and Nevada Power Company v. El
Paso Corp. et al.(filed in federal court in April 2003); Tamco v. Dynegy Inc. et al.(filed in state court in December 2004);Texas-Ohio Energy, Inc. v. CenterPoint Energy Inc., et al.(class action filed in federal court in
November 2003); Utility Savings & Refund v. Reliant Energy Services, et al.(class action filed in federal court in November 2004) and J.P. Morgan Trust Company, National Association, in its capacity as Trustee of the FLI
Liquidating Trust (Farmland) v. Dynegy Marketing and Trade, et al. (filed in Kansas state court in July 2005). In each of these suits, the plaintiffs allege that we and and/or Dynegy and other energy companies engaged in an illegal
scheme to inflate natural gas prices by providing false information to gas index publications. All of the complaints rely heavily on FERC and CFTC investigations into and reports concerning index-reporting manipulation in the energy industry.



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Pursuant to various motions filed by the parties to the litigation described above, the gas index pricing lawsuits pending in state court (except for Nelson Brothers) have been consolidated before a single
judge in San Diego. These cases are now titled the Judicial Counsel Coordinated Proceeding (JCCP) 4221, 4224, 4226, and 4228, the Natural Gas Anti-Trust Cases, I, II, III, & IV, which we refer to as the Coordinated Gas
Index Cases. In April 2005, defendants moved to dismiss the Coordinated Gas Index Cases on preemption and filed rate grounds. The Court denied defendants motion in June 2005 and in October 2005 the defendants filed answers to the
plaintiffs complaints. The parties are presently engaged in discovery.

The Nelson Brothers lawsuit involves an alleged breach
of a gas purchase contract and is pending in Alabama state court. The parties are presently engaged in discovery.

As to the gas index
pricing lawsuits filed in federal court, the Sierra Pacific case was dismissed in December 2004 on defendants motion. The Texas-Ohio case was similarly dismissed in April 2005. Plaintiffs in Sierra Pacific and
Texas-Ohio appealed the dismissals and both matters are pending before the same panel of the Ninth Circuit Court of Appeals. In December 2005, the Nevada federal court dismissed three additional cases (Ableman Art Glass, Fairhaven
Power and Utility Savings & Refund) on similar grounds to Texas-Ohio, finding plaintiffs claims barred by the filed rate doctrine. In May 2005 and November 2005, the Multiut and Farmland cases
(respectively) were transferred to the same Nevada federal court before which the other similarly situated federal cases are pending or were dismissed. The Multiut case involves a counterclaim of alleged index manipulation filed by the
defendant, Multiut, against whom we have a pending breach of gas purchase contract claim. In January 2006, we filed a motion to dismiss Multiuts claims of index manipulation based upon filed rate doctrine and preemption grounds. Such motion
remains pending. The plaintiffs generally seek unspecified actual and punitive damages relating to costs they claim to have incurred as a result of the alleged conduct.

In February 2006, we reached a settlement in In re Natural Gas Commodity Litigation, resolving a class action lawsuit by all persons who purchased, sold or settled NYMEX Natural Gas Contracts between
June 1, 1999 and December 31, 2002. The underlying action alleged the named defendants (including Dynegy and West Coast Power) unlawfully manipulated and aided and abetted the manipulation of the prices of natural gas futures contracts
traded on the NYMEX. Pursuant to the settlement agreement, Dynegy and West Coast Power continue to deny plaintiffs allegations, and Dynegy agreed to pay $7 million in settlement of any and all claims for damages arising from or relating in any
way to trading during the Class Period in NYMEX Natural Gas Contracts. The settlement is subject to a fairness hearing and final Court approval, which we expect to occur in the third quarter 2006.

We are analyzing all of these claims and are vigorously defending against them. We cannot predict with certainty whether we will incur any liability in
connection with these lawsuits. However, given the nature of the claims and the size of recent settlements of similar matters, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of
operations and cash flows. We have recorded reserves that we consider reasonable in connection with these matters.

In connection with the
sale of our interest in West Coast Power to NRG (which sale closed on March 31, 2006), we, NRG and NRG West Coast LLC entered into an Agreement Regarding Specified Litigation in which the parties allocated responsibility for managing certain
litigation and agreed to certain indemnities with respect to such litigation. Subject to conditions and limitations specified in that Agreement, the parties agreed that we would manage the gas index pricing litigation described above for which NRG
could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses resulting from such litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation.
Please read Guarantees and IndemnificationsWCP Indemnities below.



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California Market Litigation.We and/or Dynegy and various other power generators and marketers were defendants in numerous lawsuits alleging rate and market manipulation in Californias wholesale
electricity market during the California energy crisis and seeking unspecified treble damages. These cases were coordinated before a single federal judge, who dismissed two of them in the first quarter of 2003 on the grounds of FERC preemption and
the filed rate doctrine. The Ninth Circuit Court of Appeals affirmed these dismissals in June 2004 and September 2004, respectively. Petitions for Writ of Certiorari to the U.S. Supreme Court were both denied. The remaining five coordinated cases
were remanded to a California state court, and in May 2005, defendants filed a motion to dismiss. The court granted defendants motion to dismiss in October 2005 on grounds of federal preemption. Plaintiffs have appealed the ruling to a
California state appellate court.

Between April and October 2002, nine additional putative class actions and/or representative actions
were filed in state and federal court on behalf of business and residential electricity consumers against us and numerous other power generators and marketers.The complaints alleged unfair, unlawful and deceptive practices in violation of
the California Unfair Business Practices Act and sought injunctive relief, restitution and unspecified damages. Although some of the allegations in these lawsuits were similar to those in the cases referenced above, these lawsuits included
additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. Following removal of these cases, the federal court dismissed eight of the nine actions and plaintiffs appealed. In
February 2005, the Ninth Circuit affirmed the dismissals. The remaining case was remanded to state court, and in May 2005, defendants filed a motion to dismiss. In September 2005, the court granted defendants motion to dismiss on grounds of
federal preemption.

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

In May and June 2004, two additional lawsuits were filed in Oregon and Washington federal courts
against several energy companies, including DPM, seeking more than $30 million in compensatory damages resulting from alleged manipulation of the California wholesale power markets. In February 2005, the respective federal courts granted our motions
to dismiss. Shortly thereafter, plaintiffs in both cases filed notices of appeal to the Ninth Circuit. Briefing in both cases has been completed, and they remain pending.

In October 2004, an independent electric services provider in California filed suit against us and several other defendants alleging that the defendants, in violation of the California anti-trust and unfair business
practices statutes, engaged in unfair, unlawful and deceptive practices in the California wholesale energy market from May 2000 through December 2001. Plaintiff, which formerly sold electricity generated from renewable sources in the California
market, claims to have been forced out of business by the defendants conduct and is seeking $5 million in compensatory damages, as well as treble damages. We removed the action to federal court in June 2005, where it remains pending.

We believe that we have meritorious defenses to these claims and are vigorously defending against them. We cannot predict with certainty
whether we will incur any liability in connection with these lawsuits. However, given the nature of the claims, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and
cash flows.



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The energy crisis also precipitated a number of FERC actions related to the California energy market, and the Western market. These actions included investigations of alleged manipulation of energy prices in the West,
claims of false reporting to energy index publishers and complaints regarding various long-term power sales contracts. The FERC investigation of false reporting to trade publications by us concluded in July 2003. Additionally, in October 2004, the
FERC approved an agreement providing for the settlement of certain claims relating to western energy market transactions that occurred between January 2000 and June 2001. Please read FERC and Related Regulatory InvestigationsRequests for
Refunds below for further discussion.

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

FERC and Related Regulatory InvestigationsRequests for Refunds. In October 2004, the FERC approved an agreement
with Dynegy and West Coast Power that settled FERC claims relating to western energy market transactions that occurred between January 2000 and June 2001. Market participants (other than the parties to the settlement) were permitted to opt into this
settlement and share in the distribution of the settlement proceeds, and most of these other market participants have done so. The Cal ISO will determine the entitlement to refund and/or the liability of each non-settling market participant. Under
the terms of the settlement, we will have no further liability to these non-settling parties. The settlement further provides that we are entitled to pursue claims for reimbursement of fuel costs against various non-settling market participants. We
are currently pursuing these claims but are unable to predict the amounts that may be recovered from such parties.

The settlement does not
apply to the ongoing civil litigation related to the California energy markets described above in which we and/or Dynegy and West Coast Power are defendants. The settlement also does not apply to the pending appeal by the CPUC and the California
Electricity Oversight Board of the FERCs prior decision to affirm the validity of the West Coast Power-CDWR contract. We are currently awaiting a ruling on this appeal and cannot predict its outcome.

In connection with the sale of our interest in West Coast Power to NRG on March 31, 2006, we, NRG and NRG West Coast LLC entered into an Agreement
Regarding Specified Litigation in which the parties allocated responsibility for managing certain litigation and agreed to certain indemnities with respect to such litigation. The Agreement provides that NRG will manage the CDWR litigation described
above and that NRG will indemnify us for any losses in connection with such litigation with certain limits and conditions placed on that indemnification obligation. Please read Guarantees and IndemnificationsWCP Indemnities below.

ERISA/Illinois Power 401(k) Litigation. In January 2005, three DMG union employees who are participants in the DMG 401(k)
Savings Plan for Employees Covered Under a Collective Bargaining Agreement (formerly known as the Illinois Power Company Incentive Savings Plan For Employees Covered Under a Collective Bargaining Agreement), which we refer to as the DMG 401(k)
Plan, purporting to represent all DMG and Illinois Power employees who held Dynegy common stock through the DMG 401(k) Plan during the period from February 2000 through the present, filed a lawsuit in federal court in the Southern District of
Illinois against Dynegy, Illinois Power, DMG and several individual defendants. The complaint alleges violations of ERISA in connection with the



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DMG 401(k) Plan that are similar to the claims made in the Dynegy Inc. ERISA litigation settled by Dynegy in December 2004, including claims that certain of Dynegys former officers (who are past members of its Benefit Plans Committee)
breached their fiduciary duties to plan participants and beneficiaries in connection with the plans investment in Dynegy common stockin particular with respect to Dynegys financial statements, Project Alpha, round trip trades and
gas price index reporting. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorneys fees and other costs. In March 2006, an amended complaint was filed naming additional former officers of Dynegy as defendants and
amending the fraud claims.

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

We believe that we have meritorious defenses to plaintiffs claims in all of these
lawsuits and are vigorously defending against them. Although it is not possible to predict with certainty whether we will incur any liability in connection with these lawsuits, we do not believe that any liability we might incur as a result of this
lawsuit would have a material adverse effect on our financial condition, results of operations or cash flows.

LSP-Kendall
Arbitration.In May 2005, Dynegy Power Marketing, Inc. initiated an arbitration proceeding against LSP-Kendall Energy, alleging breach of the parties long-term power purchase agreement and seeking a declaratory judgment that DPM does
not owe (1) reservation payments during the period in which LSP-Kendall failed to bring dedicated generating units on-line or (2) money in connection with past incremental replacement costs. DPMs breach of contract claims are based
on LSP-Kendalls failure to design, construct and maintain the dedicated units and generation facility in accordance with the terms of the power purchase agreement. In addition to its request for declaratory relief, DPM seeks an order
compelling LSP-Kendall to cure the breaches by a certain date and such failure to cure entitles DPM to terminate the power purchase agreement without penalty. LSP-Kendall denies that it is in breach of the power purchase agreement and asserts
counterclaims alleging DPM owes in excess of $29 million in reservation payments and past incremental replacement costs. Arbitration is currently set for June 2006 and the parties are presently engaged in discovery.

We believe we have meritorious defenses to LSP-Kendalls claims and are vigorously defending against them. We cannot predict with certainty whether
we will incur any liability in connection with this arbitration, however, we do not believe that any liability we might incur would have a material adverse effect on our financial condition, results of operations or cash flows.

Stand Energy Litigation (formerly Atlantigas Corp. Litigation). In October 2004, we were named in a West Virginia federal court class
action lawsuit alleging that interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate in return for a percentage of the profits. Plaintiffs contend that such conduct violates
applicable FERC regulations and federal and state antitrust laws, and constitutes common law tortious interference with contractual and business relations. In addition, the complaint



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(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

claims the defendants conspired with the other market participants to receive preferential natural gas storage and transportation services at off-tariff prices. The complaint seeks unspecified compensatory and punitive damages. Following
numerous procedural motions which limited plaintiffs claims against us to state antitrust violations and resulting unjust enrichment, defendants filed their answers to plaintiffs Second Amended Complaint in September 2005. The parties
are actively engaged in discovery. We continue to analyze plaintiffs claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability in connection with this lawsuit; however, we believe
that any liability incurred as a result of this litigation would not have a material adverse effect on our financial condition, results of operations or cash flows.

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

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

In January 2003, one of Dynegys former natural gas traders was indicted on three counts of knowingly causing the transmission of false trade
reports used to calculate the index price of natural gas and four counts of wire fraud. A second superseding indictment was returned in March 2006, recharging the original violations and adding additional charges. The trial is scheduled for the
summer of 2006.

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

U.S. AttorneyCalifornia.The U.S. Attorneys office in the Northern District of
California issued a Grand Jury subpoena requesting information related to our activities in the California energy markets in November 2002. Dynegy continues to cooperate fully with the U.S. Attorneys office in its investigation of these
matters, including production of substantial documents responsive to the subpoena and other requests for information. We cannot predict the ultimate outcome of this investigation.

Department of Labor Investigation. In August 2002, the U.S. Department of Labor commenced an official investigation pursuant to
Section 504 of ERISA with respect to the benefit plans maintained by Dynegy and its ERISA affiliates. Dynegy cooperated with the Department of Labor throughout this investigation, which focused on a review of plan documentation, plan reporting
and disclosure, plan record keeping, plan investments and investment options, plan fiduciaries and third party service providers, plan contributions and other operational aspects of the plans. In February 2005, Dynegy received a letter from the
Department of Labor indicating that, as a result of Dynegys December 2004 settlement in the Dynegy Inc. ERISA litigation, it intended to take no further action with respect to its investigation of the Dynegy Inc. 401(k) Plan. However, its
investigation is ongoing as it relates to the Illinois Power 401(k) Plans and the recent litigation relating to those plans described above.

Calpine Corporation Bankruptcy. Calpine Corporation filed for Chapter 11 Bankruptcy protection in the United States Bankruptcy Court for the Southern District of New York (Bankruptcy Court) on December 20,
2005. The filing includes Nissequogue Cogen Partners (NCP), a subsidiary of Calpine, which has been purchasing gas from DMT under a long term gas sales agreement. NCP owes DMT approximately $8 million for pre-petition natural gas
deliveries pursuant to the gas sales agreement, and has been paying DMT on a current basis



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(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

for post-petition gas deliveries. NCP and DMT have reached a settlement pursuant to Rule 9019 of the Federal Rules of Bankruptcy Procedure and Section 105(a) of the Bankruptcy Code in which the parties agree to the mutual termination
of the long term gas sales agreement and settlement of all claims between NCP and DMT. Pursuant to the settlement agreement that was filed on April 25, 2006 with the Bankruptcy Court, NCP will continue paying for post-petition gas deliveries
pursuant to the gas sales agreement. DMTs obligation to deliver and receive gas will terminate on May 1, 2006, once the Bankruptcy Court issues a final order approving the settlement agreement and appeal periods have expired, NCP will pay
DMT approximately $8 million (which is the actual amount owed for all pre-petition gas deliveries), the long term gas sales agreement (which otherwise would have expired on May 31, 2010) will terminate, and DMT will waive any claim for
potential forward damages that it otherwise might have under the gas sales agreement.

Enron/NNG VEBA Litigation. Prior to
our acquisition of NNG from Enron, NNG employees were participants in a post-retirement medical plan maintained by Enron. The plans assets were maintained in a VEBA trust, along with the assets of other Enron companies whose plans were
included in the same VEBA trust (the Enron VEBA). Enron filed for bankruptcy in December 2001. When we acquired NNG in January 2002, the assets of the Enron VEBA had not been distributed to its participant companies. In July 2002, we
estimated that approximately $25.4 million of the assets of the Enron VEBA were attributable to the NNG employees who participated in the post-retirement medical plan. On July 1, 2002, as part of our sale of NNG to Mid American Energy Holdings
Company, NNG established a separate VEBA trust solely for its plan participants (the NNG VEBA). As a condition of the sale agreement, we placed $25.4 million into escrow under terms providing that if Enron did not release NNGs
share of the VEBA assets by August 2004, NNG was entitled to the escrowed money to fund the NNG VEBA. When Enron did not release the funds from the Enron VEBA as of August 2004, NNG drew down the escrowed funds. Pursuant to the escrow agreement, NNG
was then obligated to (1) repay us if it were to recover funds from the Enron VEBA and (2) allow us to manage any litigation against the Enron VEBA for payment of amounts owed to the NNG VEBA. In January 2006, we entered a confidential
agreement with NNG settling the claims between the parties and extinguishing the obligations under the escrow agreement in exchange for a cash payment by NNG to Dynegy.

Guarantees and Indemnifications

We routinely enter into contractual agreements that contain
various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, and procurement and
construction contracts. Some agreements contain indemnities that cover the other partys negligence or limit the other partys liability with respect to third party claims, in which event we will effectively be indemnifying the other
party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the
possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be extremely remote.

WCP Indemnities.In connection with our sale to NRG of our 50% ownership interest in West Coast Power (please read
Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsWest Coast Power for further discussion), we entered into an agreement with NRG in which we agreed how certain litigation
would be managed and allocated between the parties responsibility for any loss suffered by the parties as a result of such litigation. In this agreement, we agreed that we would continue managing the Gas Index Pricing Litigation and that we would
indemnify NRG for all losses suffered by NRG resulting from certain cases described in Gas Index Pricing Litigation and from other proceedings based on acts or omissions



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(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

similar to those which formed the basis of such litigation. We also agreed with NRG that we would continue managing the California Market Electricity Litigation and that we and NRG would each be responsible for, and indemnify the other for,
50% of any losses suffered by either party resulting from such litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation. Also pursuant to this agreement, NRG will manage the
litigation regarding the validity of the West Coast Power-CDWR power purchase agreement and NRG agreed to indemnify us for any losses suffered by us in connection with such litigation, subject to specified limitations.

Targa Indemnities.During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa against losses it may incur under
indemnifications DMSLP provided to purchasers of Hackberry and certain other assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their
value to be insignificant. We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. While we have incurred no expense in connection with this indemnification, as of March 31, 2006, we have recorded
an accrual, which we deem to be the fair value of this indemnification.

Constellation Guarantee. During 2004, as part of
entering into a back-to-back power purchase agreement with Constellation, under which Constellation effectively received our rights to purchase approximately 570 MW of capacity and energy arising under our Kendall tolling contract, we
guaranteed Constellation an aggregate $3.5 million in reactive power revenues over the four year term of the power purchase agreement. Upon entering into this contract, we established a liability of $0.3 million reflecting the fair value of this
guarantee. During the year ended December 31, 2005, we increased the liability by approximately $1 million, as it became probable that we will be obligated to make a greater payment to Constellation under the guarantee.

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

Black Mountain Guarantee.Through one of our subsidiaries, we hold a 50% ownership interest in Black Mountain (Nevada Cogeneration), in which our partner is a Chevron subsidiary which owns the Black Mountain power generation facility and has a power purchase agreement
with a third party that extends through April 2023. In connection with the power purchase agreement, pursuant to which Black Mountain (Nevada Cogeneration) receives payments which decrease in amount over time, we agreed to guarantee 50% of certain
payments that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement. At March 31, 2006, if an event of default had occurred under the terms of the mortgage on the facility entered
into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $54 million under the guarantee. In addition, while there is a question of interpretation regarding the existence of an
obligation to make payments calculated under this mechanism upon the scheduled termination of the agreement, management does not expect that any such payments would be required.



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(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

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.

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

Illinois Resource Procurement Auction. In January 2006, the ICC approved a
resource procurement auction as the process by which utilities will procure power beginning in 2007. Under the ICCs Orders, the first auction will occur in September 2006 and would likely cover substantially all of the retail needs of the
largest electric utilities in Illinois (Commonwealth Edison Company, and the three Ameren Illinois utilities: AmerenIP, AmerenCIPS and AmerenCILCO). Subsequent annual auctions would be held with the goal of ensuring adequate resources are under
contract to serve Illinois retail needs. There continue to be challenges to the auction process. Therefore, there is a possibility of political, legislative, judicial and/or regulatory actions over the next several months that could alter
substantially, or even eliminate altogether, the auctions. Given these uncertainties, the effect of the final process that will be used in Illinois cannot be predicted at this time.

Clean Air Mercury Rule.In March 2005, the Administrator of the Federal EPA signed a final Clean Air Mercury Rule (CAMR) that will require
mercury emission reductions to be achieved from existing coal-fired electric generating units. This rule requires all states to adopt either the Federal EPA rule, or a state rule meeting the minimum requirements as outlined in CAMR. The Illinois EPA
has proposed a state-specific rule (the Illinois Mercury Rule) that would require larger percent reductions in mercury emissions on a significantly shorter timeframe than the CAMR would require. We, along with most other owners of Illinois
coal-fired electric generating units, are disputing the Illinois Mercury Rule in proceedings before the Illinois Pollution Control Board (IPCB). The rule was accepted by the IPCB under the fast track rulemaking procedures of Section 28.5 of the
Illinois Environmental Protection Act; however, the Circuit Court for Sangamen County, Illinois has issued an injunction against the use of the Section 28.5 rulemaking procedures. A new schedule for the rulemaking has not been determined. After
hearings are completed, IPCB will transmit the proposed rule to the Joint Committee on Administrative Rules (JCAR), who will make the final decision. Various state legislative and regulatory bodies may be considering other legislation or rules that
could impact current regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these legislative and other regulatory developments, or the effects that they might have on our business.

Roseton State Pollutant Discharge Elimination System Permit. Rosetons SPDES Permit was issued for a five-year term in 1987. Prior
to expiration of the permit, Central Hudson Gas & Electric (the former plant owner),



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(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

filed a timely and sufficient application to renew the SPDES Permit. Under New York State law, when a timely and sufficient application for renewal is filed before a SPDES Permit expires, the permit is extended by operation of law until
final action is taken on the renewal application. In April 2005, the NYSDEC issued to DNE a draft SPDES Permit (the Draft SPDES Permit) for the Roseton plant. The Draft SPDES Permit requires the facility to manage actively its water
intake to reduce impingement mortality of fish by 85% and to reduce entrainment mortality of aquatic organisms including juvenile fish, larvae and fish eggs by 70% during the first two years of the renewal term, and by 80% thereafter.

In July 2005, a public hearing was held to receive comments on the Draft SPDES Permit. Three organizations filed petitions for party status in the permit
renewal proceeding, Riverkeeper, Inc., Natural Resource Defense Council, Inc. and Scenic Hudson, Inc. The Petitioners are seeking to impose a permit requirement that the Roseton plant install a closed cycle cooling system in order to reduce the
volume of water withdrawn from the Hudson River, thus reducing entrainment and impingement of aquatic organisms and fish. The Petitioners claim that only a closed cycle cooling system meets the Clean Water Acts requirement that the location,
design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts from the facilitys cooling water intake structures. Currently, the Draft SPDES Permit does
not require installation of a closed cycle cooling system; however, it does require entrainment and impingement mortality reductions that exceed the best technology available requirements of the USEPA regulations applicable to existing facilities.
We expect that the adjudicatory hearing on the Draft SPDES Permit will be held in the fall of 2006. We believe that the Petitioners claims are without merit, and we plan to oppose those claims vigorously. Given the high cost of installing a
closed cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operations and cash flows.

Danskammer State Pollutant Discharge Elimination System Permit. Danskammers SPDES Permit was issued for a five-year term in 1987. Prior to the expiration of the permit, Central Hudson
Gas & Electric (the former plant owner), filed an application to renew the SPDES Permit. We believe that application was timely and sufficient. Under New York State law, when a timely and sufficient application for renewal is filed before a
SPDES Permit expires, the permit is extended by operation of law until final action is taken on the renewal application. In November 2002, several environmental groups filed suit in the Supreme Court of the State of New York seeking, among other
things, a declaratory judgment that the Danskammer SPDES Permit had expired because of alleged deficiencies in the renewal application process. In August 2004, the Court ruled that the SPDES Permit for our Danskammer facility was void, but stayed
the enforcement of the decision pending further review by the Court or by the Appellate Division. In April 2006, the Appellate Division reversed the trial court and dismissed the case. The Court ruled that the environmental groups challenges
to the extension of the SPDES Permit were barred by the applicable statute of limitations.

We are continuing to seek renewal of our water
intake and discharge permit in proceedings before the NYSDEC. The Draft SPDES Permit was issued in January 2005 and an adjudicatory hearing was scheduled for the fall of 2005. The Petitioners, Riverkeeper, Inc., Natural Resource Defense Council,
Inc. and Scenic Hudson, Inc., seek to impose a permit requirement that the Danskammer plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing entrainment and impingement.
Petitioners claim that only a closed cycle cooling system meets the Clean Water Acts requirement that the location, design, construction and capacity of cooling water intake structures reflect best technology available for minimizing adverse
environmental impacts from the facilitys cooling water intake structures. The Draft SPDES Permit does not require installation of a closed cycle cooling system; however, it does require entrainment and impingement mortality reductions that
exceed the best technology available requirements of the USEPA regulations applicable to existing facilities.



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(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

A formal evidentiary hearing was held in November and December 2005 and post-hearing briefing was completed in March 2006. The Commissioners decision on the permit renewal is due on May 19, 2006. We believe
that Petitioners claims are without merit and we have vigorously opposed those claims. Given the high cost of installing a closed cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial
condition, results of operations and cash flows.

FERC Market-Based Rate Authority. FERC-approved market-based rate authority
allows those granted such authority to sell power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic re-review. On June 16, 2005, FERC issued an order accepting the updated market
power analyses submitted by Sithe Energies and Dynegy. Our next triennial market power analysis is due June 16, 2008. Accordingly, these entities have continuously had market-based rate authority.

We are also subject to the FERCs market behavior rules, which emerged from its consideration of market manipulation in the Western markets. The
rules, which were promulgated in 2003 for the purpose of prohibiting manipulation in the wholesale electricity and natural gas markets subject to FERCs jurisdiction, are incorporated in the tariffs of the various Dynegy entities with market
based rates for wholesale power and apply to sales in organized and bilateral markets and spot markets, as well as long-term sales (as well as to the wholesale sale of natural gas under a blanket marketing certificate). The remedies for violating
the rules could include disgorgement of unjust profits or suspension or revocation of the authority to sell at market-based rates and penalties. Pursuant to the Energy Policy Act of 2005, FERC recently finalized new regulations prohibiting energy
market manipulation, which regulations are patterned after the language of the SECs Rule 10b-5. Subsequently, FERC rescinded two of the six market behavior rules (as they are covered in FERCs new regulations prohibiting market
manipulation or other FERC standards) and codified the remaining four in its regulations. The extent to which these regulations will affect the costs or other aspects of our operations is uncertain. However, we believe that our entities subject to
the regulations are currently in compliance.

Note 11Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully
described in Note 17Employee Compensation, Savings and Pension Plans beginning on page F-52 of our Form 10-K.

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



|                                              |  |                         |    |   |                |   |    |      |  |      |   |  |   |  
|--------------------------------------------- |  | ----------------------- | -- | - | -------------- | - | -- | ---- |  | ---- | - |  | - | -
|                                              |  | Pension Benefits        |    |   | Other Benefits
|                                              |  | Quarter Ended March 31,
|                                              |  | 2006                    |    |   | 2005           |   |    | 2006 |  | 2005
|                                              |  | (in millions)          
|Service cost benefits earned during period    |  | $                       | 2  |   |                | $ | 3  |      |  | $    | 1 |  | $ | 1
|Interest cost on projected benefit obligation |  |                         | 2  |   |                |   | 2  |      |  |      | 1 |  |   | 1
|Expected return on plan assets                |  |                         | (2 | ) |                |   | (2 | )    |  |      |  |  |   | 
|Recognized net actuarial loss                 |  |                         | 1  |   |                |   | 1  |      |  |      |  |  |   | 
|                                              |  |                         |    |   |                |   |    |      |  |      |   |  |   |  
|Net periodic benefit cost                     |  | $                       | 3  |   |                | $ | 4  |      |  | $    | 2 |  | $ | 2
|Additional cost due to curtailment            |  |                         | 2  |   |                |   |   |      |  |      |  |  |   | 
|                                              |  |                         |    |   |                |   |    |      |  |      |   |  |   |  
|Total net periodic benefit cost               |  | $                       | 5  |   |                | $ | 4  |      |  | $    | 2 |  | $ | 2
|                                              |  |                         |    |   |                |   |    |      |  |      |   |  |   |  

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



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(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

Contributions. In our Form 10-K, we reported that we expected to contribute approximately $17 million to pension plans, $14 million of which we expect to pay in September 2006, and less than $1 million
to other postretirement benefit plans in 2006. As of March 31, 2006, we made less than $1 million in contributions.

Note 12Income Taxes

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



|                             |  |                              |     |   |      |   |    |  
|---------------------------- |  | ---------------------------- | --- | - | ---- | - | -- | -
|                             |  | Three Months Ended March 31, |    
|                             |  | 2006                         |     |   | 2005 |  
|                             |  | (in millions, except rates)  |    
|Income tax benefit (expense) |  | $                            | (10 | ) |      | $ | 59 |  
|Effective tax rate           |  |                              | 37  | % |      |   | 32 | %

We compute our quarterly taxes under the effective tax rate method based on applying an
anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the
specific transaction occurs. During 2006, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily from the effect of certain foreign and state income taxes. During 2005, our overall
effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to the nondeductible portion of the charge associated with the shareholder litigation settlement, offset by changes in the valuation allowances.

Note 13Segment Information

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

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 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.

Our former natural
gas liquids operations comprise the NGL segment and are included in discontinued operations. Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2006
and 2005 is presented below:



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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

Segment Data for the Quarter Ended March 31, 2006

(in millions)



|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|----------------------------------------------------- |  | ---------------- | ----- | - | ------ | - | --- | ------ | --------------------- | - | --- | ----- |  | - | --- |  | - | -- |  | - | ----- | - |  | - | ----- | -
|                                                      |  | Power Generation |       |   | CRM    |   | NGL |        | Other andEliminations |   |     | Total | 
|                                                      |  | GEN-MW           |       |   | GEN-NE |   |     | GEN-SO |                       |   |     |       | 
|Unaffiliated revenues:                                |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Domestic                                              |  | $                | 256   |   |        | $ | 82  |        |                       | $ | 111 |       |  | $ | 26  |  | $ |   |  | $ |      |   |  | $ | 475   |  
|Other                                                 |  |                  |      |   |        |   |    |        |                       |   |    |       |  |   | 5   |  |   |   |  |   |      |   |  |   | 5     |  
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|                                                      |  |                  | 256   |   |        |   | 82  |        |                       |   | 111 |       |  |   | 31  |  |   |   |  |   |      |   |  |   | 480   |  
|Affiliate revenues                                    |  |                  |      |   |        |   |    |        |                       |   |    |       |  |   | 40  |  |   |   |  |   |      |   |  |   | 40    |  
|Intersegment revenues                                 |  |                  |      |   |        |   | (1  | )      |                       |   |    |       |  |   | 1   |  |   |   |  |   |      |   |  |   |      |  
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Total revenues                                        |  | $                | 256   |   |        | $ | 81  |        |                       | $ | 111 |       |  | $ | 72  |  | $ |   |  | $ |      |   |  | $ | 520   |  
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Depreciation and amortization                         |  | $                | (40   | ) |        | $ | (3  | )      |                       | $ | (6  | )     |  | $ |    |  | $ |   |  | $ | (8    | ) |  | $ | (57   | )
|Operating income (loss)                               |  | $                | 98    |   |        | $ | 17  |        |                       | $ | (13 | )     |  | $ | 33  |  | $ |   |  | $ | (47   | ) |  | $ | 88    |  
|Earnings from unconsolidated investments              |  |                  |      |   |        |   |    |        |                       |   | 2   |       |  |   |    |  |   |   |  |   |      |   |  |   | 2     |  
|Other items, net                                      |  |                  |      |   |        |   |    |        |                       |   |    |       |  |   | 1   |  |   |   |  |   | 14    |   |  |   | 15    |  
|Interest expense                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   | (78   | )
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Income from continuing operations before income taxes |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   | 27    |  
|Income tax expense                                    |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   | (10   | )
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Income from continuing operations                     |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   | 17    |  
|Income from discontinued operations, net of taxes     |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   | 1     |  
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Net income                                            |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  | $ | 18    |  
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Identifiable assets:                                  |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Domestic                                              |  | $                | 4,587 |   |        | $ | 411 |        |                       | $ | 830 |       |  | $ | 728 |  | $ | 30 |  | $ | 1,604 |   |  | $ | 8,190 |  
|Other                                                 |  |                  |      |   |        |   |    |        |                       |   |    |       |  |   | 69  |  |   |   |  |   |      |   |  |   | 69    |  
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Total                                                 |  | $                | 4,587 |   |        | $ | 411 |        |                       | $ | 830 |       |  | $ | 797 |  | $ | 30 |  | $ | 1,604 |   |  | $ | 8,259 |  
|                                                      |  |                  |       |   |        |   |     |        |                       |   |     |       |  |   |     |  |   |    |  |   |       |   |  |   |       |  
|Unconsolidated investments                            |  | $                |      |   |        | $ |    |        |                       | $ | 4   |       |  | $ |    |  | $ |   |  | $ |      |   |  | $ | 4     |  
|Capital expenditures                                  |  | $                | (11   | ) |        | $ | (3  | )      |                       | $ | (3  | )     |  | $ |    |  | $ |   |  | $ | (1    | ) |  | $ | (18   | )



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

Segment Data for the Quarter Ended March 31, 2005

(in millions)



|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|--------------------------------------------------- |  | ---------------- | ----- | - | ------ | - | --- | ------ |  | - | ---------------------- | - |  | ----- | ----- | - |  | - | ----- | - |  | - | ---- | - |  | - | ------ | -
|                                                    |  | Power Generation |       |   | CRM    |   |     | NGL    |  |   | Other and Eliminations |   |  | Total |      
|                                                    |  | GEN-MW           |       |   | GEN-NE |   |     | GEN-SO |  |   |                        |   | 
|Unaffiliated revenues:                              |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Domestic                                            |  | $                | 214   |   |        | $ | 121 |        |  | $ | 72                     |   |  | $     | 33    |   |  | $ |      |   |  | $ |     |   |  | $ | 440    |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |                       |   |  |       | (46   | ) |  |   |      |   |  |   |     |   |  |   | (46    | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|                                                    |  |                  | 214   |   |        |   | 121 |        |  |   | 72                     |   |  |       | (13   | ) |  |   |      |   |  |   |     |   |  |   | 394    |  
|Affiliate revenues                                  |  |                  |      |   |        |   |    |        |  |   |                       |   |  |       | 54    |   |  |   |      |   |  |   |     |   |  |   | 54     |  
|Intersegment revenues                               |  |                  |      |   |        |   | 2   |        |  |   | (12                    | ) |  |       | 10    |   |  |   |      |   |  |   |     |   |  |   |       |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Total revenues                                      |  | $                | 214   |   |        | $ | 123 |        |  | $ | 60                     |   |  | $     | 51    |   |  | $ |      |   |  | $ |     |   |  | $ | 448    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Depreciation and amortization                       |  | $                | (37   | ) |        | $ | (3  | )      |  | $ | (5                     | ) |  | $     | (1    | ) |  | $ |      |   |  | $ | (7   | ) |  | $ | (53    | )
|Operating income (loss)                             |  | $                | 61    |   |        | $ | 14  |        |  | $ | (12                    | ) |  | $     | 9     |   |  | $ |      |   |  | $ | (184 | ) |  | $ | (112   | )
|Earnings from unconsolidated investments            |  |                  |      |   |        |   |    |        |  |   | 3                      |   |  |       |      |   |  |   |      |   |  |   |     |   |  |   | 3      |  
|Other items, net                                    |  |                  |      |   |        |   |    |        |  |   | (1                     | ) |  |       | 1     |   |  |   |      |   |  |   |     |   |  |   |       |  
|Interest expense                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | (75    | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Loss from continuing operations before income taxes |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | (184   | )
|Income tax benefit                                  |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | 59     |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Loss from continuing operations                     |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | (125   | )
|Income from discontinued operations, net of taxes   |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   | 31     |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Net loss                                            |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  | $ | (94    | )
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Identifiable assets:                                |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Domestic                                            |  | $                | 5,076 |   |        | $ | 443 |        |  | $ | 1,053                  |   |  | $     | 1,323 |   |  | $ | 1,596 |   |  | $ | 729  |   |  | $ | 10,220 |  
|Other                                               |  |                  |      |   |        |   |    |        |  |   |                       |   |  |       | 191   |   |  |   |      |   |  |   |     |   |  |   | 191    |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Total                                               |  | $                | 5,076 |   |        | $ | 443 |        |  | $ | 1,053                  |   |  | $     | 1,514 |   |  | $ | 1,596 |   |  | $ | 729  |   |  | $ | 10,411 |  
|                                                    |  |                  |       |   |        |   |     |        |  |   |                        |   |  |       |       |   |  |   |       |   |  |   |      |   |  |   |        |  
|Unconsolidated investments                          |  | $                | 62    |   |        | $ |    |        |  | $ | 276                    |   |  | $     |      |   |  | $ | 77    |   |  | $ |     |   |  | $ | 415    |  
|Capital expenditures                                |  | $                | (37   | ) |        | $ | (3  | )      |  | $ |                       |   |  | $     |      |   |  | $ | (10   | ) |  | $ | (4   | ) |  | $ | (54    | )



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DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2006 and 2005

Note 14Subsequent Events

On April 12, 2006, we completed the SPN Tender Offer in which we purchased $150 million
of our $225 million 2008 Notes, substantially all of our $625 million 2010 Notes and all of our $900 million 2013 Notes. Please see Note 7Debt Second Priority Senior Secured Notes for further discussion.

On April 12, 2006, we issued $750,000,000 aggregate principal amount of our New Senior Notes in the Senior Notes Offering. Please see Note
7Debt Senior Unsecured Notes for further discussion.

On April 19, 2006, we entered into the Fourth Senior Secured Credit
Facility. The Fourth Senior Secured Credit Facility amended our former credit facility, upsized the revolving credit facility to $470 million and added a $200 million term facility. Please see Note 7Debt Senior Secured Credit Facility
for further discussion.



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DYNEGY HOLDINGS INC.

MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended March 31, 2006 and 2005

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

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

GENERAL

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

Recent Developments

Sterlington Termination.On March 7, 2006, we completed the termination of the Sterlington long-term wholesale power tolling contract
with Quachita Power LLC. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSterlington Contract Termination for further discussion.

Exchange of Ownership Interests. On March 31, 2006, we completed our acquisition of NRGs 50% ownership interest in the entity
that owns the Rocky Road power plant, a 364-megawatt natural gas-fired peaking facility near Chicago (of which Dynegy already owned 50%), and the sale to NRG of our 50% ownership interest in a joint venture between us and NRG which has ownership in
power plants in southern California. As a result of the two transactions, we received net cash proceeds of approximately $160 million from NRG. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions
and Contract TerminationsWest Coast Power for further discussion.

Liability Management.During March and April 2006,
we initiated several transactions to utilize proceeds from the October 2005 sale of DMSLP consistent with our key objectives. These key objectives were: (i) reduce existing debt obligations, (ii) reduce interest expense, (iii) reduce
near- to medium-term debt maturities, (iv) maintain adequate liquidity and (v) enhance capital structure flexibility. We believe that these transactions will better align our capital structure with the inherently cyclical nature of our
industry and enhance our ability to benefit from the anticipated future market recovery and to access the capital markets. To that end, we accomplished the following:



| |  |  | On March 6, 2006, we entered into a third amended and restated credit agreement (the Third Senior Secured Credit Facility). The Third Senior Secured Credit Facility
replaced our former cash collateralized letter of credit facility with a $400 million revolving credit facility thereby permitting the return to us of $335 million plus accrued interest in cash collateral securing the former letter of credit
facility (the Cash Collateral Return).
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | On April 12, 2006, we completed a tender offer and consent solicitation (the SPN Tender Offer) in which we purchased $150 million of our $225 million outstanding
Second Priority Senior Secured Floating Rate Notes due 2008 (the 2008 Notes), substantially all of our $625 million 9.875% Second Priority Senior Secured Notes due 2010 (the 2010 Notes) and all of our $900 million 10.125%
Second Priority Senior Secured Notes due 2013 (the 2013 Notes and, collectively with the 2008 Notes and the 2010 Notes, the Second Priority Notes).
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Concurrent with the closing of the SPN Tender Offer, we issued $750,000,000 aggregate principal amount of 8.375% Senior Unsecured Notes due 2016 (the New Senior Notes)
in a private offering (the Senior Notes Offering). We used proceeds from the Senior Notes Offering, together with cash on hand, to fund the SPN Tender Offer.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | On April 19, 2006, we entered into a fourth amended and restated credit agreement (the Fourth Senior Secured Credit Facility). The Fourth Senior Secured Credit
Facility amended our former credit facility, upsized the revolving credit facility to $470 million and added a $200 million letter of credit facility funded with term loan proceeds.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements and our internal and external liquidity and capital resources. Our liquidity and
capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures, regulatory and legal settlements and working
capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas and coal, facility maintenance costs (including required environmental expenditures) and other
costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, asset sale proceeds and proceeds from capital market transactions to the
extent we engage in these activities. Additionally, from time to time, we may borrow money from our parent.

Debt Obligations

During 2006, we continued our efforts to reduce our outstanding debt and extend our maturity profile, evidenced by the transactions discussed under
Liability Management above. Please read Note 7Debt for further discussion.

We may further reduce our outstanding debt if
we exercise our contractual option to call for redemption, on or after July 15, 2006, any remaining outstanding 2008 Notes at the redemption price of $1,030.00 per $1,000 principal amount thereof, plus accrued and unpaid interest to the
redemption date. Any such notice, if given, will be given in accordance with the applicable provisions of the indenture. We may ultimately determine not to effect the redemption of the remaining outstanding 2008 Notes. Pursuant to the indenture
governing the Second Priority Notes, the 2010 Notes are redeemable at our option on or after July 15, 2007 at the redemption price of $1,049.38 per $1,000 principal amount thereof, plus accrued and unpaid interest to the redemption date.



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Collateral Postings

We continue to use a significant portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands. These counterparty collateral demands reflect our
non-investment grade credit ratings and counterparties views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. The following table summarizes our consolidated
collateral postings to third parties by segment at May 4, 2006, March 31, 2006 and December 31, 2005:



|                         |  |               |     |               |   |                  |  |   |    
|------------------------ |  | ------------- | --- | ------------- | - | ---------------- |  | - | ---
|                         |  | May 4, 2006   |     | March 31,2006 |   | December 31,2005
|                         |  | (in millions)
|By Segment:              |  |               |     |               |   |                  |  |   |    
|Generation               |  | $             | 149 |               | $ | 159              |  | $ | 263
|Customer risk management |  |               | 84  |               |   | 76               |  |   | 106
|Other                    |  |               | 10  |               |   | 10               |  |   | 12 
|                         |  |               |     |               |   |                  |  |   |    
|Total                    |  | $             | 243 |               | $ | 245              |  | $ | 381
|                         |  |               |     |               |   |                  |  |   |    
|By Type:                 |  |               |     |               |   |                  |  |   |    
|Cash (1)                 |  | $             | 68  |               | $ | 67               |  | $ | 122
|Letters of Credit        |  |               | 175 |               |   | 178              |  |   | 259
|                         |  |               |     |               |   |                  |  |   |    
|Total                    |  | $             | 243 |               | $ | 245              |  | $ | 381
|                         |  |               |     |               |   |                  |  |   |    

---

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

The decrease in collateral postings from December 31, 2005 to March 31, 2006 is
primarily due to a return of collateral postings of approximately $104 million in our generation business and $30 million in our customer risk management business. This decrease is primarily a result of decreases in commodity prices since the end of
2005, as well as rolloffs of our hedging positions. In addition, the collateral posted on behalf of West Coast Power decreased by approximately $25 million in anticipation of the sale of our 50% interest in West Coast Power to NRG, completed on
March 31, 2006. As of March 31 and May 4, 2006, we posted approximately $21 million and $6 million, respectively, of collateral on behalf of West Coast Power, all of which is offset by cash collateral received from West Coast Power.
Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsWest Coast Power for further discussion of the West Coast Power sale.

Going forward, we expect counterparties collateral demands to continue to reflect changes in commodity prices, including seasonal changes in
weather-related demand, as well as their views of our creditworthiness. Considering our credit ratings and current commodity price estimates, specifically as prices relate to fuel purchases and power hedging activities, we estimate that collateral
requirements will be approximately $300 million at year-end 2006. We believe that we have sufficient capital resources to satisfy counterparties collateral demands, including those for which no collateral is currently posted, for the
foreseeable future.

Disclosure of Contractual Obligations and Contingent Financial Commitments

We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual
obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly
supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees.

Our contractual obligations and contingent financial commitments have changed since December 31, 2005, with respect to which information is included
in our Form 10-K. As a result of the termination of the Sterlington long-term wholesale power tolling contract with Quachita Power, capacity payments of up to approximately $744 million have been eliminated. Please read Note 3Dispositions,
Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSterlington Contract Termination for further discussion.



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As of March 31, 2006, there were no other material changes to our contractual obligations and
contingent financial commitments since December 31, 2005.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our Fourth Senior Secured Credit
Facility, which is scheduled to mature in April 2009. Additionally, from time to time, we may borrow money from our parent.

Current
Liquidity.The following table summarizes our consolidated revolver capacity and liquidity position at May 4, 2006, March 31, 2006 and December 31, 2005:



|                                                                       |  |               |      |        |               |   |       |                  |  |   |       |    
|---------------------------------------------------------------------- |  | ------------- | ---- | ------ | ------------- | - | ----- | ---------------- |  | - | ----- | ---
|                                                                       |  | May 4,2006    |      |        | March 31,2006 |   |       | December 31,2005 | 
|                                                                       |  | (in millions) |     
|Total revolver capacity                                                |  | $             | 470  | (1)    |               | $ | 400   | (1)              |  | $ |      |    
|Total additional letter of credit capacity plus 3% reserve requirement |  |               | 194  |        |               |   |      |                  |  |   | 325   |    
|Outstanding letters of credit under revolving credit facility          |  |               | (175 | )      |               |   | (178  | )                |  |   | (259  | )  
|                                                                       |  |               |      |        |               |   |       |                  |  |   |       |    
|Unused revolver capacity                                               |  |               | 489  |        |               |   | 222   |                  |  |   | 66    |    
|Cash                                                                   |  |               | 254  | (2)(3) |               |   | 1,315 | (2)              |  |   | 1,301 | (2)
|                                                                       |  |               |      |        |               |   |       |                  |  |   |       |    
|Total available liquidity                                              |  | $             | 743  |        |               | $ | 1,537 |                  |  | $ | 1,367 |    
|                                                                       |  |               |      |        |               |   |       |                  |  |   |       |    

---

|(1) | In March and April 2006, we amended and restated the credit facility. Please see Note 7Debt for further discussion.
|--- | --------------------------------------------------------------------------------------------------------------------

|(2) | The May 4, 2006, March 31, 2006 and December 31, 2005 amounts include approximately $19 million, $22 million and $21 million, respectively, of cash that remains
in Europe. and $20 million, $18 million and $19 million, respectively, of cash that remains in Canada.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | The decrease in cash balance since March 31, 2006 was primarily due to the payments associated with our SPN Tender Offer, offset by the proceeds from the issuance of our Senior
Unsecured Notes. Please read Note 7Debt for further discussion.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Cash Flows from Operations. We had
operating cash outflows of $341 million for the three months ended March 31, 2006. This consisted of $193 million in operating cash flows from our power generation business, offset by $387 million of cash outflows relating to our customer risk
management business and $147 million of cash outflows relating to corporate-level expenses. Please read Results of OperationsOperating Income (Loss) and Cash Flow Disclosures for further discussion of
factors impacting our operating cash flows for the periods presented.

Over the longer term, our operating cash flows also will be impacted
by, among other things, our ability to manage tightly our operating costs, including costs for fuel and maintenance. Our ability to achieve targeted cost savings in the face of industry-wide increases in labor and benefits costs, together with
changes in commodity prices, will impact our future operating cash flows. Please read Results of Operations2006 Outlook for further discussion.

Cash on Hand. At May 4, 2006 and March 31, 2006, we had cash on hand of $254 million and $1,315 million, respectively, as compared to $1,301 million at the end of 2005. This slight
increase in cash on hand to March 31, 2006 as compared to the end of 2005 is primarily attributable to (i) the return of $335 million of cash collateral plus accrued interest posted for the former Third Amended and Restated Credit Facility
and (ii) proceeds of $205 million received from the sale of our 50% ownership interest in the West Coast Power power plants to NRG. This was largely



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offset by (i) payment of $40 million, net of cash acquired of $5 million, to NRG for acquiring NRGs 50%
ownership interest in the Rocky Road power plant and (ii) payment of $370 million to Quachita Power LLC to terminate the Sterlington long-term wholesale power tolling contract and (iii) repayment of $120 million of borrowings from Dynegy.
The decrease in cash balance on May 4, 2006 from March 31, 2006 was primarily due to the payments associated with our SPN Tender Offer, offset by the proceeds from the issuance of our Senior Unsecured Notes. Please read Note 7Debt
for further discussion.

Revolver Capacity. In April 2006, we entered into the Fourth Senior Secured Credit Facility.
The Fourth Senior Secured Credit Facility replaces our former Third Senior Secured Credit Facility. Please read Note 20Subsequent Events beginning on page F-62 of our Form 10-K for further discussion of our former Third Senior Secured Credit
Facility. This credit facility is scheduled to mature in April 2009 and is our primary credit facility. We currently have no drawn amounts under this facility, although as of May 4, 2006, we had $175 million in letters of credit issued under
the facility. Our ability to borrow and/or issue letters of credit under a revolving credit facility could become increasingly important to our liquidity and financial condition, particularly if we are unable to generate operating cash flows
relative to our substantial debt obligations and ongoing operating requirements. Please read Note 7Debt for further discussion of our Fourth Senior Secured Credit Facility.

External Liquidity Sources

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

Asset Sale Proceeds. In March 2006, we completed our ownership exchange
transaction with NRG Energy, Inc. which comprised our acquisition of NRGs 50% ownership interest in the entity that owns the Rocky Road power plant (of which Dynegy already owned 50%), and the sale to NRG of our 50% ownership interest in a
joint venture between us and NRG which has ownership in power plants in southern California. As a result of the two transactions, we received net cash proceeds of approximately $160 million from NRG. Please read Note 3Dispositions, Contract
Terminations and Discontinued OperationsDispositions and Contract TerminationsWest Coast Power for further discussion.

Going
forward, we will continue to evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. Consistent with industry practice, we periodically consider divestitures of non-core
generation assets where the balance of the factors described above suggests that such assets earnings potential is limited. Although we have not executed definitive agreements regarding the divestitures of any non-core assets, opportunities
arise from time to time and, as a result, a divestiture could occur at any time.

Capital-Raising Transactions. As part of
Dynegys ongoing efforts to develop a capital structure that is more closely aligned with the cash-generating potential of the consolidated enterprises asset-based business, which is subject to cyclical changes in commodity prices, Dynegy
is continuing to explore additional capital-raising transactions both in the near- and long-term. The timing of any capital-raising transaction may be impacted by unforeseen events, such as strategic growth opportunities, legal judgments or
regulatory requirements, which could require it to pursue additional capital in the near term.

Conclusion

We have recently completed financing transactions designed to (i) reduce existing debt obligations, (ii) reduce interest expense,
(iii) reduce near- to medium-term debt maturities, (iv) maintain adequate liquidity and (v) enhance capital structure flexibility. We believe that these transactions will better align our capital structure with the inherently cyclical
nature of our industry and enhance our ability to benefit from the anticipated market recovery and to access the capital markets.

We
intend to continue our efforts to manage costs and capital expenditures effectively. To that end, in December 2005, we implemented a comprehensive plan to better align our corporate cost structure with our single line



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of business. The plan included headcount reductions and system changes, and has resulted in a reduction of our run-rate
general and administrative expenses. Further, our generation assets are managed to require a relatively predictable level of maintenance capital expenditures without compromising the operational integrity of our facilities, allowing us to maintain
our focus on being a reliable, low-cost producer of physical products and provider of services.

We believe that our efficient and scalable
operations platform, together with our multi-fuel capabilities and regionally-focused presence, position us to benefit from opportunities that might arise in connection with any growth transactions, industry consolidations or other strategic
activities. To achieve these strategic objectives, we expect to continue to develop opportunities that may expand our existing facilities, achieve operating efficiencies or pursue opportunistic and selective expansion of our generation portfolio.
Please read Item 1A-Risk Factors for further discussion.

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

RESULTS OF OPERATIONS

Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by
segment, for the three-month periods ended March 31, 2006 and 2005. At the end of this section, we have included our 2006 outlook for each segment.

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



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Summary Financial Information.The following tables provide summary financial data
regarding our consolidated and segmented results of operations for the three-month periods ended March 31, 2006 and 2005, respectively:

Quarter Ended March 31, 2006



|                                                      |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   |     |  
|----------------------------------------------------- |  | ---------------- | -- | -------- | --- | ------ | --------------------- | - | --- | ----- |  | - | -- |  | - | --- | - |  | - | --- | -
|                                                      |  | Power Generation |    |          | CRM |        | Other andEliminations |   |     | Total | 
|                                                      |  | GEN-MW           |    | GEN - NE |     | GEN-SO |                       |   |     |      
|                                                      |  | (in millions)    |   
|Operating income (loss)                               |  | $                | 98 |          | $   | 17     |                       | $ | (13 | )     |  | $ | 33 |  | $ | (47 | ) |  | $ | 88  |  
|Earnings from unconsolidated investments              |  |                  |   |          |     |       |                       |   | 2   |       |  |   |   |  |   |    |   |  |   | 2   |  
|Other items, net                                      |  |                  |   |          |     |       |                       |   |    |       |  |   | 1  |  |   | 14  |   |  |   | 15  |  
|Interest expense                                      |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   | (78 | )
|                                                      |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   |     |  
|Income from continuing operations before income taxes |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   | 27  |  
|Income tax expense                                    |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   | (10 | )
|                                                      |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   |     |  
|Income from continuing operations                     |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   | 17  |  
|Income from discontinued operations, net of taxes     |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   | 1   |  
|                                                      |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   |     |  
|Net income                                            |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  | $ | 18  |  
|                                                      |  |                  |    |          |     |        |                       |   |     |       |  |   |    |  |   |     |   |  |   |     |  

Quarter Ended March 31, 2005



|                                                    |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   |      |  
|--------------------------------------------------- |  | ---------------- | -- | -------- | --- | ------ | --------------------- | - | --- | ----- |  | - | - |  | - | ---- | - |  | - | ---- | -
|                                                    |  | Power Generation |    |          | CRM |        | Other andEliminations |   |     | Total | 
|                                                    |  | GEN-MW           |    | GEN - NE |     | GEN-SO |                       |   |     |      
|                                                    |  | (in millions)    |   
|Operating income (loss)                             |  | $                | 61 |          | $   | 14     |                       | $ | (12 | )     |  | $ | 9 |  | $ | (184 | ) |  | $ | (112 | )
|Earnings from unconsolidated investments            |  |                  |   |          |     |       |                       |   | 3   |       |  |   |  |  |   |     |   |  |   | 3    |  
|Other items, net                                    |  |                  |   |          |     |       |                       |   | (1  | )     |  |   | 1 |  |   |     |   |  |   |     |  
|Interest expense                                    |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   | (75  | )
|                                                    |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   |      |  
|Loss from continuing operations before income taxes |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   | (184 | )
|Income tax benefit                                  |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   | 59   |  
|                                                    |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   |      |  
|Loss from continuing operations                     |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   | (125 | )
|Income from discontinued operations, net of taxes   |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   | 31   |  
|                                                    |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   |      |  
|Net loss                                            |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  | $ | (94  | )
|                                                    |  |                  |    |          |     |        |                       |   |     |       |  |   |   |  |   |      |   |  |   |      |  



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The following table provides summary segmented operating statistics for the three months ended
March 31, 2006 and 2005, respectively:



|                                                  |  |                         |      |      |   |     
|------------------------------------------------- |  | ----------------------- | ---- | ---- | - | ----
|                                                  |  | Quarter Ended March 31,
|                                                  |  | 2006                    |      | 2005
|GEN-MW                                            |  |                         |      |      |   |     
|Million Megawatt Hours GeneratedGross and Net    |  |                         | 5.4  |      |   | 5.0 
|Average On-Peak Market Power Prices ($/MWh):      |  |                         |      |      |   |     
|Cinergy (Cin Hub)                                 |  | $                       | 49   |      | $ | 49  
|Commonwealth Edison (NI Hub)                      |  | $                       | 50   |      | $ | 49  
|                                                  |  |                        
|GEN-NE                                            |  |                         |      |      |   |     
|Million Megawatt Hours GeneratedGross and Net    |  |                         | 0.7  |      |   | 1.5 
|Average On-Peak Market Power Prices ($/MWh):      |  |                         |      |      |   |     
|New York Zone G                                  |  | $                       | 76   |      | $ | 70  
|                                                  |  |                        
|GEN-SO                                            |  |                         |      |      |   |     
|Million Megawatt Hours Generated Gross           |  |                         | 1.4  |      |   | 1.7 
|Million Megawatt Hours Generated Net             |  |                         | 1.1  |      |   | 1.3 
|Average On-Peak Market Power Prices ($/MWh):      |  |                         |      |      |   |     
|Southern                                          |  | $                       | 55   |      | $ | 49  
|ERCOT                                             |  | $                       | 56   |      | $ | 51  
|SP-15                                             |  | $                       | 58   |      | $ | 56  
|                                                  |  |                        
|Average natural gas priceHenry Hub ($/MMBtu) (1) |  | $                       | 7.75 |      | $ | 6.39

---

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

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



|                             |  |                              |   |        |   |        |     |   |       |  |   |       |   |  |   |    |  |   |      |   |  |   |      |  
|---------------------------- |  | ---------------------------- | - | ------ | - | ------ | --- | - | ----- |  | - | ----- | - |  | - | -- |  | - | ---- | - |  | - | ---- | -
|                             |  | Quarter Ended March 31, 2006 |  
|                             |  | Power Generation             |   | CRM    |   |        | NGL |   | Other |  |   | Total |  
|                             |  | GEN-MW                       |   | GEN-NE |   | GEN-SO |     |   |       | 
|                             |  | (in millions)                |  
|Legal and settlement charges |  | $                            |  |        | $ |       |     | $ |      |  | $ | (15   | ) |  | $ |   |  | $ |     |   |  | $ | (15  | )
|                             |  |                              |   |        |   |        |     |   |       |  |   |       |   |  |   |    |  |   |      |   |  |   |      |  
|Total                        |  | $                            |  |        | $ |       |     | $ |      |  | $ | (15   | ) |  |   |   |  | $ |     |   |  | $ | (15  | )
|                             |  |                              |   |        |   |        |     |   |       |  |   |       |   |  |   |    |  |   |      |   |  |   |      |  
|                             | 
|                             |  | Quarter Ended March 31, 2005 |  
|                             |  | Power Generation             |   | CRM    |   |        | NGL |   | Other |  |   | Total |  
|                             |  | GEN-MW                       |   | GEN-NE |   | GEN-SO |     |   |       | 
|                             |  | (in millions)                |  
|Discontinued operations      |  | $                            |  |        | $ |       |     | $ |      |  | $ | 4     |   |  | $ | 46 |  | $ |     |   |  | $ | 50   |  
|Legal and settlement charges |  |                              |  |        |   |       |     |   |      |  |   |      |   |  |   |   |  |   | (154 | ) |  |   | (154 | )
|                             |  |                              |   |        |   |        |     |   |       |  |   |       |   |  |   |    |  |   |      |   |  |   |      |  
|Total                        |  | $                            |  |        | $ |       |     | $ |      |  | $ | 4     |   |  | $ | 46 |  | $ | (154 | ) |  | $ | (104 | )
|                             |  |                              |   |        |   |        |     |   |       |  |   |       |   |  |   |    |  |   |      |   |  |   |      |  

Operating Income (Loss)

Operating income was $88 million for the three months ended March 31, 2006, compared to a loss of $112 million for the three months ended
March 31, 2005.

Power Generation Midwest Segment.Operating income for GEN-MW was $98 million for the three
months ended March 31, 2006, compared to $61 million for the three months ended March 31, 2005. GEN-MW results for the three months ended March 31, 2005 included general and administrative expenses of $8 million.



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Beginning in 2006, general and administrative expenses are reported in our Other segment. Please see Results of
OperationsOperating Income (Loss)Other for a consolidated discussion of general and administrative expenses.

Results
from our coal-fired generating units increased to $135 million for the three months ended March 31, 2006 from $107 million for the three months ended March 31, 2005. This improvement was driven by an 8% increase in generated volumes, up
from 5.0 million MWh for the first quarter 2005 to 5.4 million MWh for the same period in 2006. Average actual on-peak prices in NI Hub/ComEd pricing region increased from $49 per MWh in first quarter 2005 to $50 per MWh for the first
quarter 2006. However, we realized higher power prices in the first quarter 2006 as we settled forward power sales, which had been entered into during the fourth quarter 2005.

GEN-MWs results for the first three months of 2006 include no significant mark-to-market income, compared with losses of $4 million for the three
months ended March 31, 2005. This is primarily related to options and other transactions that economically hedged our generation assets, and were not accounted for as cash flow hedges.

Results for our gas-fired peaking facilities in GEN-MW improved by $5 million, increasing from a loss of $2 million for the first three months of 2005 to
positive earnings of $3 million for the same period in 2006. This improvement was the result of higher volume as the MISO increased dispatch of these units during first quarter 2006 to maintain system reliability.

Depreciation expense increased slightly, from $37 million in 2005 to $40 million in 2006 as a result of capital projects placed into service in 2005.
This was primarily the conversion of the Havana facility to burn PRB coal.

Power Generation Northeast Segment.Operating income for GEN-NE was $17 million for the three months ended March 31, 2006, compared to $14 million for the three months ended March 31, 2005. GEN-NE for the three months ended March 31, 2005 included general and
administrative expenses of $3 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please see Results of OperationsOperating Income (Loss)Other for a consolidated discussion of
general and administrative expenses.

Average on-peak prices for Zone G, the market served by our Roseton and Danskammer facilities,
increased from $70 per MWh in 2005 to $76 per MWh in 2006. However, this price increase was largely offset by a volume decrease, caused by compressed spark spreads at our Roseton facility, where volumes fell by 0.7 million MWh from first
quarter 2005 as compared to first quarter 2006. Generated volumes at our Danskammer facility decreased by 0.2 million MWh from first quarter 2005 to first quarter 2006. Results also increased by $10 million as a result of the opportunistic sale
of emissions credits that will not be required for the near-term operations of our facilities. However, this increase was offset by net mark-to-market losses of $6 million for the first quarter 2006, related to financial transactions not designated
as cash flow hedges. First quarter 2005 results included mark-to-market gains of $3 million.

Depreciation expense for GEN-NE was $3
million for the three months ended March 31, 2006, which was not materially different from the same period in 2005.

Power
Generation South Segment.Operating loss for GEN-SO was $13 million for three months ended March 31, 2006, compared to a loss of $12 million for three months ended March 31, 2005. GEN-SO for the three months ended
March 31, 2005 included general and administrative expenses of $3 million. Beginning in 2006, general and administrative expenses are reported in our Other segment. Please see Results of OperationsOperating Income
(Loss)Other for a consolidated discussion of general and administrative expenses.

Results from our ERCOT facility decreased by
$6 million, from a loss of $4 million in 2005 to a loss of $10 million in 2006. Power prices increased by 10% from 2005 to 2006. This was offset by the negative effect of higher gas prices on the steam contract at our CoGen Lyondell cogeneration
facility in 2006. In addition, we were able to capture additional revenue for ancillary services provided to ERCOT in first quarter 2005 at levels that we were not asked to provide in first quarter 2006.



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Results from our southeast peaker assets increased slightly from negligible earnings in first quarter
2005 to earnings of $1 million in the same period in 2006 as a result of additional capacity sales from our Rockingham facility.

Depreciation expense increased slightly from $5 million to $6 million, as a result of additional capital spending.

CRM.Operating income for the CRM segment was $33 million for the three months ended March 31, 2006, compared to operating income of $9 million for the three months ended March 31, 2005. 2006 income was partially driven by
mark-to-market gains on our legacy emissions positions, offset by a $15 million increase in legal reserves resulting from additional activities during the period that negatively affected managements assessment of the probable and estimable
losses associated with the applicable proceedings. Additionally, we recognized $18 million of income from our tolling and financial swap arrangements with Sithe Energies. The income is driven primarily by the effect of gas and power price volatility
on the value of our financial swap instrument.

2005 income primarily relates to mark-to-market income arising from legacy trading
positions and the financial swap contract arrangements with Sithe Energies, which offset net losses associated with our remaining tolling arrangements.

Other.Other operating loss was $47 million for the quarter ended March 31, 2006, compared to a loss of $184 million for the quarter ended March 31, 2005. Results for first quarter 2006 include
approximately $36 million of general and administrative expenses, including costs related to our business segments, which prior to first quarter 2006 were included in the individual segments. Results for the three months ended March 31, 2005
included general and administrative expenses of $177 million. Please see below for a consolidated discussion of general and administrative expenses.

Consolidated general and administrative expenses decreased from $191 million for the three months ended March 31, 2005 to $51 million for the three months ended March 31, 2006, primarily due to a $154
million charge associated with settlement of our shareholder class action litigation in 2005, offset by the $15 million legal reserve recorded in 2006 in our CRM segment.

Earnings from Unconsolidated Investments

The $2 million earnings reported from unconsolidated
investments for the three months ended March 31, 2006 included the GEN-SO investment in Black Mountain. The $3 million earnings reported for the three months ended March 31, 2005 includes results from GEN-SO investments in both Black
Mountain and West Coast Power.

Other Items, Net

Other items, net totaled $15 million of income for the three months ended March 31, 2006, compared to zero for the three months ended March 31,
2005. The increase is primarily associated with higher interest income in 2006 resulting from higher cash balances and higher interest rates.

Interest Expense

Interest expense totaled $78 million for the three months ended March 31, 2006, compared to
$75 million for the three months ended March 31, 2005. The increase is primarily attributable to increases in LIBOR.

Income Tax
Benefit (Expense)

We reported an income tax expense from continuing operations of $10 million during the three months ended
March 31, 2006, compared to an income tax benefit from continuing operations of $59 million during the three months ended March 31, 2005. The 2006 effective tax rate was 37%, compared to 32% in 2005. During 2006, our overall effective tax
rate on continuing operations was different than the statutory rate of 35% due primarily from the effect of certain foreign and state income taxes. During 2005, our overall effective tax rate on continuing operations was different than the statutory
rate of 35% due primarily to the nondeductible portion of the charge associated with the shareholder litigation settlement, offset by changes in the valuation allowances.



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Discontinued Operations

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

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

Three Months Ended March 31, 2006



|                                                                 |  |               |   |     |   |       |  |   |    |  
|---------------------------------------------------------------- |  | ------------- | - | --- | - | ----- |  | - | -- | -
|                                                                 |  | U.K. CRM      |   | NGL |   | Total | 
|                                                                 |  | (in millions) |  
|Operating income included in income from discontinued operations |  | $             |  |     | $ | 1     |  | $ | 1  |  
|Other items, net included in income from discontinued operations |  |               | 1 |     |   |      |  |   | 1  |  
|                                                                 |  |               |   |     |   |       |  |   |    |  
|Income from discontinued operations before taxes                 |  |               |   |     |   |       |  |   | 2  |  
|Income tax expense                                               |  |               |   |     |   |       |  |   | (1 | )
|                                                                 |  |               |   |     |   |       |  |   |    |  
|Income from discontinued operations                              |  |               |   |     |   |       |  | $ | 1  |  
|                                                                 |  |               |   |     |   |       |  |   |    |  

Three Months Ended March 31, 2005



|                                                                                         |  |               |   |     |   |    |       |  |   |     |  
|---------------------------------------------------------------------------------------- |  | ------------- | - | --- | - | -- | ----- |  | - | --- | -
|                                                                                         |  | U.K. CRM      |   | NGL |   |    | Total | 
|                                                                                         |  | (in millions) |  
|Operating income included in income from discontinued operations                         |  | $             |  |     | $ | 59 |       |  | $ | 59  |  
|Earnings from unconsolidated investments included in income from discontinued operations |  |               |  |     |   | 2  |       |  |   | 2   |  
|Other items, net included in income from discontinued operations                         |  |               | 4 |     |   | (4 | )     |  |   |    |  
|Interest expense included in income from discontinued operations                         |  |               |   |     |   |    |       |  |   | (11 | )
|                                                                                         |  |               |   |     |   |    |       |  |   |     |  
|Income from discontinued operations before taxes                                         |  |               |   |     |   |    |       |  |   | 50  |  
|Income tax expense                                                                       |  |               |   |     |   |    |       |  |   | (19 | )
|                                                                                         |  |               |   |     |   |    |       |  |   |     |  
|Income from discontinued operations                                                      |  |               |   |     |   |    |       |  | $ | 31  |  
|                                                                                         |  |               |   |     |   |    |       |  |   |     |  

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

During the three months ended March 31, 2006, pre-tax income from discontinued operations of $2 million ($1 million after-tax)
included $1 million in pre-tax income attributable to NGL. During the three months ended March 31, 2005, pre-tax income from discontinued operations of $50 million ($31 million after-tax) included $46 million in pre-tax income attributable to
NGL.

In accordance with EITF Issue 87-24, Allocation of Interest to Discontinued Operations, we have allocated interest
expense to discontinued operations associated with debt instruments that were required to be paid upon the sale of DMSLP. Interest expense included in income from discontinued operations, which includes interest incurred on our former term loan and
our former Generation facility debt, totaled zero and $11 million during the three months ended March 31, 2006 and 2005, respectively.



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Income Tax Expense From Discontinued Operations. We recorded an income tax expense from
discontinued operations of $1 million during the three months ended March 31, 2006, compared to an income tax expense from discontinued operations of $19 million during the three months ended March 31, 2005. These amounts reflect effective
rates of 50% and 36%, respectively. In general, differences between these effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax
differences.

2006 Outlook

The following summarizes our outlook for the remainder of 2006 for our power generation business and our customer risk management business.

Power Generation Business. Generally,we expect that future generation business financial results will continue to reflect
sensitivity to fuel and emissions commodity prices, market prices for energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and in-market asset availability. We continue to manage price risk through
optimization of fuel procurement and we expect to limit long-term forward sales of power and related transactions in order to capture short-term market pricing opportunities. Any change in commodity prices will affect our earnings either positively
or negatively depending on the direction of the commodity price movement.

GEN- MW. We expect our results to continue
to be impacted by fuel and power prices, in-market availability of our assets and fuel availability. Although we expect power prices to continue to remain high in the Midwest, we will not be able to fully realize these prices due to volume options
held by AmerenIP in our fixed price power purchase agreement with them. This agreement expires at the end of 2006. Under terms of this power purchase agreement, AmerenIP can take up to 2,800 MW of energy and ancillary services in each hour at a
fixed price of $30/MWh around the clock from May-September; and, up to 2,300 MW of energy and ancillary services in each hour at a fixed price of $30/MWh around the clock during the other months. Over the course of a year, AmerenIPs takes are
contractually constrained by quarterly and annual limitations. Beyond these limits, AmerenIP may request up to another 150 MW in each hour at a market-based price.

Beyond 2006, Midwest results will be affected by the expiration of this power purchase agreement and decisions we make with regard to the sale of our production in the Illinois auction described below, under potential
new bilateral agreements and/or directly into the wholesale market. Depending on these decisions, expiration of this contract may result in increased exposure to market price volatility and a stronger price environment potentially allowing us to
realize additional revenue.

Another factor impacting our results in the Midwest beyond 2006 will be the regulatory environment in
Illinois. In January 2006, the Illinois Commerce Commission approved proposals by the two major Illinois electric utilities to hold an auction as the means by which they will procure capacity and energy necessary to serve load after 2006. While the
ICC issued orders approving a reverse auction process, there remains a possibility of substantial legal, regulatory, and legislative challenge to these orders and the power of the ICC to issue them. Thus, it is difficult to predict (i) whether
an auction or some other mechanism(s), if any, will be approved in advance of 2007, and (ii) what impact an auction or lack thereof will have on our results.

Operation of our Midwest generation facilities is in part dependent on our ability to procure coal. Power generators have experienced significant pressures on coal supply availability that are either transportation or
supply related. Long-term supply and transportation agreements for our Midwest fleet largely mitigate these concerns from a commitment perspective; however, we have experienced decreased delivery certainty since the third quarter 2004, and more
significantly since May 2005, as a result of increased track maintenance programs, weather delays and train derailments. As this situation persists in 2006, we may re-implement a program to selectively conserve coal during off-peak periods,
foregoing the revenue associated with this off-peak production to ensure adequate coal supply for on-peak load during high demand periods in 2006. A similar approach was successful in fourth quarter 2005.



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During 2005, our results reflected increased demand for capacity-related products from our peaking and
intermediate generation facilities. In addition, we benefited from operation of all of our peaking plants at certain times during the summer months of 2005. Based on increased demand and market design changes, including the 2005 implementation of a
fully-functioning market in MISO, we continue to expect a contribution from our peaking and intermediate generation facilities in the summer months of 2006. This will be largely subject to market demand and will therefore be heavily impacted by
weather and system reliability.

GEN-NE.We expect commodity fuel prices and market prices for energy and capacity to
continue to be strong, although current forward prices are lower than forward market highs seen in the fall of 2005. Spreads are expected to remain volatile as fuel prices change. Warmer than normal temperatures through the first three months of
2006 have resulted in lower than expected demand. As a result, we expect year-to-year decreased runtime for our at-the-money facilities in the first half of 2006, particularly at our Roseton facility.

Our results are also dependent on our ability to maintain coal and oil deliveries to the facilities. We continue to maintain sufficient coal and oil
inventories and contractual commitments to provide us with a stable fuel supply.

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

GEN-SO.We entered into various agreements in September 2005 extending the steam and energy sales component of an ongoing relationship to sell up to approximately 80 MW of energy and
1.5 million pounds per hour of steam from our CoGen Lyondell cogeneration facility to Lyondell Chemical Company for an initial term from January 2007 through December 2021 and subsequent automatic rollover terms of two years each thereafter
through December 2046. Expected incremental annual operating income associated with this contract will range between $40 million to $55 million. The primary driver of this improvement is the adjustment to the price of steam supplied to Lyondell
Chemical. In addition, we retain our ability to capture market upside in the Texas region for the excess generation from the Cogen Lyondell facility.

Our peaking facilities in the South continue to contribute revenue from sales of capacity mainly to local load-serving entities or wholesale buyers. We currently have a substantial portion of our portfolio capacity
committed on an annual basis through 2015. Where we have uncommitted capacity and energy, we believe opportunities to sell additional capacity from these facilities will develop at times during the year. Due to the regulated, non-liquid market
available in this region, our results will be impacted by our ability to complete additional sales to a limited pool of buyers for these products.

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



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Cash Flow Disclosures

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



|                                                                |  |                          |      |   |      |   |      |  
|--------------------------------------------------------------- |  | ------------------------ | ---- | - | ---- | - | ---- | -
|                                                                |  | Quarters Ended March 31, |     
|                                                                |  | 2006                     |      |   | 2005 |  
|                                                                |  | (in millions)            |     
|Operating cash flows from our generation businesses             |  | $                        | 193  |   |      | $ | 81   |  
|Operating cash flows from our customer risk management business |  |                          | (387 | ) |      |   | (33  | )
|Operating cash flows from our natural gas liquids business      |  |                          |     |   |      |   | 69   |  
|Other operating cash flows                                      |  |                          | (147 | ) |      |   | (158 | )
|                                                                |  |                          |      |   |      |   |      |  
|Net cash used in operating activities                           |  | $                        | (341 | ) |      | $ | (41  | )
|                                                                |  |                          |      |   |      |   |      |  

Operating Cash Flow. Our cash flow used in operations totaled $341 million for the
quarter ended March 31, 2006. During the quarter, our power generation business provided positive cash flow from operations of $193 million due to positive earnings for the period and changes in working capital primarily due to return of
collateral. Our customer risk management business used approximately $387 million in cash primarily due to a $370 million termination payment on our Sterlington tolling contract, offset by other changes in working capital. Please read Note 3-
Dispositions, Contract Terminations and Discontinued Operations- Dispositions and Contract TerminationsSterlington Contract Termination for further information. Other and Eliminations includes a use of approximately $147 million in cash
primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances.

Our cash flow used in operations totaled $41 million for the quarter ended March 31, 2005. During the quarter, our power generation business and natural gas liquids business provided positive cash flow from operations. Our power
generation business provided cash flow from operations of $81 million due to positive earnings for the period; and our natural gas liquids business provided cash flow from operations of $69 million primarily due to positive earnings for the period.
Our customer risk management business segment used approximately $33 million in cash primarily due to fixed payments associated with the power tolling arrangements and our final payment related to our exit from gas transportation contracts. Other
and eliminations includes a use of approximately $158 million in cash primarily due to interest payments to service debt and general and administrative expenses.

Capital Expenditures and Investing Activities. Cash provided by investing activities during the quarter ended March 31, 2006 totaled $483 million. Capital spending of $18 million was primarily
comprised of $11 million, $3 million, and $3 million in the GEN-MW, GEN-NE, and GEN-SO segments, respectively. The capital spending for the GEN-MW segment primarily related to maintenance capital projects, as well as $1 million in development
capital associated with the completion of the Vermilion PRB conversion. Capital spending in our GEN-NE and GEN-SO segments primarily related to maintenance and environmental projects.

The cost to acquire NRGs 50% ownership interest in Rocky Road, net of cash proceeds, totaled $40 million. Please read Note 2- Acquisition for more
information. The decrease in restricted cash related to the return of our $335 million deposit associated with our former cash collateralized facility.

Net cash proceeds from asset sales of $205 million was due to the sale of our 50% ownership interest in West Coast Power to NRG. Please read Note 3- Dispositions, Contract Terminations and Discontinued Operations-
Dispositions and Contract TerminationsWest Coast Power for further information.

Cash used in investing activities during the quarter
ended March 31, 2005 totaled $69 million. Capital spending of $54 million was primarily comprised of $37 million, $3 million and $10 million in the GEN-MW, GEN-NE and NGL segments, respectively. The capital spending for the GEN-MW segment
primarily related to maintenance capital projects, as well as $10 million in development capital associated with the completion of the Havana PRB conversion. Capital spending in our NGL segment primarily related to maintenance capital projects and
wellconnects.



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Financing Activities. Cash used in financing activities during the quarter ended
March 31, 2006 totaled $128 million, primarily due to a $120 million repayment of borrowings from Dynegy.

Cash provided by financing
activities during the quarter ended March 31, 2005 totaled $33 million. Repayments of long-term debt totaled $19 million for the three months ended March 31, 2005 and consisted of the following: (1) payments of $18 million on a
maturing series of our senior notes; and (2) payments of $1 million on our May 2004 term loan. Borrowings from affiliates totaled $50 million related to our cash received from Dynegy to fund our operational needs.

RISK-MANAGEMENT DISCLOSURES

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



|                                                                                 |  |                                                |      |  
|-------------------------------------------------------------------------------- |  | ---------------------------------------------- | ---- | -
|                                                                                 |  | As of and for the Quarter Ended March 31,
2006 |     
|                                                                                 |  | (in millions)                                  |     
|Balance Sheet Risk-Management Accounts                                           |  |                                                |      |  
|Fair value of portfolio at January 1, 2006                                       |  | $                                              | (131 | )
|Risk-management gains recognized through the income statement in the period, net |  |                                                | 56   |  
|Cash received related to risk-management contracts settled in the period, net    |  |                                                | (2   | )
|Changes in fair value as a result of a change in valuation technique (1)         |  |                                                |     |  
|Non-cash adjustments and other (2)                                               |  |                                                | 11   |  
|                                                                                 |  |                                                |      |  
|Fair value of portfolio at March 31, 2006                                        |  | $                                              | (66  | )
|                                                                                 |  |                                                |      |  

---

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

|(2) | This amount consists of changes in value associated with cash flow hedges on forward power sales and fair value hedges on debt.
|--- | -------------------------------------------------------------------------------------------------------------------------------

The net risk management liability of $66 million is the aggregate of the following line items on our condensed consolidated balance sheets: Current
AssetsAssets from risk-management activities, Other AssetsAssets from risk-management activities, Current LiabilitiesLiabilities from risk-management activities and Other LiabilitiesLiabilities from risk-management
activities.

Risk-Management Asset and Liability Disclosures. The following tables depict the mark-to-market value and cash
flow components of our net risk-management assets and liabilities at March 31, 2006 and December 31, 2005. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in
periods other than those depicted below:

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



|                  |  |               |      |   |         |   |     |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |   
|----------------- |  | ------------- | ---- | - | ------- | - | --- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | ---------- | - |  | - | - |  | - | --
|                  |  | Total         |      |   | 2006(2) |   |     | 2007 |  |   | 2008 |   |  | 2009 |     |   | 2010 |   | Thereafter
|                  |  | (in millions)
|March 31, 2006    |  | $             | (32  | ) |         | $ | 1   |      |  | $ | (52  | ) |  | $    | (8  | ) |      | $ | 1          |   |  | $ | 3 |  | $ | 23
|December 31, 2005 |  |               | (103 | ) |         |   | (16 | )    |  |   | (73  | ) |  |      | (29 | ) |      |   | (2         | ) |  |   |  |  |   | 17
|                  |  |               |      |   |         |   |     |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |   
|Increase          |  | $             | 71   |   |         | $ | 17  |      |  | $ | 21   |   |  | $    | 21  |   |      | $ | 3          |   |  | $ | 3 |  | $ | 6 
|                  |  |               |      |   |         |   |     |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |   

---

|(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 March 31, 2006 of
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

$66 million on the unaudited condensed consolidated balance sheets include the $32 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 April 1 to December 31, 2006 values in the March 31, 2006 row and January 1 to December 31, 2005 values in the December 31, 2005 row.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------

Cash Flow Components of Net Risk-Management Asset



|                   |  |                                   |    |                                    |   |            |  |   |      |   |  |      |     |   |      |   |     |      |  |            |    |   |  |   |   |  |   |   
|------------------ |  | --------------------------------- | -- | ---------------------------------- | - | ---------- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---- |  | ---------- | -- | - |  | - | - |  | - | --
|                   |  | Three Months Ended March 31,
2006 |    | Nine Months EndedDecember 31, 2006 |   | Total 2006 |  |   | 2007 |   |  | 2008 |     |   | 2009 |   |     | 2010 |  | Thereafter
|                   |  | (in millions)                    
|March 31, 2006 (1) |  | $                                 | 11 |                                    | $ | 5          |  | $ | 16   |   |  | $    | (50 | ) |      | $ | (9  | )    |  | $          | 1  |   |  | $ | 4 |  | $ | 33
|December 31, 2005  |  |                                   |    |                                    |   |            |  |   | (10  | ) |  |      | (72 | ) |      |   | (33 | )    |  |            | (3 | ) |  |   |  |  |   | 24
|                   |  |                                   |    |                                    |   |            |  |   |      |   |  |      |     |   |      |   |     |      |  |            |    |   |  |   |   |  |   |   
|Increase           |  |                                   |    |                                    |   |            |  | $ | 26   |   |  | $    | 22  |   |      | $ | 24  |      |  | $          | 4  |   |  | $ | 4 |  | $ | 9 
|                   |  |                                   |    |                                    |   |            |  |   |      |   |  |      |     |   |      |   |     |      |  |            |    |   |  |   |   |  |   |   

---

|(1) | The cash flow values for 2006 reflect realized cash flows for the three months ended March 31, 2006 and anticipated undiscounted cash inflows and outflows by contract based on
the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative
instruments designated as hedges.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The following table provides an assessment of net contract values by year as of
March 31, 2006, based on our valuation methodology.

Net Fair Value of Risk-Management Portfolio



|                       |  |               |     |   |      |   |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |   
|---------------------- |  | ------------- | --- | - | ---- | - | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | ---------- | - |  | - | - |  | - | --
|                       |  | Total         |     |   | 2006 |   | 2007 |  |   | 2008 |   |  | 2009 |     |   | 2010 |   | Thereafter
|                       |  | (in millions)
|Market Quotations (1)  |  | $             | (66 | ) |      | $ | 1    |  | $ | (52  | ) |  | $    | (21 | ) |      | $ | 2          |   |  | $ |  |  | $ | 4 
|Prices Based on Models |  |               | 34  |   |      |   |     |  |   |     |   |  |      | 13  |   |      |   | (1         | ) |  |   | 3 |  |   | 19
|                       |  |               |     |   |      |   |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |   
|Total                  |  | $             | (32 | ) |      | $ | 1    |  | $ | (52  | ) |  | $    | (8  | ) |      | $ | 1          |   |  | $ | 3 |  | $ | 23
|                       |  |               |     |   |      |   |      |  |   |      |   |  |      |     |   |      |   |            |   |  |   |   |  |   |   

---

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

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as
forward-looking statements. All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect,
believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown
risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to
historical or current facts. They use words such as anticipate, estimate, project, forecast, plan, may, will, should, expect and other words
of similar meaning. In particular, these include, but are not limited to, statements relating to the following:



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



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



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| |  |  | beliefs about commodity pricing;
| | - |  | --------------------------------



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



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



| |  |  | beliefs and assumptions relating to our liquidity position, including our ability to redeem the remaining outstanding 2008 Notes and to satisfy or refinance our significant debt
maturities and other obligations before or as they come due;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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



| |  |  | sufficiency of coal and fuel oil inventories and transportation;
| | - |  | ----------------------------------------------------------------



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



| |  |  | assumptions about prospective regulatory developments;
| | - |  | ------------------------------------------------------



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



| |  |  | strategies to remediate the material weakness existing in our accounting for income taxes:
| | - |  | ------------------------------------------------------------------------------------------



| |  |  | application of the remaining proceeds from the sale of our midstream natural gas business;
| | - |  | ------------------------------------------------------------------------------------------



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



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

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and
other factors, many of which are beyond our control, including those set forth under Part IIOther Information, Item 1ARISK FACTORS.

RECENT ACCOUNTING PRONOUNCEMENTS

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

CRITICAL ACCOUNTING POLICIES

Please read Critical Accounting Policies beginning on page 69 of our Form 10-K for a complete description of our critical accounting policies,
with respect to which there have been no material changes since the filing of our Form 10-K.

Item 3QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A.
Quantitative and Qualitative Disclosures About Market Risk beginning on page 75 of our Form 10-K for a discussion of our exposure to commodity price variability and other markets risks, including foreign currency exchange rate risk. Following is a
discussion of the more material of these risks and our relative exposures as of March 31, 2006.



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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 Portfolios



|                                                             |  |               |    |                  |   |   
|------------------------------------------------------------ |  | ------------- | -- | ---------------- | - | --
|                                                             |  | March 31,2006 |    | December 31,2005
|                                                             |  | (in millions)
|One Day VaR95% Confidence Level                             |  | $             | 6  |                  | $ | 5 
|One Day VaR99% Confidence Level                             |  | $             | 8  |                  | $ | 7 
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $             | 11 |                  | $ | 11

Credit Risk. The following table represents our credit exposure at March 31,
2006 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary



|                                |  |                         |     |                              |   |       |  |   |    
|------------------------------- |  | ----------------------- | --- | ---------------------------- | - | ----- |  | - | ---
|                                |  | InvestmentGrade Quality |     | Non-Investment Grade Quality |   | Total
|                                |  | (in millions)          
|Type of Business:               |  |                         |     |                              |   |       |  |   |    
|Financial Institutions          |  | $                       | 136 |                              | $ |      |  | $ | 136
|Commercial/Industrial/End Users |  |                         | 32  |                              |   | 18    |  |   | 50 
|Utility and Power Generators    |  |                         | 5   |                              |   | 11    |  |   | 16 
|                                |  |                         |     |                              |   |       |  |   |    
|Total                           |  | $                       | 173 |                              | $ | 29    |  | $ | 202
|                                |  |                         |     |                              |   |       |  |   |    

Of the $29 million in credit exposure to non-investment grade counterparties, 44% is
collateralized or subject to other credit exposure protection.

Interest Rate Risk. We are exposed to fluctuating interest
rates related to variable rate financial obligations. As of March 31, 2006, our fixed rate debt instruments as a percentage of total debt instruments was approximately 82%. Based on sensitivity analysis of the variable rate financial
obligations in our debt portfolio as of March 31, 2006, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended March 31, 2007 would either
decrease or increase income before taxes by approximately $8 million. Hedging instruments that impact such interest rate exposure are included in the sensitivity analysis. Over time, we may seek to reduce the percentage of fixed rate financial
obligations in our debt portfolio through the use of swaps or other financial instruments.



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

Absolute Notional Contract Amounts



|                                                                         |  |                |        |                  |   |       
|------------------------------------------------------------------------ |  | -------------- | ------ | ---------------- | - | ------
|                                                                         |  | March 31, 2006 |        | December 31,2005
|Natural Gas (Trillion Cubic Feet)                                        |  |                | 0.440  |                  |   | 0.374 
|Electricity (Million Megawatt Hours) (1)                                 |  |                | 25.495 |                  |   | 30.479
|Emission Credits (Million Tons) (2)                                      |  |                | 0.031  |                  |   | 0.043 
|Net Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)   |  | $              | 525    |                  | $ | 525   
|Fixed Interest Rate Received on Swaps (Percent)                          |  |                | 4.331  |                  |   | 4.331 
|Net Interest Rate Risk-Management Contract (In Millions of U.S. Dollars) |  | $              | 25     |                  | $ | 25    
|Fixed Interest Rate Paid (Percent)                                       |  |                | 5.998  |                  |   | 5.998 

---

|(1) | This amount includes notional volumes related to Financial Transmission Rights (FTRs) that we acquired in various ISOs during 2005.
|--- | -----------------------------------------------------------------------------------------------------------------------------------

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

Item 4CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation
of our management and the management of Dynegy, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprises disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of Dynegys disclosure committee in an effort to ensure that information required
to be disclosed in the consolidated entitys SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the first quarter 2006
relating to our participation in Dynegys compliance with Section 404 of the Sarbanes-Oxley Act of 2002.

Based on this
evaluation, our CEO and CFO concluded that, as of March 31, 2006, as a result of the material weaknesses discussed below, our disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our
SEC reports is recorded, processed, summarized and reported within the requisite time periods.

Notwithstanding the material weaknesses
that existed at March 31, 2006, management believes, based on its knowledge, that the financial statements, and other financial information included in this report, fairly present in all material respects in accordance with GAAP our
financial condition, results of operations and cash flows as of, and for, the periods presented in this report.

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

Material Weakness Related to Income Taxes.As of December 31, 2005 and March 31, 2006, we did
not maintain effective controls over the completeness and accuracy of the tax provision and deferred income tax balances in accordance with generally accepted accounting principles. Specifically, our processes, procedures and controls related to the
preparation, analysis and recording of the income tax provision were not effective to ensure



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that the deferred tax provision and deferred tax balances were recorded in accordance with generally accepted accounting
principles. This control deficiency resulted in the restatement of our 2004 and 2003 annual consolidated financial statements, as well as audit adjustments to the 2005 income tax provision. Further, this control deficiency could result in a
misstatement of the income tax provision and related deferred tax accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Therefore, as
of December 31, 2005 and March 31, 2006, we concluded that this control deficiency constitutes a material weakness.

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

Status of Remediation of Material Weaknesses

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

In addition to continuing the enhanced processes implemented in 2005 and described above, during 2006, we have already taken or plan to take the
following steps in an attempt to remediate the material weakness reported at December 31, 2005: (i) implementing new processes around the analysis of the income tax provision, including detailed reconciliations between book basis and tax
basis of significant tax sensitive balance sheet accounts; (ii) implementing additional procedures around identifying, analyzing and recording the tax effects of significant transactions; and (iii) further formalizing and documenting the
procedures around the preparation and review of the tax provision and tax accounts. Dynegy has also engaged an independent consulting firm to assess and provide recommendations to strengthen our current processes and procedures. We will not be able
to conclude that this material weakness has been successfully remediated, and we cannot assure you we will be able to make such conclusion, until managements testing and assessment demonstrates that such controls have operated effectively for
a sufficient period of time.

We believe we are taking the steps necessary to remediate this material weakness relating to our tax
accounting and tax reconciliation processes, procedures and controls. However, certain of the corrective processes, procedures and controls relate to annual controls that cannot be tested until the preparation of our 2006 annual tax provision.
Accordingly, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further changes management determines are necessary.

Material Weakness Related to Risk Management Assets and Liabilities.In order to remediate this material weakness, we will implement
additional controls around our risk management asset and liability valuation process, including enhanced controls and management review and approvals of price-validation process changes and system-generated controls.

Changes in Internal Controls Over Financial Reporting. Other than as noted above in this Item 4, there were no changes in our internal
control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under



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the Exchange Act) identified in connection with the evaluation of our internal controls performed during the last fiscal
quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



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DYNEGY HOLDINGS 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 1ARISK FACTORS

Item 1A. Risk Factors beginning on page 20 of our 2005 Form 10-K
includes a detailed discussion of our risk factors. The information presented below updates, and should be read in conjunction with, the risk factors and information disclosed in our 2005 Form 10-K.

Risks Related to Our Business

We reported a material weakness
in our internal control over financial reporting that caused a restatement and, if not remedied, it could continue to adversely affect our internal controls and financial reporting.

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

In connection with managements
assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, management concluded that, as of December 31, 2005, we did not maintain effective internal control over our financial reporting due
to a material weakness in our processes, procedures and controls related to the preparation, analysis and recording of the income tax provision. Our managements assessment of the effectiveness of our internal control over financial reporting
as of December 31, 2005 was audited by PricewaterhouseCoopers LLP, which expressed an unqualified opinion on managements assessment and an adverse opinion on the effectiveness of our internal control over financial reporting as of
December 31, 2005.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a
remote likelihood that a material misstatement of our annual or interim financial statements would not be prevented or detected. We previously reported in our 2004 Form 10-K that we did not maintain effective internal control over financial
reporting as of December 31, 2004 due to the same material weakness discussed above. During 2005, actions were taken to remediate the material weakness reported in our 2004 Form 10-K. Despite these efforts, when making managements
assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, we determined that those controls were still not operating effectively.

This control deficiency resulted in the restatement of our 2004 and 2003 annual consolidated financial statements, as well as year-end audit adjustments
to the 2005 income tax provision. Further, this control deficiency could have resulted in a misstatement of the income tax provision and related deferred tax accounts and disclosures that would result in a material misstatement to the annual or
interim consolidated financial statements that would not be prevented or detected.

We have taken steps to remediate the material weakness,
and plan to take additional steps during 2006. Although we believe we will address the material weakness with the remedial measures we have implemented and plan to implement, the measures we have taken to date and any future measures may not
remediate the material weakness reported and we may not be able to implement and maintain effective internal control over financial reporting in the future. In addition, additional deficiencies in our internal controls may be discovered in the
future. Any failure to remediate the reported material weakness or to implement new or improved controls, or difficulties encountered in their implementation, could harm our operating results, cause us to fail to meet our reporting



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obligations or result in material misstatements in our financial statements. Any such failure also could affect the
ability of our management to certify that our internal controls are effective when it provides an assessment of our internal control over financial reporting, and could affect the results of our independent registered public accounting firms
attestation report regarding our managements assessment. Inferior internal controls and further related restatements could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the
trading price of our stock.

Our growth strategy may include acquisitions or combinations that could fail or present unanticipated problems for our
business in the future, which could adversely affect our ability to realize anticipated benefits of those transactions.

Our growth
strategy may include acquiring or combining with other businesses. We may not be able to identify suitable acquisition or combination opportunities or finance and complete any particular acquisition or combination successfully. Furthermore,
acquisitions and combinations involve a number of risks and challenges, including:



| |  |  | diversion of managements attention;
| | - |  | ------------------------------------



| |  |  | the need to integrate acquired or combined operations;
| | - |  | ------------------------------------------------------



| |  |  | potential loss of key employees;
| | - |  | --------------------------------



| |  |  | difficulty in evaluating the power assets, operating costs, infrastructure requirements, environmental and other liabilities, and other factors beyond our control;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | potential lack of operating experience in new geographic/power markets;
| | - |  | -----------------------------------------------------------------------



| |  |  | an increase in our expenses and working capital requirements; and
| | - |  | -----------------------------------------------------------------



| |  |  | the possibility that we may be required incur additional debt to finance any such transactions.
| | - |  | -----------------------------------------------------------------------------------------------

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize synergies or other anticipated benefits
from a strategic transaction.

Furthermore, while we intend to pursue strategic transactions, the market for transactions is highly
competitive, which may adversely affect our ability to find transactions that fit our strategic objectives. In pursuing our strategy, consistent with industry practice, we routinely engage in discussions with industry participants regarding
potential transactions, large and small. We are currently engaged in discussions, although no definitive agreements have been reached. We intend to continue to engage in strategic discussions and we will need to respond to potential opportunities
quickly and decisively. As a result, strategic transactions may occur at anytime and may be significant in size relative to our assets and operations.



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Risks Related to Investing in Dynegys Common Stock

We have significant debt that could negatively impact our business.

Dynegy has and will continue to have a significant amount of debt outstanding. As of May 4, 2006, we had total consolidated debt (including lease obligations) of $3.4 billion, which consisted of our senior
unsecured notes and other debt, including other secured and unsecured facilities and certain operating leases of our subsidiaries. Our significant level of debt could:



| |  |  | make it difficult to satisfy our financial obligations, including debt service requirements;
| | - |  | --------------------------------------------------------------------------------------------



| |  |  | limit our ability to obtain additional financing to operate our business;
| | - |  | -------------------------------------------------------------------------



| |  |  | limit our financial flexibility in planning for and reacting to business and industry changes;
| | - |  | ----------------------------------------------------------------------------------------------



| |  |  | impact the evaluation of our creditworthiness by counterparties to commercial agreements and affect the level of collateral we are required to post under such agreements;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | place us at a competitive disadvantage compared to less leveraged companies;
| | - |  | ----------------------------------------------------------------------------



| |  |  | increase our vulnerability to general adverse economic and industry conditions, including changes in interest rates and volatility in commodity prices; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | require us to dedicate a substantial portion of our cash flows to payments on our debt, thereby reducing the availability of our cash flow for other purposes including our
operations, capital expenditures and future business opportunities.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Although we recently completed a series of liability
management transactions, we remain highly leveraged. Furthermore, we may incur additional indebtedness in the future. If new debt is added to our current debt levels and those of our subsidiaries, the related risks that we and they face could
increase significantly.

The terms of our debt may severely limit our ability to plan for or respond to changes in our businesses.

Our secured debt obligations require us to meet specific financial tests to issue debt and make restricted payments, among other
things. Further, the senior debt associated with the Sithe Independence indenture prohibits cash distributions by Independence to its affiliates, including Dynegy, unless certain project reserve accounts are funded to specified levels and the
required debt service coverage ratio is met. Our ability to comply with the covenants in our financing agreements, as they currently exist or as they may be amended, may be affected by many events beyond our control, and our future operating results
may not allow us to comply with the covenants, or in the event of a default, to remedy that default. Our failure to comply with those financial covenants or to comply with the other restrictions in our financing agreements could result in a default,
requiring such financing agreements (and by reason of cross-default or cross-acceleration provisions, our other indebtedness) to become immediately due and payable. If we are unable to repay those amounts or to otherwise cure the default, the
holders of the indebtedness under our secured debt obligations could proceed against the collateral granted to them to secure that indebtedness. If those lenders accelerate the payment of such indebtedness, we cannot assure you that we could pay or
refinance that indebtedness immediately and continue to operate our business.



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The ultimate outcome of unresolved legal proceedings and investigations relating to our past activities cannot be
predicted. Any adverse determination could have a material adverse effect on our financial condition, results of operations and cash flows.

We are, or have in recent years been, a party to various material litigation matters and regulatory matters arising out of our business operations. These matters include, among other things, certain actions and investigations by the FERC
and related regulatory bodies, litigation with respect to alleged actions in the western power and natural gas markets, a number of securities class action lawsuits that were settled in 2005, purported class action suits with respect to alleged
violations of the Employment Retirement Income Security Act and various other matters. The ultimate outcome of pending matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome in each case
reasonably be estimated. Three significant matters are described below:

DNE is involved in litigation or administrative proceedings
regarding the State Pollutant Discharge Elimination System, or SPDES, permits for two of our facilities, Roseton and Danskammer, in New York. In April 2005, the New York State Department of Environmental Conservation, or NYSDEC, issued to DNE a
draft SPDES Permit for the Roseton plant. The draft SPDES Permit contains provisions governing, among other things, the cooling water intake and the discharge of heated effluent water. In mid- 2005, three organizations filed petitions for party
status seeking to impose a permit requirement that the Roseton plant install a closed cycle cooling system. We believe that Petitioners claims are without merit; however, given the high cost of installing a closed cycle cooling system, an
adverse result in this proceeding could have a material adverse effect on our financial condition, results of operations and cash flows.

Danskammers SPDES Permit was issued for a five-year term in 1987. Prior to expiration of the permit, an application to renew the SPDES Permit was filed. In November 2002, several environmental groups filed suit in the Supreme Court of
the State of New York seeking, among other things, a declaratory judgment that the Danskammer SPDES Permit had expired because of alleged deficiencies in the renewal application process. In August 2004, the Court ruled that the SPDES Permit for our
Danskammer facility was void, but stayed the enforcement of the decision pending further review by the Court or by the Appellate Division. In April 2006, the Appellate Division reversed the trial court and dismissed the case. The Court ruled that
the environmental groups challenges to the extension of the SPDES Permit were barred by the applicable statue of limitations. If Petitioners appeal and are ultimately successful, we may be required to suspend operations at our Danskammer
facility until receipt of final approval of the renewal of our Danskammer SPDES Permit. We cannot predict with any certainty the outcome of this proceeding; however, an adverse outcome, particularly a requirement that we suspend operations at our
Danskammer facility for any period of time, could have a material adverse effect on our financial condition, results of operations and cash flows.

We and/or Dynegy are a party to various suits that claim damages resulting from the alleged manipulation of gas index publications and prices by us and others. In each of these suits, the plaintiffs allege that we and/or Dynegy and other
energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to gas index publications. All of the complaints rely heavily on the FERC and CFTC investigations into and reports concerning index-reporting
manipulation in the energy industry. We cannot predict with certainty whether we will incur any liability in connection with these lawsuits; however, given the nature of the claims and the high costs of recent settlements of similar matters, an
unfavorable result in any of these pending matters could materially adversely affect our financial condition, results of operations and cash flows.

Shortly before Enrons bankruptcy filing in the fourth quarter of 2001, we determined that we had net exposure to Enron Corp. and its affiliates, including certain liquidated damages and other amounts relating to the termination of
commercial transactions among the parties, of approximately $84 million. This exposure was calculated by setting off approximately $230 million owed from Dynegy entities to Enron entities against approximately $314 million owed from Enron entities
to Dynegy entities. The master netting agreement between Enron and Dynegy 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. We previously mediated this dispute but no settlement was reached. As a result, in April 2006, Enron requested that mediation be terminated; the mediator has recommended that the case be returned to the Bankruptcy
Court. In the



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event that Enron prevails in its position that the master netting agreement is unenforceable, our potential liability to
Enron could be approximately $216 million before interest, with as much as $220 million in unsecured Dynegy claims remaining to enforce against the bankruptcy estate. If the setoff rights are modified or disallowed, either by agreement or otherwise,
the amount available for our entities to set off against sums that might be due Enron entities could be reduced materially. In fact, we could be required to pay to Enron the full amount that it claims to be owed, while we would be an unsecured
creditor of Enron to the extent of our claims. Given the size of the claims at issue, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.

Item 6EXHIBITS

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



|               |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|-------------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit Number |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|               | 
|4.1            |  | Second Supplemental Indenture, dated as of March 28, 2006, by and among Dynegy Holdings Inc., the guarantors party thereto, Wilmington Trust Company, as trustee, and Wells Fargo Bank, N.A.,
as collateral trustee, supplementing the Indenture, dated as of August 11, 2003 (as supplemented by the Supplemental Indenture, dated as of August 24, 2005), pursuant to which the Second Priority Senior Secured Floating Rate Notes due
2008, 9.875% Second Priority Senior Secured Notes due 2010 and 10.125% Second Priority Senior Secured Notes due 2013 of Dynegy Holdings Inc. were issued (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on March 29,
2006, File No. 1-15659).
|               | 
|4.2            |  | Second Supplemental Indenture, dated as of April 12, 2006, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of
March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003 (incorporated by
reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 12, 2006, File No. 1-15659).                                                                                                                                                   
|               | 
|4.3            |  | Registration Rights Agreement, dated as of April 12, 2006, by and among Dynegy Holdings Inc. and the several initial purchasers party thereto (incorporated by reference to Exhibit 4.2 to the
Current Report on Form 8-K of Dynegy Inc. filed on April 12, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                                     
|               | 
|10.1           |  | Third Amended and Restated Credit Agreement dated as of March 6, 2006 among Dynegy Holdings Inc., as Borrower, and Dynegy Inc., as Parent Guarantor (incorporated by reference to Exhibit
10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 9, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                               
|               | 
|10.2           |  | Agreement Concerning Employment Agreement and Stock Options dated as of March 16, 2006 between Dynegy Inc. and Bruce A. Williamson (incorporated by reference to Exhibit 10.1 to the Current
Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                                               
|               | 
|10.3           |  | Third Amendment to October 18, 2002 Employment Agreement dated as of March 16, 2006 between Dynegy Inc. and Bruce A. Williamson (incorporated by reference to Exhibit 10.2 to the Current Report
on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                                                  



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|       |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|------ |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.4   |  | Non-Qualified Stock Option Award Agreement dated as of March 16, 2006, between Dynegy Inc., all of its subsidiaries and Bruce A. Williamson (incorporated by reference to Exhibit 10.3 to
the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                      
|       | 
|10.5   |  | Form of Performance Award Agreement (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|       | 
|10.6   |  | Amendment to the Dynegy Inc. 2000 Long Term Incentive Plan effective January 1, 2006 (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March
17, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                             
|       | 
|10.7   |  | Amendment to the Dynegy Inc. 2002 Long Term Incentive Plan effective January 1, 2006 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on March
17, 2006, File No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                             
|       | 
|10.8   |  | Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No.
1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                                               
|       | 
|10.9   |  | Form of Restricted Stock Award Agreement (Managing Directors and Above) (incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File
No. 1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                          
|       | 
|10.10  |  | Form of Restricted Stock Award Agreement (Directors and Below) (incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No.
1-15659).                                                                                                                                                                                                                                                                                                                                                                                                                                   
|       | 
|10.11  |  | Purchase Agreement dated as of March 29, 2006 for the sale of $750,000,000 aggregate principal amount of the 8.375% Senior Unsecured Notes due 2016 of Dynegy Holdings, Inc. among Dynegy Holdings
Inc. and the several initial purchasers named therein (incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on May 10, 2006, File No. 1-15659).                                                                                                                                                                                                                                       
|       | 
|10.12  |  | Second Lien Shared Security Agreement Supplement dated as of August 24, 2005 by Dynegy Midstream Holdings, Inc., Dynegy Storage Technology and Services, Inc. and Dynegy Gas Transportation, Inc.
in favor of Wells Fargo Bank, N.A., as collateral trustee (supplementing the Second Lien Shared Security Agreement dated August 11, 2003 among Dynegy Holdings Inc., Dynegy Inc., as a grantor, the other grantors named therein and Wells Fargo Bank
Minnesota, N.A., as collateral trustee) (incorporated by reference to Exhibit 10.12 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on May 10, 2006, File No. 1-15659).
|       | 
|10.13  |  | Fourth Amended and Restated Credit Agreement dated as of April 19, 2006 among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, the other guarantors party thereto, the lenders
party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 20, 2006, File No. 1-15659).                                                                                                                                                                                                                                               
|       | 
|**31.1 |  | Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    



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|       |  |                                                                                                                                                            
|------ |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------
|**31.2 |  | Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.      
|       | 
|32.1  |  | Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|       | 
|32.2  |  | Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

---

|** | Filed herewith
|-- | --------------

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



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DYNEGY HOLDINGS INC.

SIGNATURES

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



|                   |  |     |  |                                                                                                                                
|------------------ |  | --- |  | -------------------------------------------------------------------------------------------------------------------------------
|                   |  |     |  | DYNEGY HOLDINGS INC.                                                                                                           
|                   |  |    
|Date: May 12, 2006 |  | By: |  | /s/ HOLLI C. NICHOLS                                                                                                           
|                   |  |     |  | Holli C. Nichols Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal
Financial Officer)



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