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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-K



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



For the fiscal year ended December 31, 2004



| ̈ | 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)



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



1000 Louisiana,
Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)



(713) 507-6400

(Registrants telephone number, including area code)



Securities registered pursuant to Section 12(b) of the Act:



|                    |  |                                          
|------------------- |  | -----------------------------------------
|Title of each class |  | Name of each exchange on which registered
|None                |  |                                         



Securities
registered pursuant to Section 12(g) of the Act:



|                    |  |                                          
|------------------- |  | -----------------------------------------
|Title of each class |  | Name of each exchange on which registered
|None                |  |                                         



All outstanding equity
securities of Dynegy Holdings Inc. are held by its parent, Dynegy Inc.



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 the filing requirements for the past 90 days.    Yes  þ    No ̈



Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ



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



DOCUMENTS INCORPORATED BY REFERENCE. None.



REDUCED DISCLOSURE FORMAT.Dynegy Holdings Inc. meets the conditions
set forth in General Instruction (I) (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

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DYNEGY HOLDINGS INC. FORM 10-K

INTRODUCTORY NOTE



This Form 10-K reflects the effect of a $6 million increase to our deferred tax liability at December 31, 2003, as well as increases to income tax expense in periods prior to 2004, related to errors in our previously
completed tax basis balance sheet review, on our historical consolidated financial statements and related information, as reported in Amendment No. 1 to our Annual Report of Form 10-K for the year ended December 31, 2003, which was filed on January
25, 2005.



Although this item was not considered material to
the periods to which it related, this item is material to our 2004 results. We are required to restate prior periods in accordance with APB 20, Accounting Changes. The item is discussed in more detail in the Explanatory Note to the
accompanying consolidated financial statements beginning on page F-8. The following Items of our Form 10-K for the year ended December 31, 2003, as amended by Amendment No. 1, are affected by these items:



Item 6. Selected Financial Data



Item 7. Managements Discussion and Analysis of Financial Condition and Results of
Operations



Item 8. Financial Statements and Supplementary Data



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DYNEGY HO
LDINGS INC.

FORM 10-K



TABLE OF CONTENTS



|            |  |                                                                                                             |  |     
|----------- |  | ----------------------------------------------------------------------------------------------------------- |  | ----
|            |  |                                                                                                             |  | Page
|            |  | PART I                                                                                                      |  |     
|Definitions |  | 1                                                                                                          
|Item   1.   |  | Business                                                                                                    |  | 1   
|Item 2.     |  | Properties                                                                                                  |  | 26  
|Item 3.     |  | Legal Proceedings                                                                                           |  | 27  
|Item 4.     |  | Submission of Matters to a Vote of Security Holders                                                         |  | 27  
|            |  |                                                                                                            
|            |  | PART II                                                                                                     |  |     
|Item 5.     |  | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities |  | 27  
|Item 6.     |  | Selected Financial Data                                                                                     |  | 27  
|Item 7.     |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                       |  | 29  
|Item   7A.  |  | Quantitativeand Qualitative Disclosures About Market Risk                                                   |  | 70  
|Item 8.     |  | Financial Statements and Supplementary Data                                                                 |  | 73  
|Item 9.     |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                        |  | 73  
|Item 9A.    |  | Controls and Procedures                                                                                     |  | 73  
|Item 9B.    |  | Other Information                                                                                           |  | 75  
|            |  |                                                                                                            
|            |  | PART III                                                                                                    |  |     
|Item 10.    |  | Directors and Executive Officers of the Registrant                                                          |  | 76  
|Item 11.    |  | Executive Compensation                                                                                      |  | 76  
|Item 12.    |  | Security Ownership of Certain Beneficial Owners and Management                                              |  | 76  
|Item 13.    |  | Certain Relationships and Related Transactions                                                              |  | 76  
|Item 14.    |  | Principal Accountant Fees and Services                                                                      |  | 76  
|            |  |                                                                                                            
|            |  | PART IV                                                                                                     |  |     
|Item 15.    |  | Exhibits, Financial Statement Schedules                                                                     |  | 77  
|Signatures  |  | 85                                                                                                         



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PART I



DEFINITIONS



As used in this Form
10-K, the abbreviations contained herein have the meanings set forth in the glossary beginning on page F-71. 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.



|Item 1. | Business
|------- | --------



THE COMPANY



We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused
primarily in two areas of the energy industry: power generation and natural gas liquids.



During 2004, we made substantial progress toward the completion of our efforts to restructure our company to align more closely our asset base with our business strategy. Our significant accomplishments during this
period include the replacement of our $1.1 billion credit facility with a new $1.3 billion credit facility, the restructuring of our Kendall tolling arrangements, Dynegys restructuring of our Independence tolling arrangement, the termination
of four long-term natural gas transportation agreements, sales of non-core GEN and NGL assets generating approximately $246 million in proceeds and the pre-payment of the ABG Gas Supply financing.



We also continued our exit from the customer risk management business.
Collateral to support our CRM business declined 22% from $121 million at the end of 2003 to $94 million at the end of 2004, primarily due to termination of the ABG Gas Supply contract. Our remaining customer risk management business, which primarily
consists of our four remaining power tolling arrangements (including the Gregory toll, which expires in July 2005) as well as our gas transportation agreements and legacy power and gas trading positions, will continue to impact negatively our cash
flows and operating results until the associated obligations have been terminated, restructured or satisfied.



With only a few significant legacy matters remaining to be addressed, more of our companys resources are available to continue our efforts to
operate our energy businesses safely, reliably and efficiently, to manage the costs across our organization and to deliver value to our investors. We are also continuing to focus on identifying and evaluating strategic growth opportunities,
particularly organic or bolt-on projects, such as the conversion of our Havana power generating facility to lower-cost and lower-emission PRB coal, to improve the operational performance and efficiency of certain assets, enabling us to
realize costs savings and to capture even more of the benefit of increases in commodity prices.



Such opportunities may also include merger and acquisition activities, which we discuss and evaluate as part of our ongoing business strategy. For
example, in January 2005, Dynegy completed the purchase from Exelon Corporation of all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies, Inc., which we refer to as Sithe Energies, and Sithe/Independence Power
Partners, L.P., which we refer to as Independence. The financial terms of the acquisition included Dynegys payment of $135 million, subject to certain specified purchase price adjustments, and its consolidation of $919 million in face value
project debt. Through this acquisition, Dynegy acquired the 1,021 MW combined-cycle Independence power generation facility located near Scriba, NY, four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities
in Pennsylvania. Independence holds power tolling, financial swap and other contracts with one of our subsidiaries. At the time of the closing, ExRes SHC, Inc. was not consolidated by us. The acquisition



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transformed the tolling and swap contracts into Dynegy intercompany (and our affiliate) agreements. Other than the reporting of the transactions with
Independence as affiliate transactions, we do not anticipate any other material impact to us from the transaction.



We are a wholly owned subsidiary of Dynegy, which began operations in 1985. Dynegy acquired Illinova Corporation in the first quarter of 2000. As part of
the acquisition of Illinova, the former Dynegy Inc., which was renamed Dynegy Holdings Inc., became a wholly owned subsidiary of a new holding company, Dynegy Inc. The assets, liabilities and operations of the former Dynegy Inc. before the
acquisition became the assets, liabilities and operations of Dynegy Holdings Inc. after the acquisition.



We file annual, quarterly and current reports, proxy statements and other information with the SEC. You may read and copy any document we file at the
SECs Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SECs Public Reference Room. Our SEC filings are also available to the public at the
SECs web site at www.sec.gov. No information from such web site is incorporated by reference herein. Our SEC filings are also available free of charge on our website, www.dynegy.com, as soon as reasonably practicable after those reports are
filed with or furnished to the SEC. The contents of our website are not intended to be, and should not be considered to be, incorporated by reference into this Form 10-K.



SEGMENT DISCUSSION



Our current business operations are focused primarily in two areas of the energy industry: power generation and natural gas liquids. Because of the
diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. We also separately report the results of our customer risk management business, which primarily
consists of our four remaining power tolling arrangements (including the Gregory toll, which expires in July 2005) as well as our gas transportation contracts and legacy gas and power trading positions. Our consolidated financial results also
reflect corporate-level expenses such as general and administrative, interest and infrastructure depreciation and amortization, but because of their nature, these items are not reported as a separate segment.



Power Generation



General. Our power generation segment is engaged in the production and sale of electric power from our owned
and leased facilities. We sell power and related products and services, including capacity, into real-time and day-ahead markets, as well as on a forward basis. We seek to optimize our power generating assets and to mitigate our exposure to
commodity prices through financial instruments and other transactions, including hedges related to our generation capacity and power purchases related to our supply obligations. Additionally, to mitigate risk related to fuel requirements at our
generation facilities, we are also party to long-term coal purchase and transportation agreements and to short-term natural gas and fuel oil agreements.



We sell our power products and services under short- and long-term agreements. Short-term sales usually occur through industry standard contracts.
Conversely, long-term sales usually occur under negotiated arrangements. Long-term contractual arrangements that we may enter into include:



| |  |  | Sales of capacity purchased by customers to meet regulatory reserve requirements. Under these types of contracts, the purchasers may also acquire the option to purchase energy at an
index or other pre-arranged price.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Tolling agreements under which we receive fixed payments in return for the customers ability to purchase fuel for one of our facilities and take title to the power generated.
Some contracts may also include provisions for reimbursement of variable operating and maintenance costs.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Ancillary services agreements under which we sell load regulation, scheduling services, reserves and voltage support to purchasers for fixed prices.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------



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Our customers include independent system operators (ISOs), municipalities, electric cooperatives,
integrated utilities, transmission and distribution utilities, industrial customers, power marketers, other power generators and commercial end-users.



Additionally, markets exist for the purchase and sale of emission credits. From time to time, we either purchase emission credits from third parties in
quantities sufficient to operate our plants within the emission guidelines of the various air districts or pay mitigation fees to the applicable air district as required. We may also sell emission credits that we do not need to utilize with respect
to emissions from our generating facilities. Please read RegulationPower Generation Regulation beginning on page 19 and Environmental and Other Matters beginning on page 21 for further discussion of the
environmental and regulatory restrictions applicable to our business.



U.S. Generation Facilities. We own or lease electric power generation facilities with an aggregate net generating capacity of 11,699 MWs located in six regions of the United States. The following table describes our current
generation facilities by name, region, location, net capacity, fuel and dispatch type.



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REGIONAL SUMMARY OF OUR U.S. GENERATION FACILITIES (1)

(as of December 31, 2004)



|                         |  |                 |  |                                  |  |                  |  |                 
|------------------------ |  | --------------- |  | -------------------------------- |  | ---------------- |  | ----------------
|Region/Facility          |  | Location        |  | Total NetGeneratingCapacity(MWs) |  | PrimaryFuel Type |  | Dispatch Type   
|Midwest-MAIN             |  |                 |  |                                  |  |                  |  |                 
|Baldwin                  |  | Baldwin, IL     |  | 1,768                            |  | Coal             |  | Baseload        
|Havana:                  |  |                 |  |                                  |  |                  |  |                 
|Havana Units 1-5         |  | Havana, IL      |  | 238                              |  | Oil              |  | Peaking         
|Havana Unit 6            |  | Havana, IL      |  | 445                              |  | Coal             |  | Baseload        
|Hennepin                 |  | Hennepin, IL    |  | 290                              |  | Coal             |  | Baseload        
|Oglesby                  |  | Oglesby, IL     |  | 54                               |  | Gas              |  | Peaking         
|Stallings                |  | Stallings, IL   |  | 82                               |  | Gas              |  | Peaking         
|Tilton                   |  | Tilton, IL      |  | 176                              |  | Gas              |  | Peaking         
|Vermilion                |  | Oakwood, IL     |  | 191                              |  | Coal/Gas/Oil     |  | Baseload/Peaking
|Wood River:              |  |                 |  |                                  |  |                  |  |                 
|Wood River Units 1-3     |  | Alton, IL       |  | 130                              |  | Gas              |  | Peaking         
|Wood River Units 4-5     |  | Alton, IL       |  | 452                              |  | Coal             |  | Baseload        
|Rocky Road (2)           |  | East Dundee, IL |  | 165                              |  | Gas              |  | Peaking         
|                         |  |                 |  |                                  |  |                  |  |                 
|Total Midwest-MAIN       |  |                 |  | 3,991                            |  |                  |  |                 
|Midwest-ECAR             |  |                 |  |                                  |  |                  |  |                 
|Riverside (6)            |  | Louisa, KY      |  | 495                              |  | Gas              |  | Peaking         
|Rolling Hills            |  | Wilkesville, OH |  | 825                              |  | Gas              |  | Peaking         
|Foothills                |  | Louisa, KY      |  | 330                              |  | Gas              |  | Peaking         
|Renaissance              |  | Carson City, MI |  | 660                              |  | Gas              |  | Peaking         
|Bluegrass                |  | Oldham Co., KY  |  | 495                              |  | Gas              |  | Peaking         
|                         |  |                 |  |                                  |  |                  |  |                 
|Total Midwest-ECAR       |  |                 |  | 2,805                            |  |                  |  |                 
|Northeast-NPCC           |  |                 |  |                                  |  |                  |  |                 
|Roseton (3)              |  | Newburgh, NY    |  | 1,210                            |  | Gas/Oil          |  | Intermediate    
|Danskammer:              |  |                 |  |                                  |  |                  |  |                 
|Danskammer Units 12     |  | Newburgh, NY    |  | 128                              |  | Gas/Oil          |  | Peaking         
|Danskammer Units 3-4 (3) |  | Newburgh, NY    |  | 370                              |  | Coal/Gas/Oil     |  | Baseload        
|                         |  |                 |  |                                  |  |                  |  |                 
|Total Northeast-NPCC     |  |                 |  | 1,708                            |  |                  |  |                 
|Southeast-SERC           |  |                 |  |                                  |  |                  |  |                 
|Calcasieu                |  | Sulphur, LA     |  | 320                              |  | Gas              |  | Peaking         
|Heard County             |  | Heard Co., GA   |  | 495                              |  | Gas              |  | Peaking         
|Rockingham               |  | Rockingham, NC  |  | 825                              |  | Gas/Oil          |  | Peaking         
|                         |  |                 |  |                                  |  |                  |  |                 
|Total Southeast-SERC     |  |                 |  | 1,640                            |  |                  |  |                 
|West-WECC                |  |                 |  |                                  |  |                  |  |                 
|Cabrillo IEncina (4)    |  | Carlsbad, CA    |  | 480                              |  | Gas              |  | Intermediate    
|Black Mountain (5)       |  | Las Vegas, NV   |  | 43                               |  | Gas              |  | Baseload        
|El Segundo (4)           |  | El Segundo, CA  |  | 335                              |  | Gas              |  | Intermediate    
|Cabrillo II (4)          |  | San Diego, CA   |  | 87                               |  | Gas              |  | Peaking         
|                         |  |                 |  |                                  |  |                  |  |                 
|Total West-WECC          |  |                 |  | 945                              |  |                  |  |                 
|Texas-ERCOT              |  |                 |  |                                  |  |                  |  |                 
|CoGen Lyondell           |  | Houston, TX     |  | 610                              |  | Gas              |  | Baseload        
|                         |  |                 |  |                                  |  |                  |  |                 
|TOTAL                    |  |                 |  | 11,699                           |  |                  |  |                 
|                         |  |                 |  |                                  |  |                  |  |                 

---

|(1) | We own 100% of each unit listed except as otherwise indicated. For each unit in which we own less than a 100% interest, the Total Net Generating Capacity set forth in this table
includes only our proportionate share of such units gross generating capacity.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | We own a 50% interest in this facility and the remaining 50% interest is held by NRG Energy, Inc.
|--- | -------------------------------------------------------------------------------------------------

|(3) | We lease the Roseton facility and units 3 and 4 of the Danskammer facility pursuant to a leveraged lease arrangement that is further described in Item 7. Managements
Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital ResourcesOff-Balance Sheet ArrangementsDNE Leveraged Lease beginning on page 37.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | We own a 50% interest in each of these facilities through West Coast Power, L.L.C., a joint venture with NRG Energy. Our 50% interest in West Coast Powers Long Beach
generation facility has not been included because this asset was retired effective January 1, 2005 as discussed further below.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) | We own a 50% interest in this facility and the remaining 50% interest is held by ChevronTexaco.
|--- | -----------------------------------------------------------------------------------------------

|(6) | We lease this facility.
|--- | -----------------------



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Midwest regionMid-America Interconnected Network (MAIN). At December 31, 2004, we
owned nine generating facilities with an aggregate net generating capacity of 3,991 MWs located within MAIN. The generating capacity of our MAIN facilities represents approximately 6% of the generating capacity within the MAIN region. The MAIN
market includes all of Illinois and portions of Missouri, Wisconsin, Iowa, Minnesota and Michigan.



Approximately 50% of the power generated by our MAIN facilities was sold pursuant to a former power purchase agreement between DMG and Illinois Power
which expired at the end of 2004. This agreement, which was served through Illinois Powers former generation facilities now owned by DMG, provided Illinois Power with approximately 70% of its capacity requirements through December 2004. The
contract provided for fixed capacity payments based on the capacity reserved, as well as variable energy payments for each MWh of energy delivered under the contract based on DMGs cost of generation. Under the former agreement, DMG served as
the provider of last resort to Illinois Power, providing the resources through which Illinois Power fulfilled its load obligations; it also supplied all ancillary services required by Illinois Power. This power purchase agreement provided a
substantial portion of the operating income from our power generation business in 2004.



In connection with Dynegys sale of Illinois Power to Ameren in the third quarter 2004, DMG entered into a new contract to sell to Illinois Power 2,800 MWs of capacity at $48 per KW-yr and up to 11.5 million MWh
of energy at a fixed price of $30 per MWh to Illinois Power for two years beginning in January 2005. DMG also agreed to sell 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to Illinois Power at a fixed price of $16 per KW-yr with an
option to purchase energy at market-based prices. Under this arrangement, DMG is no longer the provider of last resort to Illinois Power. Please read Item 7. Managements Discussion and Analysis of Financial Condition and Results of
OperationsResults of Operations2005 OutlookGEN Outlook beginning on page 56 for further discussion.



Approximately 9% of our total capacity in this region which is not committed under the Illinois Power power purchase agreement will be sold under capacity
contracts in 2005, including 165 MWs related to our interest in Rocky Road through 2009. The remainder of the capacity and energy is sold primarily into wholesale markets in MAIN, the neighboring East Central Reliability, or ECAR, and the
Pennsylvania-New Jersey-Maryland market, or PJM.



All of our
MAIN facilities (except Rocky Road, which is located in PJM) are located in a market to be administered by the Midwest ISO Regional Transmission Organization, or MISO. Formation of MISO was approved by the FERC in 2001, and MISO currently
administers transmission operations. MISO has received FERC approval to begin operating energy markets on April 1, 2005. MISO has indicated that it plans to use locational-pricing for energy, as well as financial transmission rights to allow market
participants to manage transmission risks. MISO has proposed implementation of a capacity market by June 1, 2006, but has not yet committed to a specific market design. The impact on our results of operations, financial condition and cash flows of
MISO capacity market structures, should they be implemented, cannot currently be estimated.



The MAIN region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERCs estimated 2004 reserve margin of 30%. MISO proposals to implement
reserve requirements and capacity markets are currently under development, but we expect reserve margin targets will generally be consistent with the 15% target reserve margin of Pennsylvania-New Jersey-Maryland Interconnection, LLC, or PJM.
Overcapacity in the MAIN region has depressed energy and capacity prices and likely will continue to do so absent peak demand growth and/or plant retirements. Based on current expectations of future demand growth and retirements, we believe that
reserve margins are likely to return to target levels within the next 3-5 years.



Midwest regionEast Central Area Reliability Council (ECAR).We own or lease interests in five generating facilities with an aggregate net generating capacity of 2,805 MWs located within ECAR. The
majority of the power generated by our ECAR facilities is sold to wholesale customers in the ECAR market, which



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includes all or portions of the states of Indiana, Ohio, Michigan, Virginia, West Virginia, Tennessee, Kentucky, Maryland and Pennsylvania.



At the end of 2003, we entered into a contract for 495 MWs of our Renaissance
facilitys generating capacity, which expired in September 2004. In July 2004, we entered into an agreement with a term from June 2005 through May 2006 to sell 500 MWs of capacity from our peaking facilities in the ECAR region. In August 2004,
we entered into an additional agreement with a term from May 2005 through September 2005 to sell 330 MWs of our Renaissance facilitys net generating capacity. The generating capacity of our ECAR facilities represents approximately 2% of the
generating capacity within the region.



Our Renaissance and
Bluegrass facilities are located in the MISO. Our Riverside, Rolling Hills, and Foothills facilities are located within PJM. PJMs geographic area has significantly expanded in the past two years, including the addition of the AEP service area
in which the Riverside, Rolling Hills, and Foothills facilities are located. The boards of PJM and MISO have committed to establish a joint and common market across their respective regions; however, there can be no assurance that
efforts to integrate the two market structures will be successful.



PJM currently administers markets for wholesale electricity and provides transmission planning for the region. PJM operates day-ahead and real time markets into which generators can bid to provide electricity and ancillary services. To
account for transmission congestion and losses, PJM calculates prices using a locational-based pricing model that is also used to determine generation unit dispatch. Wholesale electricity prices in PJM are currently capped at $1,000 per MWh. PJM
also administers markets for installed capacity, which are an important potential revenue source for peaking facilities. PJM has proposed changes to its capacity markets, including establishing longer-term markets for capacity to improve market
signals for new generation, although there are no assurances that such proposals will be implemented. The future economic impact, if any, of PJM and MISO policies and proposals on our ECAR facilities cannot currently be estimated.



The ECAR region currently has excess generation capacity as a result of
recent development projects. This overcapacity is evidenced by the NERCs estimated 2004 reserve margin of 27%. MISO has indicated that it will enforce the current reserve requirement in each Reliability Region (i.e., MAIN, ECAR and MAPP) until
such time that a capacity market is implemented. The reserve requirement to apply during the period following establishment of such capacity market has not been determined. This overcapacity has depressed energy and capacity values in this region
and likely will continue to do so absent peak demand growth and/or plant retirements. Based on current expectations of future demand growth and retirements, we believe that reserve margins are likely to return to target levels within the next 3-5
years.



Northeast regionNortheast Power
Coordinating Council (NPCC). We lease two generating facilities in New York, which we refer to as the DNE facilities, with an aggregate net generating capacity of 1,708 MWs. Our DNE facilities sites are adjacent and share common
resources such as fuel handling, a docking terminal, personnel and systems. The generating capacity of these facilities represents approximately 5% of the generating capacity in the state of New York.



The New York Independent System Operator, or NYISO, administers the statewide
transmission system and spot markets for electricity and, like PJM, calculates electricity prices and dispatches generation using a locational-based pricing model. NYISO also administers markets for installed capacity, operating reserves and
regulation service. NYISO employs an AMP in its day-ahead electricity market that caps energy bids when certain bid screen criteria are exceeded. In 2003, NYISO implemented a Demand Curve mechanism for calculating pricing for installed
capacity for three locational zones: New York City, Long Island, and the rest of the State of New York. Our facilities operate outside of New York City and Long Island. Capacity pricing is calculated as a function of NYISOs 18% target reserve
margin, estimated cost of new entrant generation, estimated peak demand, and the actual amount of capacity bid into the market. The demand curve mechanism provides for incrementally higher capacity pricing at lower reserve margins, such
that new entrant economics become attractive as the reserve margin approaches target levels.



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Due to transmission constraints, prices vary across the state and are generally higher in the Eastern
part of New York, where our Roseton and Danskammer facilities are located, and in New York City. Current reserve margins of 21% are somewhat above the NYISOs target reserve margin of 18%. We believe that reserve margins are likely to return to
target levels within the next 3-5 years.



Southeast
regionSoutheastern Electric Reliability Council (SERC).We own interests in three generating facilities with an aggregate net generating capacity of 1,640 MWs located within SERC. SERC includes all or portions of the states of
Missouri, Kentucky, Arkansas, Tennessee, West Virginia, Virginia, North Carolina, South Carolina, Louisiana, Mississippi, Alabama and Georgia. The generating capacity of these facilities represents approximately 1% of the generating capacity in
SERC. Of our 1,640 MWs of net generating capacity in SERC, 665 MWs, or 40%, is sold under contract. A contract for our Calcasieu facilitys 320 MWs of capacity expired in December 2004. In January and February 2004, we signed two agreements to
sell an aggregate 215 MWs of our Rockingham facilitys net generation capacity, with terms beginning in 2006 and expiring in 2010. We also signed an agreement in January 2004 covering an additional 165 MWs of our Rockingham facilitys net
generating capacity, which expired in September 2004.



Our SERC
assets are located within the control areas of vertically integrated utilities and municipalities. All power sales and purchases are consummated between individual parties and are physically delivered either within or across the control areas of the
transmission owners. The present market framework in SERC is not a centralized market, and the timing of any transition to centralized competitive markets for energy and capacity is currently unknown.



The SERC region currently has excess generation capacity as a result of
recent development projects. This overcapacity is evidenced by the NERCs estimated 2004 reserve margin of 51%, which significantly exceeds SERCs estimated target reserve margin of approximately 17%. This overcapacity has depressed energy
and capacity values in this region and likely will continue to do so absent peak demand growth and/or plant retirements. Overcapacity is concentrated in the Entergy and Southern sub-regions of SERC, and these regions are unlikely to see reserve
margins near target levels within the next ten years. Overcapacity is less severe in the VACAR sub-region of SERC, where we believe market conditions may require new capacity additions within the next 4-6 years.



West regionWestern Electricity Coordinating Council (WECC).We own interests in four generating facilities with an aggregate net generating capacity of 945 MWs within WECC. The WECC regional market includes all or parts of the states of Arizona, California, Oregon, Nevada, New Mexico, Colorado,
Wyoming, Idaho, Montana, Nebraska, Texas, South Dakota, Utah and Washington. Our generating capacity in the WECC represents less than 1% of the overall generating capacity in this region.



Of our 945 MWs of net generating capacity in the WECC, 902 MWs consists of our 50% share of the 1,804 MWs of facilities
owned by West Coast Power. All of the West Coast Power facilities are located in southern California, and the generation output of the facilities was substantially covered by a contract, which we refer to as the CDWR contract, between one of our
marketing subsidiaries, as agent for the facility owners, and the CDWR. This contract expired in December 2004.



Since the expiration of the CDWR contract, all of our West Coast Power assets have been operating under Reliability Must Run (RMR) Condition II contracts
with the Cal ISO, except for the Long Beach facility, which is discussed below. Under the terms of these RMR contracts, Cal ISO reimburses West Coast Power for 100% of approved costs plus a rate of return specified in the contracts. When the
facilities are instructed to provide power by the Cal ISO, they are reimbursed for their variable production costs. Under RMR Condition II, the facilities are 100% committed to the Cal ISO and, therefore, do not experience changes in market
conditions through bilateral energy or capacity sales to third parties that might otherwise be consummated. The RMR contracts are effective for calendar year 2005. The Cal ISO may renew or terminate the RMR contracts at its sole option on an annual
basis as of the first of the following year. In addition West Coast Power, through one of our marketing



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subsidiaries, as agent for the facility owner, has entered into a power sales agreement with a major California utility for the sale of 100% of the capacity
and associated energy from the El Segundo facility from May through December 2005. During the term of this agreement, the purchaser will be entitled to primary energy dispatch rights for the facilitys generating capacity. The agreement is
subject to the amendment of the El Segundo RMR agreement to switch to RMR Condition I and to otherwise allow the purchaser to exercise its primary dispatch rights under this agreement while preserving Cal ISOs ability to call on the El Segundo
facility as a reliability resource under the RMR agreement, if necessary.



In Californias current energy market, the West Coast Power generating facilities are significantly less profitable under RMR contracts or as merchant facilities, and we may consider other alternatives if
necessary, including shutting down units if we no longer consider them commercially viable. Based on our ongoing evaluation of strategic alternatives for our West Coast Power assets, we determined that it was not economically feasible to continue to
operate our Long Beach generation facility beyond the expiration of the CDWR contract. Therefore, we retired the asset as of January 1, 2005.



Our West Coast Power facilities are located in the Cal ISO control area, which includes facilities serving approximately 75% of Californias demand.
The Cal ISO schedules transmission transactions, arranges for ancillary services, and administers a real time balancing energy market. Day ahead purchases and sales are executed bilaterally and scheduled for physical delivery by the Cal ISO. There
is currently no capacity market in the Cal ISO. The Cal ISO is continuing its plan to move toward a market design similar to PJM and NYISO, although the timing and final structure of any such market design cannot currently be predicted.



For a discussion of litigation and other legal proceedings related to
energy market restructuring in California, the impact of current regulations on our WECC facilities and related uncertainty associated with the California wholesale market, please read Note 14Commitments and ContingenciesSummary of
Material Legal ProceedingsCalifornia Market Litigation beginning on page F-46.



Texas regionElectric Reliability Council of Texas (ERCOT).We own a generating facility with a generating capacity of 610 MWs located in ERCOT. This facility represents less than 1% of the
generating capacity in the ERCOT region. The ERCOT market is comprised of the majority of the state of Texas.



Approximately 13% of our capacity in this region, consisting of 80 MWs of capacity at our CoGen Lyondell facility, is sold under a capacity agreement
which expires in December 2006.



Our Texas facility
participates in a market administered by the ERCOT ISO, which oversees competitive wholesale and retail markets. ERCOTs operations are overseen by the PUCT. ERCOT operates as the single control area within its region, and operates capacity and
energy markets for market participants. Price mitigation measures in ERCOT include a $1,000 per MWh offer cap. ERCOT is considering wholesale market design changes including locational-based pricing similar to markets in NYISO and PJM in response to
a PUCT rule; however, there can be no assurances that such design changes will be implemented.



By most measures, the ERCOT region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERCs estimated 2004 reserve margin of 26%, which is
significantly in excess of the ERCOTs target minimum reserve margin of 12.5%. This overcapacity has depressed energy and capacity values in this region and will likely continue to do so absent peak demand growth and/or plant retirements.
However, recently released reports from ERCOT indicate that reserve margins may fall below the 12.5% level within the next 1  2 years due to recently announced generating retirements and mothballed units.



Retail Supply Business.We selectively enter into short- and
long-term contracts with individual commercial and industrial customers to serve their load requirements in markets where we have a generation presence and where the regulatory environment supports these efforts. Our current sales and retail
operations are directed toward Texas, Illinois and New York. In early 2005, we made the decision to formally exit the Retail Supply Business.



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Natural Gas Liquids



General. Our natural gas liquids segment consists of our midstream asset operations, located principally in Texas, Louisiana and New Mexico,
and our North American natural gas liquids marketing business. This segment has both upstream and downstream components. The upstream components include natural gas gathering and processing; while the downstream components include fractionating,
storing, terminalling, transporting, distributing and marketing natural gas liquids.



The following graphic depicts the revenue opportunities that exist throughout our upstream and downstream operations.



LOGO



Upstream Business



Our upstream business includes the gathering of
natural gas produced from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. We own interests in 17 gas processing plants, including 11 plants we operate. We
also operate over 9,385 miles of natural gas gathering pipeline systems associated with the 11 operated facilities and two stand-alone natural gas gathering pipeline systems where gas is treated and/or processed at third-party plants. Our upstream
assets are located in the growing oil and gas exploration and production areas of North Texas and Louisiana, and the mature Permian Basin of West Texas and Southeast New Mexico. During 2004, we processed an average of 1.6 Bcf/d of natural gas and
produced an average of 82,120 barrels per day of natural gas liquids, in each case, net to our ownership interests. We are also party to natural gas processing agreements with five third-party plants.



Our upstream business is significantly impacted by the types of contracts
under which we process gas. There are four primary types of gas processing contracts where natural gas liquids are extracted: percent of proceeds, percent of liquids, keep-whole and wellhead purchase.



| |  |  | Under percent of proceeds, or POP, contracts, a producer delivers to us a percentage of the natural gas liquids and a percentage of the natural gas as payment for our services and
retains the value of the remaining natural gas liquids and natural gas at the processing plant tailgate. The producer retains this value by either taking its share of the natural gas liquids and natural gas in kind or by receiving its share of the
proceeds from our sale of their share of the commodities.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Under percent of liquids, or POL, contracts, a producer delivers to us a percentage of the natural gas liquids as payment for our services and retains the value of
the remaining natural gas liquids and all of the natural gas at the processing plant tailgate. Similar to POP contracts, the producer will either take
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | their share of the natural gas liquids in kind or take the proceeds from our sale of their share of the natural gas liquids.
| | ----------------------------------------------------------------------------------------------------------------------------



| |  |  | Under keep-whole, or KW, contracts, we extract natural gas liquids and return to the producer volumes of merchantable natural gas containing the same Btu content as the unprocessed
natural gas that was delivered to us. We retain the natural gas liquids as our payment for processing. We must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus that were removed as natural gas
liquids through processing so that the producer is kept whole on a Btu basis. This contract type is fully exposed to the frac spread, which is the relative difference in value between natural gas liquids and natural gas on a Btu basis.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Under wellhead purchase, or WHP, contracts, we purchase unprocessed natural gas from a producer at the wellhead at a discount to the market value of the gas. This discount, together
with any value increase for natural gas liquids extracted from the natural gas, is our margin for gathering and processing.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Factors influencing the contract mix at a particular facility include, among other things, the Btu content of the gas, which determines if natural gas
liquids must be extracted from the natural gas to meet natural gas pipeline quality specifications; the investment in extensive gathering systems to bring gas to a particular plant; the term of the gas supply contracts behind a processing plant; and
the prevailing competitive factors when contracts are negotiated.



We characterize our natural gas processing plants in two categoriesfield plants and straddle plants. The processing contract mix varies significantly between the two categories.



Field Plants. Field plants connect volumes of unprocessed gas
from multiple onshore producing wells. Through extensive gathering systems, these volumes are aggregated into sufficient volumes to be economically processed to extract natural gas liquids and to remove water vapor, solids and other contaminants to
provide marketable natural gas, commonly referred to in the industry as residue gas. The following map depicts our field plant assets, including our capacity, 2004 natural gas throughput and natural gas liquids production levels for the
assets as of year end 2004. Our field plants are located in the mature and prolific Permian Basin of West Texas and Southeast New Mexico, and in North Texas, where we are ideally situated to benefit from the high volume growth Barnett Shale
production development.



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In our field plants we process natural gas primarily under POP contracts. In 2004, approximately 99% of
the volumes processed were under POP settlement terms and the remainder was processed under KW or WHP contracts. We expect a similar contract mix in 2005. This is particularly important because the natural gas processed by all of these facilities
contains natural gas liquids in sufficient quantities to require that the natural gas be processed to extract enough of the natural gas liquids to meet gas pipeline and market quality specifications. Having essentially all POP contracts removes the
significant price spread risk associated with KW and WHP contracts and makes the key economic drivers for our field plants natural gas and natural gas liquids volumes and the absolute price of both residue gas and natural gas liquids.



Our field plants recovered an average of 4.28 gallons of natural gas liquids
per Mcf of raw gas processed in 2004. The component split of mixed natural gas liquids produced by our field plants in 2004 was as follows:



LOGO



We are also impacted by producer
drilling activity, which is sensitive to commodity prices. Additionally, safe, low-cost and reliable operation of our facilities, together with highly efficient plant operation, improves our competitiveness in attracting new gas volumes to replace
intrinsic declines in natural gas well production at the same or better contractual terms.



Straddle Plants. Straddle plants generally are situated on mainline natural gas pipelines. Our straddle plants are located on pipelines transporting natural gas from the Gulf of Mexico to key Midwest and
East Coast natural gas markets. The following map depicts our straddle plant assets as of year end 2004, including our capacity, 2004 natural gas throughput and natural gas liquids production levels.



LOGO





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We process natural gas in our straddle plants under POL and KW contracts as well as hybrid contracts that
contain different settlement terms. Under hybrid contracts, the settlement outcome can be either POL, KW or a fee and is usually triggered by market conditions, most often automatically, or, in some cases, by the election of one or both of the
parties. When it is economical to extract natural gas liquids, these hybrid contracts typically settle under POL terms.



When it is not profitable to extract natural gas liquids (i.e., when the value of the natural gas liquids is less than the value of natural gas on an
equivalent Btu basis), most of the volumes processed under these hybrid contracts automatically convert to a fee-based processing arrangement. This fee is generally paid in the form of cash and/or a nominal percentage of the natural gas liquids
processed. For some of these volumes, the producer and/or the processor have contract settlement election options. The producer can elect to either process or not process, generally on a POL basis. If the producer elects to not process, we often
have the option to process on a KW basis. If we elect to not process, either we can cause the gas to bypass the plant, where such capabilities exist, or the producer pays us a per-unit fee to process the gas.



The charts below show the current and expected contract mix for our straddle
plants. On the left, the current mix does not reflect an expected FERC approval of hydrocarbon dew point specifications on natural gas pipelines along the Gulf of Mexico. Assuming FERC approves hydrocarbon dew point specifications, significant
production historically processed under KW contracts will be generally settled under fee or hybrid contracts. The chart on the right shows our anticipated contract mix following enforcement of hydrocarbon dew point specifications on pipelines in the
Gulf area and reflects our expectation of a significant decline in our frac spread exposure.



LOGO



The results of our straddle plant
operations are heavily dependent on the absolute price of natural gas liquids. This is particularly true when processing economics are favorable, as the hybrid contracts settle under POL terms. When processing economics are less favorable, we do
have some KW exposure to the frac spread. Our view is that strong natural gas prices will generally continue to depress the frac spread for the foreseeable future. However, our frac spread exposure is limited because most of the hybrid contracts in
this price environment settle on fee terms.



As with our field
plants, our straddle plants are impacted by producer drilling activity, which is sensitive to commodity prices, as well as our ability to operate safely, reliably and efficiently.



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The straddle plants recovered an average of 1.13 gallons of natural gas liquids per Mcf of raw gas
processed in 2004. The component split of mixed natural gas liquids produced by our straddle plants in 2004 was as follows:



LOGO



Major customers of our upstream
business include ChevronTexaco and many other large and small producers. We have a contractual right to process substantially all of ChevronTexacos gas in North America. Generally, with respect to gas they produce from all areas other than the
Gulf of Mexico, we process the gas at field plants owned by us or by third parties. The ChevronTexaco gas processed in our field plants is processed on a POP basis and is based on ChevronTexacos commitment of such production for the life of
the lease from which the production is obtained.



With respect
to the gas produced from the Gulf of Mexico area, ChevronTexacos gas is processed in both straddle plants in which we own an interest and in plants owned by third parties. We operate five of the plants in which we own an interest.
ChevronTexaco gas produced from the Gulf of Mexico area is processed on a POL basis when processing is economical or is processed on a fee basis if natural gas liquids extraction is not profitable. The leases, or portions thereof, committed under
this agreement are committed for the life of the leases dedicated to us for processing. Until September 1, 2006, ChevronTexaco has agreed to dedicate to us for processing any gas attributable to new production obtained from oil, gas and/or mineral
leases not previously dedicated to us for processing as of March 1, 2002. These dedications made by ChevronTexaco may be limited to certain productive horizons and/or may only be partially committed as to acreage.



Both types of processing agreements with ChevronTexaco allow either party to
initiate renegotiation of the commercial terms for processing previously dedicated natural gas production effective in September 2006 and on each successive 10-year anniversary thereafter for ChevronTexaco gas processed in field plants; and, five
years thereafter, for gas produced from the Gulf of Mexico and processed in Louisiana straddle plants. During 2004 and 2003, respectively, ChevronTexaco gas accounted for 32% and 46% of the total volume of gas we processed.



Hedging Strategy. As a result of our POP and POL contracts, we
take ownership of natural gas and natural gas liquids as payment for our services. We have a comprehensive hedging strategy and related control procedures to manage price risk on these equity volumes. We limit volume considered for hedging and
forward selling to Dynegy-owned volumes received at our field processing facilities that must operate for gas to meet natural gas pipeline quality specifications. The portion of equity natural gas and natural gas liquids that we hedge is monitored
closely against our field processing plant operations to ensure we hedge no more than the volume we own. We seek to mitigate correlation risk by hedging each natural gas liquid product against our physical production of that product. Realized loss
on hedged volumes was $10 million below the average realized price for unhedged volumes for 2004 as compared to $7 million below the average realized price for unhedged volumes for 2003.



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Downstream Business



In our downstream business, we use our integrated assets to fractionate, store, terminal, transport, distribute and market
natural gas liquids. Our downstream assets are generally connected to and supplied, in part, by our upstream assets and are located in Mont Belvieu, Texas, the hub of the U.S. natural gas liquids business, and West Louisiana. The following map
depicts our downstream assets, including our capacity and throughput capabilities.



LOGO



Fractionation. When
pipeline-quality natural gas is separated from natural gas liquids at processing plants, the natural gas liquids are generally in the form of a commingled stream of light liquid hydrocarbons, which is referred to as mixed or
raw natural gas liquids. The mixed natural gas liquids are separated at fractionation facilities through a distillation process into the following component products:



| |  |  | Ethane, or a mixture of ethane and propane known as EP mix;
| | - |  | -----------------------------------------------------------



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



| |  |  | Normal butane;
| | - |  | --------------



| |  |  | Isobutane; and
| | - |  | --------------



| |  |  | Natural gasoline.
| | - |  | -----------------



The percentages of these products produced at our fractionators in 2004 were as follows:



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We fractionate volumes for customers, from both our own upstream operations and third parties, under
contracts that typically include a base fee per gallon plus other fee components that are subject to adjustment for variable costs such as energy consumed in fractionation. We have ownership interests in three stand-alone fractionation facilities
that are strategically located on the Texas and Louisiana Gulf Coast. We operate two of the facilities, one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. During 2004, these facilities fractionated an aggregate average of 183,000
gross barrels per day (net to our ownership interests). We also have an equity investment in a third fractionator located in Mont Belvieu, which is subject to a 1996 consent decree with the FTC that prevents us from participating in commercial
decisions regarding rates paid by third parties for fractionation services.



The results of our fractionation operations are significantly impacted by the following factors: our ability to attract term volumes of raw natural gas liquids at profitable margins; the impact of frac spreads on the
supply of natural gas liquids available for fractionation; the composition of the liquids received; energy costs; and operational efficiencies.



Storage & Terminalling.Our natural gas liquids storage facilities have extensive pipeline connections to third-party pipelines,
third-party facilities and to our own fractionation and terminalling facilities. In addition, some of these storage facilities are connected to marine, rail and truck loading and unloading facilities that provide service and products to our
customers. We provide long- and short-term storage services and throughput capability to affiliates and third-party domestic customers for a fee.



We own and/or operate a total of 41 storage wells with an aggregate capacity of 108 MMBbls, the usage of which may be limited by brine handling capacity.
Brine is utilized to displace natural gas liquids from storage. When large volumes of natural gas liquids are stored, we store the displaced brine in our brine storage ponds adjacent to our storage facilities and, depending on the volume, may inject
excess brine in our brine disposal wells. When reduced volumes of natural gas liquids are stored, we utilize the brine from our brine storage ponds to displace the volumes of natural gas liquids removed and, if necessary, can produce additional
brine from wells dedicated for that purpose through a process known as brine leaching.



The results of our storage operations are significantly impacted by the following factors: the petrochemical industrys level of capacity utilization and their specific feedstock requirements; our ability to
utilize our integrated asset base flexibly to meet changing customer and market demands; and safe, low-cost, efficient operations.



Transportation and Logistics. Our natural gas liquids transportation and logistics infrastructure comprises a wide range of transportation
and distribution assets supporting both third-party customers and the delivery requirements of our distribution and marketing business. We provide a fee-based transportation service to refineries and petrochemical companies throughout the Gulf Coast
area. These assets are also deployed to serve our wholesale distribution terminals, fractionation facilities, underground storage facilities, pipeline injection terminals and many of the nations crude oil refineries and petrochemical
facilities. Our marine terminals are located in Texas, Florida, Louisiana and Mississippi. We also have wholesale propane terminals located in Tennessee, Texas, Mississippi, Kentucky and Florida, and lease capacity at third-party storage facilities
throughout North America. These distribution assets provide a variety of ways to transport and deliver products to our customers. Our transportation assets include:



| |  |  | More than 2,000 railcars owned or leased by ChevronTexaco that we manage pursuant to a services agreement with ChevronTexaco;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | 78 transport tractors and 114 tank trailers;
| | - |  | --------------------------------------------



| |  |  | More than 550 miles of gas liquids pipelines, primarily in the Gulf Coast area; and
| | - |  | -----------------------------------------------------------------------------------



| |  |  | 21 natural gas liquids pressurized barges with more than 320,000 barrels of capacity.
| | - |  | -------------------------------------------------------------------------------------



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Distribution and Marketing Services. Our distribution and marketing services include: (1)
Refinery services; (2) Wholesale propane marketing; and (3) Purchasing mixed natural gas liquids and natural gas liquids products from natural gas liquids producers and other sources and selling the natural gas liquids products to petrochemical
manufacturers, refineries and other marketing and retail companies.



| |  |  | Refinery Services.In our refinery services business, we provide LPG balancing services, purchasing natural gas liquids products from refinery customers and selling
natural gas liquids products to various customers. We also use our storage, transportation, distribution and marketing assets to assist refinery customers in managing their natural gas liquids product demand and production schedules. This includes
both feedstocks consumed in refinery processes and the excess LPG produced by those same refining processes. Under our netback contracts, we generally retain a portion of the resale price of natural gas liquids sold or receive a fixed
minimum fee per gallon on products sold. Also under netback contracts, fees are obtained for locating and supplying natural gas liquids feedstocks to the refineries either based on a percentage of the cost to obtain such supply or through a minimum
fee per gallon. In 2004, we sold an average of 38,000 barrels of LPG per day through our refinery services business.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



We have refinery services contracts with each of ChevronTexacos refineries situated in El Segundo, California; Pascagoula, Mississippi; Richmond,
California; Salt Lake City, Utah; and Barbers Point, Hawaii. All of these contracts allow us to market excess LPG produced during the refining process. With respect to all of the ChevronTexaco refineries, except Hawaii, these agreements also require
us to supply to ChevronTexaco natural gas liquids utilized in their refining process as required by the refinery. The agreements require us to obtain, on behalf of the refineries, natural gas liquids feedstocks that each refinery requires on a daily
basis. These agreements extend through August 2006. Approximately 47% and 44% of the business natural gas liquids volumes purchased in 2004 and 2003, respectively, were from ChevronTexaco.



Key factors impacting the results of our refinery services business include
propane and butane prices, our ability to perform receipt, delivery and transportation services and refinery demand.



| |  |  | Wholesale Propane Marketing. Our wholesale propane marketing operations include the sale of propane and related logistics services to major multi-state retailers,
independent retailers and other end users. Our propane supply primarily originates from both our refinery/gas supply contracts and our other owned and/or managed distribution and marketing assets. We generally sell propane at a fixed or posted price
at the time of delivery. In 2004, we sold an average of 44,500 barrels of propane per day.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Our wholesale propane marketing business is significantly impacted by weather-driven demand, particularly in the winter, the price of propane in the
markets we serve and our ability to deliver propane to customers to satisfy peak winter demand.



| |  |  | Distribution and Marketing Services. We market our own natural gas liquids production and also purchase natural gas liquid products from other natural gas liquids
producers and marketers for resale. In 2004, our distribution and marketing services business sold an average of 200,000 barrels per day of natural gas liquids in North America. We generally purchase mixed natural gas liquids from producers at a
monthly pricing index less applicable fractionation, transportation and marketing fees and resell these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical business in which we
earn margins from purchasing and selling natural gas liquid products from producers under contract. We also earn margins by purchasing and reselling natural gas liquids products in the spot and forward physical markets.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



We also have the right to purchase or market substantially all of
ChevronTexacos natural gas liquids pursuant to a Master Natural Gas Liquids Purchase Agreement that extends through August 31, 2006.



This business is impacted by a number of factors, including our ability to prudently manage inventories during periods of market price movements and
meeting our delivery obligations under term contracts.



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In 2004 and 2003, approximately 35% and 32%, respectively, of our specification natural gas liquids sales
were made to ChevronTexaco or one of its affiliates pursuant to the refinery agreements discussed above and pursuant to an agreement we have with Chevron Phillips Chemical Company. In the latter agreement, we supply a significant portion of Chevron
Phillips Chemicals natural gas liquids feedstock needs in the Mont Belvieu area and collect a cents-per-barrel fee for storage and product delivery.



Customer Risk Management



Our CRM segment is comprised largely of our four remaining power tolling arrangements (including the Gregory toll, which expires in July 2005). On January
31, 2005, Dynegy acquired from Exelon Corporation the 1,021 MW Independence power generating facility in New York. We are entitled to 955 MW of the power generated by this facility under the Independence tolling arrangement. The toll remains in
effect, and we remain obligated to Independence under the agreement. However, Independence is now owned by Dynegy, our parent. See Note 20Subsequent Events, for further discussion. We have mitigated the effect of our Kendall tolling
arrangement through November 2008 by entering into a back-to-back power purchase agreement with a subsidiary of Constellation Energy, whereby we will receive payments which offset our obligations to LSP-Kendall. Pursuant to these power
tolling arrangements, we are obligated to make aggregate payments of approximately $1.8 billion to our counterparties in exchange for access to power generated by their facilities, resulting in a total obligation of $1.6 billion, net of $161 million
to be received from Constellation. In addition to these tolling arrangements, our CRM segment includes gas transportation contracts and our remaining gas and power trading positions. We are actively pursuing opportunities to terminate, assign or
renegotiate the terms of our contractual obligations related to our remaining obligations under these agreements.



The following table contains a listing of our power tolling arrangements, including the name and location of each related project, the term of each
arrangement, the project capacity and our annual capacity payments, as well as other CRM fixed obligations.



CRM Obligations



|                                                     |  |           |     |                 |        |   |     |   |                          |    |     |      |   |    |       |   |   |            |  |  |   |     | 
|---------------------------------------------------- |  | --------- | --- | --------------- | ------ | - | --- | - | ------------------------ | -- | --- | ---- | - | -- | ----- | - | - | ---------- |  |  | - | --- | 
|                                                     |  |           |     |                 |        |   |     |   | Annual Capacity Payments |   
|Project                                              |  | Location  |     | Expiration Date |        |   | MWs |   | 2005                     |    |     | 2006 |   |    | 2007  |   |   | 2008 2017 | 
|                                                     |  |           |     |                 |        |   |     |   | (in millions)            |   
|Sterlington/Quachita                                 |  | Louisiana |     | 9/2017          | (1)    |   | 835 |   | $                        | 59 |     |      | $ | 61 |       |   | $ | 63         |  |  | $ | 627 | 
|Gregory                                              |  | Texas     |     | 7/2005          |        |   | 335 |   |                          | 13 |     |      |   |   |       |   |   |           |  |  |   |    | 
|Kendall                                              |  | Illinois  |     | 3/2017          | (1)(2) |   | 578 |   |                          | 39 |     |      |   | 41 |       |   |   | 42         |  |  |   | 374 | 
|Independence                                         |  | New York  |     | 11/2014         | (3)    |   | 955 |   |                          | 44 |     |      |   | 42 |       |   |   | 43         |  |  |   | 329 | 
|                                                     |  |           |     |                 |        |   |     |   |                          |    |     |      |   |    |       |   |   |            |  |  |   |     | 
|Total annual capacity payments                       |  |           | 155 |                 |        |   | 144 |   |                          |    | 148 |      |   |    | 1,330 |  
|Other fixed obligations                              |  |           | 52  |                 |        |   | 46  |   |                          |    | 46  |      |   |    | 313   |  
|Less: Payments to be received from Constellation (4) |  |           | (39 | )               |        |   | (41 | ) |                          |    | (42 | )    |   |    | (39   | )
|                                                     |  |           |     |                 |        |   |     |   |                          |    |     |      |   |    |       |   |   |            |  |  |   |     | 
|Net cash commitments                                 |  | $         | 168 |                 |        | $ | 149 |   |                          | $  | 152 |      |   | $  | 1,604 |  
|                                                     |  |           |     |                 |        |   |     |   |                          |    |     |      |   |    |       |   |   |            |  |  |   |     | 

---

|(1) | Includes a five-year extension option pursuant to which either party can elect to continue the arrangement depending on the market price for power at the expiration of the initial
contract term.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | We have entered into an offsetting agreement with a subsidiary of Constellation Energy through November 2008, under which we will receive payments equal to those owed under our
Kendall tolling arrangement.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | On January 31, 2005, Dynegy completed the Sithe Energies acquisition. As a result, these obligations are payable to a wholly owned subsidiary of Dynegy. See Note 20Subsequent
Events beginning on page F-70, for further discussion.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | Includes contractual cash commitments we are obligated to pay under a derivative contract and natural gas transportation agreements related to the Independence tolling agreement for
which liabilities have already been recorded on our balance sheet at their discounted values.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Regarding our legacy gas and power trading positions, we have substantially reduced the size of our
mark-to-market portfolio since October 2002, when we initiated our efforts to exit the CRM business. As of December 31, 2004, we have exited approximately 90% of our physical and financial gas business. We expect to have effectively exited this
business by the end of 2007, with the exception of a minimal number of physical gas transactions that expire between 2010 and 2017. Additionally, we have forward obligations to deliver emissions allowances. Currently, we own adequate allowances to
satisfy the forward obligations. Our remaining CRM power business, exclusive of our power tolling arrangements, will be effectively exited by the end of 2005; with the exception of a minimum number of positions that will remain until 2010. We will
continue our efforts to exit the remaining transactions as allowed by market liquidity and credit requirements.



Other



Our Other results include corporate governance roles and functions, which are managed on a consolidated basis, and specialized support functions such as finance, accounting, risk control, tax, legal, human resources,
administration and technology. Corporate general and administrative expenses, income taxes and corporate interest expenses, which we previously allocated among our operating divisions, are included in our other reported results, as are
corporate-related other income and expense items. Interest expense associated with borrowings incurred by our operating divisions, such as our power generation facility financings, will continue to be reflected in the appropriate business
segments results.



COMPETITION



Power Generation. Demand for power may be met by generation
capacity based on several competing technologies, such as gas-fired, coal-fired or nuclear generation and power generating facilities fueled by alternative energy sources, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste
heat and solid waste sources. Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities and other energy service companies in the development and operation of
energy-producing projects. We believe that our ability to compete effectively in this business will be driven in large part by our ability to achieve and maintain a low cost of production, primarily by managing fuel costs, and to provide reliable
service to our customers. We believe our primary competitors in this business consist of approximately 19 companies.



Natural Gas Liquids. Our natural gas liquids businesses face significant and varied competitors, including major integrated oil companies,
major pipeline companies and their marketing affiliates and national and local gas gatherers, processors, fractionators, brokers, marketers and distributors of varying sizes and experience. The principal areas of competition include obtaining gas
supplies for gathering and processing operations, obtaining supplies of raw product for fractionation, purchase and marketing of natural gas liquids, residue gas, condensate and sulfur, and transportation of natural gas and natural gas liquids and
storage of natural gas liquids. Competition typically is based on location and operating efficiency of facilities, reliability of services, delivery capabilities and price. We believe our primary competitors in this business consist of approximately
21 companies.



REGULATION



We are subject to regulation by various federal, state, local and foreign
agencies, including the regulations described below.



Please
read Environmental and Other Matters beginning on page 21 for a discussion of environmental regulations affecting our business.



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Power Generation Regulation. The FERC has exclusive ratemaking jurisdiction over wholesale
power sales in interstate commerce. Our power generation operations are subject to FERC regulation with respect to rates, the procurement and provision of certain services and operating standards. All of our current QF projects are qualifying
facilities and, as such, are exempt from the ratemaking and other provisions of the FPA. Our EWGs, which are not QFs, have been granted market-based rate authority and comply with the FPA requirements governing approval of wholesale rates and
subsequent transfers of project ownership interests. We are subject to the jurisdiction of the PUCT with respect to our operations in ERCOT.



In certain markets where we own power generation facilities, specifically California and New York, the FERC has, from time to time, approved temporary
price caps on wholesale power sales or other market mitigation measures. In New York, the FERC approved and extended indefinitely an Automated Mitigation Procedure, or AMP, that caps bid prices based on the cost characteristics of power generating
facilities, such as our DNE facilities. In January 2005, the U.S. Court of Appeals for the District of Columbia Circuit issued an opinion vacating and remanding the FERCs orders approving the AMP in the day-ahead market outside of New York
City, where our DNE facilities are located. At this time it is not known whether the NYISO and others have sought reconsideration of this decision; consequently, the AMP currently remains in effect.



In February 2004, the FERC accepted, subject to certain modifications, the
NYISOs proposed real-time scheduling software, but rejected the NYISOs proposal to extend the real-time AMP to areas outside New York City. On rehearing in August 2004, the FERC granted rehearing and allowed the NYISO to apply the
real-time AMP in the area outside New York City.



As a
consequence of the California energy crisis, which arose in 2000, generation within the Cal ISO is subject to mitigation consisting primarily of a $250/MWh offer cap and an AMP that under certain conditions limits the pricing of the electricity we
generate in California. All power generating facilities in California fueled by fossil fuels, including all of our California facilities, are still obligated to offer all available output subject to these restrictions.



The energy crisis also precipitated a number of other FERC actions related to
the California energy market, and the Western market generally, in addition to price caps and market mitigation measures. These actions included investigations concerning alleged manipulation of energy prices in the West, including claims of false
reporting of trading data to publications that publish energy indices, and complaints requesting the FERC to reform or void various long-term power sales contracts. The FERC investigation with respect to us regarding false reporting to trade
publications concluded in July 2003. Additionally, in October 2004, the FERC approved an agreement providing for the settlement of certain FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001.
Finally, we are awaiting the outcome of an appeal to the Ninth Circuit Court of Appeals regarding the validity of our CDWR contract, which expired in December 2004. Please read Note 14Commitments and ContingenciesSummary of Material
Legal ProceedingsFERC and Related Regulatory InvestigationsRequests for Refunds beginning on page F-47 for further discussion of the settlement.



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 apply to sales in organized and bilateral markets and spot markets, as well as long-term sales. The remedies for violating the rules could include disgorgement of unjust profits, suspension or revocation of the
authority to sell at market-based rates and penalties. The extent to which the rules will affect the costs or other aspects of our operations is uncertain. However, we believe that our entities subject to the FERCs market behavior rules, which
consists of our entities with market-based rates for wholesale power sales and our entity with blanket natural gas sales certificate authority, are in compliance with these rules.



The FERCs market-based rate authority allows the sale of power at negotiated rates through the bilateral market or
within an organized energy market, conditioned on periodic re-review. In April 2004, the FERC issued an order concerning the ability of companies to sell electricity at market-based rates. In this order, the FERC



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adopted two new tests for assessing generation market power. If an applicant for market-based rate authority is found to possess generation market power
under these tests and is unsuccessful in challenging that finding, the applicant may either propose mitigation measures or adopt cost-based rates. If the FERC finds that the proposed mitigation measures fail to eliminate the ability to exercise
market power, the applicants market-based rate authority will be revoked and the applicant will be subject to cost-based default rates, or other cost-based rates proposed by the applicant and approved by the FERC. The FERC issued a follow up
order in May 2004 which (i) addressed the implementation process for pending and new market-based rate applications and (ii) established a timeline for entities with FERC market-based rate authority to provide the FERC with their market power
assessment. Despite challenges from numerous industry participants, in July 2004 the FERC upheld the April 2004 order. These orders require entities that were previously granted market-based rate authority by the FERC, including entities with
pending applications for re-review, to resubmit their applications in accordance with the new directive. Consequently, our entities with applications pending since February 2002 timely resubmitted their applications to the FERC on February 7, 2005,
as required.



In December 2004, the FERC ruled that once the
MISO becomes a single market and performs functions such as single central commitment and dispatch with FERC-approved market monitoring and mitigation (currently scheduled for April 1, 2005), MISO would be considered to have a single geographic
market for purposes of assessing generation market power. This ruling will enlarge the geographic area in which our DMG facilities would be evaluated for generation market power for the relevant period. Although we cannot predict with any certainty
whether our applications to renew our market based rate authority will be approved or the loss of revenues that would result from the imposition of cost-based rates, an adverse outcome with respect to these applications, and the resulting
requirement that we charge cost-based rates, could have a material adverse effect on our financial condition, results of operations and cash flows.



Electricity Marketing Regulation. Our electricity marketing operations are regulated pursuant to the FPA by the FERC with respect to rates,
terms and conditions of services and various reporting requirements. As discussed above, current FERC policies permit trading and marketing entities to market electricity at market-based rates.



Natural Gas Processing. Our natural gas processing operations
could become subject to FERC regulation. While the FERC has found that its jurisdiction under the NGA applies to plants that perform processing necessary for the safe and efficient transportation of natural gas, the FERC has historically held that
the extraction of liquid hydrocarbons for their economic value is not necessary for the safe and efficient transportation of gas. Thus, if a processing plants primary function is the extraction of natural gas liquids for their economic value,
the plant is not subject to the FERCs jurisdiction. We believe our gas processing plants are primarily involved in removing natural gas liquids for economic purposes and, therefore, are exempt from FERC jurisdiction. Nevertheless, the FERC has
made no specific finding as to our gas processing plants. As such, no assurance can be given that all of our processing operations will remain exempt from FERC regulation.



Natural Gas Gathering. The NGA exempts gas gathering facilities from the jurisdiction of the FERC, while
interstate transmission facilities remain subject to FERC jurisdiction, as described above. We believe our gathering facilities and operations meet the FERCs current tests for determining non-jurisdictional gathering facility status, although
the FERCs articulation and application of such tests have varied over time. Nevertheless, the FERC has made no specific findings as to the exempt status of any of our facilities. No assurance can be given that all of our gas gathering
facilities will remain classified as such and, therefore, remain exempt from FERC regulation. Some states regulate gathering facilities to varying degrees; generally, rates are not state-regulated.



Natural Gas Regulation.The transportation, storage and sale
for resale of natural gas in interstate commerce is subject to regulation by the FERC under the NGA and, to a lesser extent, the NGPA. The FERC regulates the rates interstate pipelines charge for interstate transportation and storage services. The
FERC also has jurisdiction over, among other things, the construction and operation of pipeline and related facilities used in



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the transportation and storage of natural gas in interstate commerce, including the extension, expansion, acquisition, disposition, or abandonment of such
facilities; maintenance of accounts and records; depreciation and amortization policies; and transactions with and conduct of interstate pipelines relating to affiliates. Venice Gathering System, in which we own a minority interest, is a regulated
interstate pipeline. Like other interstate pipelines, Venice Gathering System must comply with FERCs open-access transportation regulations. The FERC continues to review and modify its open-access regulations and some appeals are pending.



State Regulatory Reforms. Our domestic power
generation business is subject to various regulations from the states in which we operate. Proposed reforms to these regulations are proceeding in several states. In Illinois, both the regulators and the legislature are considering alternatives for
the regulation of the retail electric markets, including how the procurement of power and energy by electric utilities will be handled following the expiration of the mandatory transition period at the end of 2006. In addition, in Texas, the PUCT
has passed various rules regarding wholesale market re-design which will take effect during 2005 and 2006. In California, rules regarding resource adequacy requirements are expected to be determined by the California Public Utilities Commission, or
CPUC, during 2005 and fully implemented in 2006. Although we are not regulated by the CPUC, the results of some or all of these reforms could have a material affect on our operations.



Legislation. The U.S. Congress is considering passage of comprehensive energy legislation that will impact us.
We cannot predict with certainty if or when the U.S. Congress will finish its work on the energy legislation and send it to the President for signature or what effect any final legislation will have. Also, as noted above, in Illinois, both the
regulators and the legislature are considering alternatives for the regulation of the retail electric markets, including how the procurement of power and energy by electric utilities will be handled following the expiration of the mandatory
transition period at the end of 2006.



ENVIRONMENTAL AND
OTHER MATTERS



General. We incorporate
environmental protection and stewardship as an integral part of the design, construction, operation and maintenance of our facilities. An important part of all of these strategies and actions is our commitment to conduct all business activities in
an environmentally responsible manner.



Our operations are
subject to extensive federal, state and local statutes, rules and regulations governing the discharge of materials into the environment or otherwise relating to environmental, health and safety protection. Environmental laws and regulations,
including environmental regulators interpretations of these laws and regulations, are complex, change frequently and have become more stringent over time. Many environmental laws require permits from governmental authorities before
construction on a project may commence or before wastes or other materials may be discharged into the environment. The process for obtaining necessary permits can be lengthy and complex, and can sometimes result in the establishment of permit
conditions that make the project or activity for which the permit was sought either unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and
operating expenditures, and we may be required to incur costs to remediate contamination from past releases of wastes into the environment. Failure to comply with these statutes, rules and regulations may result in the assessment of administrative,
civil and even criminal penalties. Furthermore, the failure to obtain or renew an environmental permit could prevent operation of one or more of our facilities.



In general, the construction and operation of our facilities are subject to federal, state and local environmental laws, regulations and permitting
requirements governing the siting and operation of energy facilities, the discharge of pollutants and other materials into the environment, the protection of wetlands, endangered species, and other natural resources, the control and abatement of
noise and other similar requirements. A variety of permits are typically required before construction of a project commences, and additional permits are typically required for facility operation.



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Environmental Expenditures. Our aggregate expenditures for compliance with laws and
regulations related to the protection of the environment were approximately $25 million in 2004, compared to approximately $50 million in 2003 and approximately $82 million in 2002. We estimate that total environmental expenditures (both capital and
operating) in 2005 will be approximately $40 million. In 2005, the projected costs are associated primarily with enhanced air pollution controls and the handling of combustion byproducts. Changes in environmental regulations or the outcome of
litigation could result in additional requirements that could necessitate increased future spending. Please read Environmental and Other MattersThe Clean Air Act below for a discussion of the litigation brought by the
Environmental Protection Agency against us relating to activities at our Baldwin generating station in Illinois.



The Clean Air Act. The Clean Air Act and comparable state laws and regulations relating to air emissions impose responsibilities on owners
and operators of sources of air emissions, including requirements to obtain construction and operating permits and annual compliance and reporting obligations. In addition to the new source performance standards applicable to sulphur dioxide and
nitrogen oxides, the Clean Air Act requires that fossil-fueled plants have sufficient sulphur dioxide and, in some geographical regions of the country, nitrogen oxides emission allowances, as well as meet certain pollutant emission standards. Our
electric generation facilities are presently in compliance with these allowance and emission rate requirements. Although the impact of future air quality regulations cannot be predicted with certainty, these regulations are expected to become
increasingly stringent, particularly for electric power generating facilities. Current Clean Air Act requirements include the following:



| |  |  | The Clean Air Act Amendments of 1990 required a two-phase reduction by electric utilities in emissions of sulfur dioxide and nitrogen oxides by 2000 as part of an overall plan to
reduce acid rain in the eastern United States. Installation of control equipment and changes in fuel mix and operating practices have been completed at our facilities as necessary to comply with the emission reduction requirements of the acid rain
provision of the Clean Air Act Amendment of 1990.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In October 1998, the EPA issued a final rule on regional ozone control that required 22 eastern states and the District of Columbia to revise their State Implementation Plans to
significantly reduce emissions of nitrogen oxides. The compliance deadline for implementation of these emission reductions was May 31, 2004. In January 2000, the EPA finalized another ozone-related rule under Section 126 of the Clean Air Act that
has similar emission control requirements. The required capital expenditures and installation of the necessary emission control equipment to meet these requirements was completed before the compliance deadline; as a result, our power generation
system met the specified compliance deadlines for implementation. Portions of our GEN and NGL businesses are also subject to similar ozone rules applicable to the Houston area. We have plans in place to satisfy these requirements and could incur
capital expenditures of up to $23 million through 2007 pursuant to such plans.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Baldwin Station Litigation. Since November 1999, DMG has been the subject of an NOV from the EPA and a complaint filed by the EPA and the
DOJ in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations related to certain maintenance, repair and replacement activities at our Baldwin generating station. We have reached agreement with
the EPA, the DOJ, the State of Illinois and the environmental group intervenors on terms to settle the litigation. A consent decree was signed by all parties and lodged with the U.S. District Court for the Southern District of Illinois on March 7,
2005, and is subject to final approval of the Court following public comment. The consent decree requires us to (i) pay a $9 million civil penalty; (ii) fund several environmental projects in the additional aggregate amount of $15 million; and (iii)
invest $321 million through 2010, and $224 million from 2011 through 2012, respectively, in emission control projects at our Baldwin, Vermilion and Havana plants. Please read Note 14Commitments and ContingenciesSummary of Material Legal
ProceedingsBaldwin Station Litigation beginning on page F-45 for further discussion of this lawsuit and consent decree.



Remedial Laws. We are also subject to environmental requirements relating to the handling and disposal of toxic and hazardous materials,
including provisions of CERCLA and RCRA and similar state laws. CERCLA imposes liability, regardless of fault or the legality of the original conduct, on persons that contributed to the



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release of a hazardous substance into the environment. These persons include the current or previous owner and operator of a facility and
companies that disposed, or arranged for the disposal, of the hazardous substance found at a facility. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to public health or the environment and
to seek recovery for the costs of cleaning up the hazardous substances that have been released and for damages to natural resources from such responsible party. Further, it is not uncommon for neighboring landowners and other affected parties to
file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. CERCLA or RCRA could impose remedial obligations at a variety of our facilities.



Additionally, the EPA may develop new regulations that impose additional
requirements on facilities that store or dispose of non-hazardous fossil fuel combustion materials, including coal ash. If so, power generators like us may be required to change current waste management practices and incur additional capital
expenditures to comply with these regulations.



As a result of
their age, a number of our facilities contain quantities of asbestos insulation, other asbestos containing materials and lead-based paint. Existing state and federal rules require the proper management and disposal of these materials. We have
developed a management plan that includes proper maintenance of existing non-friable asbestos installations and removal and abatement of asbestos-containing materials where necessary because of maintenance, repairs, replacement or damage to the
asbestos itself.



Pipeline Safety. In addition to
environmental regulatory issues, the design, construction, operation and maintenance of some of our pipeline facilities are subject to the safety regulations established by the Secretary of the DOT pursuant to the NGPSA and the HLPSA, or by state
regulations meeting the requirements of the NGPSA and the HLPSA, or to similar statutes, rules and regulations in other jurisdictions. In December 2000, the DOT adopted new regulations requiring operators of interstate pipelines to develop and
follow an integrity management program that provides for continual assessment of the integrity of all pipeline segments that could affect so-called high consequence environmental impact areas, through periodic internal inspection,
pressure testing or other equally effective assessment means. An operators program to comply with the new rule must also provide for periodically evaluating the pipeline segments through comprehensive information analysis, remediating
potential problems found through the required assessment and evaluation, and assuring additional protection for the high consequence segments through preventative and mitigative measures. Although the requirements of this DOT rule have increased the
costs of pipeline operations, we do not believe that such costs are material to our financial condition or results of operations.



In the wake of the September 11, 2001 terrorist attacks on the United States, the Coast Guard has developed a security guidance document for marine
terminals and has issued a security circular that defines appropriate countermeasures for protecting them and explains how the Coast Guard plans to verify that operators have taken appropriate action to implement satisfactory security procedures and
plans. Using the guidelines provided by the Coast Guard, we have specifically identified certain of our facilities as marine terminals and therefore potential terrorist targets. In compliance with the Coast Guard guidance, we performed vulnerability
analyses on such marine terminals. Future analyses of our security measures may result in additional measures and procedures, which measures or procedures have the potential for increasing our costs of doing business. Regardless of the steps taken
to increase security, however, we cannot be assured that our marine terminals will not become the subject of a terrorist attack. Please read Operational Risks and Insurance beginning on page 25 for further discussion.



Health and Safety. Our operations are subject to the
requirements of OSHA and other comparable federal, state and provincial statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the Superfund Amendments and Reauthorization Act and similar
state statutes require that information be organized and maintained about hazardous materials used or produced in our operations. Some of this information must be provided to employees, state and local government authorities and citizens. We believe
we are currently in substantial compliance, and expect to continue to comply in all material respects, with these rules and regulations.



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Summary. Subject to final approval of the Baldwin consent decree announced in
March 2005 and described in Note 14Commitments and ContingenciesSummary of Material Legal ProceedingsBaldwin Station Litigation beginning on page F-45, management believes that it is in substantial compliance with, and is expected
to continue to comply in all material respects with, applicable environmental statutes, regulations, orders and rules. Further, to managements knowledge, other than the previously referenced complaints, there are no existing, pending or
threatened actions, suits, investigations, inquiries, proceedings or clean-up obligations by any governmental authority or third-party relating to any violations of any environmental laws with respect to our assets or pertaining to any
indemnification obligations with respect to properties we previously owned or operated, which could reasonably be expected to have a material adverse effect on our operations, cash flows and financial condition.



Ongoing Environmental Initiatives



Following is a description of ongoing environmental initiatives for which we
could incur significant capital expenditures, depending on the outcome.



Multi-Pollutant Air Emission Initiatives. In recent years, various federal and state legislative and regulatory multi-pollutant initiatives have been introduced to replace multiple overlapping regulatory regimes with a limited
number of programs and to streamline and simplify compliance planning.



There are currently numerous multi-pollutant initiatives being considered by state and federal governments which target many of the same pollutants but contain different compliance targets and timelines, such as the Clear Skies
initiative, the Clean Air Interstate Rule, or CAIR, and the Clean Air Mercury Rule. The major issues addressed by these initiatives include the transportation of ozone and particulate matter, visibility impairment or Regional Haze and
emissions of other pollutants, including mercury. These initiatives are aimed at long-term reductions of multiple pollutants produced from electric generating facilities. Some of these proposed initiatives, if enacted, would also impose controls on
emissions of the greenhouse gas carbon dioxide, which is emitted by all combustion sources.



Additional EPA initiatives include designation of areas as attainment, non-attainment or non-classifiable for purposes of (i) the new particulate matter 2.5 standard, or PM 2.5 standard, and (ii) the new 8-hour ozone
standard. The PM 2.5 standard is aimed at the reduction of fine (smaller than 2.5 microns in diameter) particulate matter, and would impose limitations on emissions of the precursor pollutants sulphur dioxide and nitrogen oxides. The new ozone
standard may result in additional nitrogen oxides reductions from power generating facilities in affected locations. Fossil fuel-fired power plants in the U.S. would be affected by the adoption of these programs or other multi-pollutant legislation
currently proposed by Congress addressing similar issues. Such programs would require compliance to be achieved either by the installation of pollution controls, the purchase of emission allowances, the curtailment of operations or some combination
thereof. Based on court-ordered deadlines and Congressional activity, we anticipate that some of these new requirements will be finalized in 2005. The final requirements would specify the target emission or cap levels as well as the timeframe in
which compliance must be achieved.



Water Issues.Our wastewater discharges are permitted under the Clean Water Act and analogous state laws. These permits are subject to review every five years. The state-issued water discharge permits associated with our DNE facilities expired in 1992.
However, under New York State law, the authorization arising under these permits remains in effect and allows for continued operation under the terms of the original permit, provided that a timely and sufficient application requesting renewal has
been filed as required. In May 1992, the then owner of the Danskammer facility filed a renewal application which we believe was timely and sufficient. In November 2002, several environmental groups filed suit in the Supreme Court of the State of New
York seeking, among other things, a declaratory judgment that the Danskammer water intake and discharge permit expired because of alleged deficiencies in the renewal application process. In September 2004, the Court ruled that the water intake and
discharge permit for our Danskammer facility is void, but stayed the enforcement of the decision pending further review by the Court or by the Appellate Division.



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In October 2004, we filed our appeal of the Courts decision with the Appellate Division, and we
intend to pursue vigorously our challenge to the Courts ruling voiding our permit. We will also continue to seek approval of our application to renew the water intake and discharge permit in proceedings before the New York State Department of
Environmental Conservation. If our appeal is ultimately unsuccessful, we may be required to suspend operations at our Danskammer facility pending receipt of final approval of the renewal of our water intake and discharge permit. We cannot predict
with any certainty the outcome of these proceedings; however, an adverse outcome, particularly a requirement that we suspend operations at our Danskammer facility for any period of time, could have a material adverse effect on our financial
condition, results of operations and cash flows.



In February
2004, the EPA issued final rules, which we refer to as Rule 316(b), establishing national standards aimed at protecting aquatic life at power generating facilities with existing cooling water intake structures. This rule requires that final
compliance plans be in place by January 2008. We believe that the requirements of Rule 316(b) are consistent with the provisions proposed in the Danskammer permit application. However, we expect that several of our other facilities will be impacted
by the requirements of Rule 316(b), and we cannot predict what plant modifications may be necessary to comply with this rule.



As with air quality, the requirements applicable to water quality are expected to increase in the future. A number of efforts are under way within the EPA
to evaluate water quality criteria for parameters associated with the by-products of fossil fuel combustion. These parameters include arsenic, mercury and selenium. Significant changes in these criteria could impact station discharge limits and
could require our facilities to install additional water treatment equipment.



Global Climate Change. The international treaty relating to global warming (commonly known as the Kyoto Protocol) would have required reductions in emissions of greenhouse gases, primarily carbon dioxide
and methane, by energy companies, including us, if adopted by the United States. As an alternative to Kyoto, which became effective (without ratification by the United States) in February 2005, current U.S. policy regarding greenhouse gases favors
voluntary reductions, increased operating efficiency, and continued research and technology development. Although several bills have been introduced in Congress that would compel reductions in carbon dioxide emissions, none have advanced through the
legislature and there are presently no federal mandatory greenhouse gas reduction requirements. The likelihood of any federal mandatory carbon dioxide emissions reduction program being adopted in the near future, and the specific requirements of any
such program, are uncertain. However, a number of states in the Northeast and the West are in the process of developing regulatory programs to manage greenhouse gas emissions. The final program requirements and subsequent impact to our operations
are not known at this time, but the Northeast states currently intend to finalize carbon dioxide emissions requirements for electric generating facilities during 2005. To the extent that any of the federal or state governments adopt or enact laws or
regulations mandating a substantial reduction in greenhouse gas emissions, such mandatory reduction requirements could have far-reaching and significant implications for industry in those jurisdictions, particularly the energy industry in which we
operate. Although we cannot predict the potential impact of such laws or regulations on our future financial condition, results of operations or cash flows, we will continue to monitor and participate in greenhouse gas policy developments in the
regions in which we operate and will continue to assess and respond to the potential impact on our business operations.



For all of the ongoing environmental matters described above, it is difficult to predict the form that proposed rules will ultimately take and the impact
that such rules, if approved, will have on our operations. It is possible that the result of these ongoing initiatives could require us and other similarly situated companies to incur material environmental compliance costs over a period of years,
beginning as early as 2005.



OPERATIONAL RISKS AND INSURANCE



We are subject to all risks inherent in the various
businesses in which we operate. These risks include, but are not limited to, explosions, fires, terrorist attacks, product spillage, weather, nature, inadequate maintenance of rights-of-way and the public, which could result in damage to or
destruction of operating assets and other



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property, or could result in personal injury, loss of life or pollution of the environment, as well as curtailment or suspension of operations at the
affected facility. We maintain general public liability, property/boiler and machinery, and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider
reasonable and not excessive given the current insurance market environment. The costs associated with these insurance coverages have increased significantly during recent periods, and may continue to do so in the future. The occurrence of a
significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types
of insurance that we believe to be prudent under current insurance industry market conditions, our potential inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial
stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates we consider commercially reasonable, particularly in the area of terrorism
insurance should the Terrorism Risk Insurance Act of 2002 not be extended beyond December 2005.



In our CRM segment, we also face market, price, credit and other risks relative to our exit from the CRM business. Please read Item 7A. Quantitative and
Qualitative Disclosures About Market Risk beginning on page 70 for further discussion of these risks.



In addition to these commercial risks, we also face the risk of damage to our reputation and financial loss as a result of inadequate or failed internal
processes and systems. A systems failure or failure to enter a transaction properly into the records and systems may result in an inability to settle a transaction in a timely manner or cause a contract breach. Our inability to implement the
policies and procedures that we have developed to minimize these risks could increase our potential exposure to damage to our reputation in the industries in which we compete and to financial loss. Please read Item 9A. Controls and Procedures
beginning on page 73 for further discussion of our internal control systems.



SIGNIFICANT CUSTOMER



For the years ended December 31, 2004, 2003 and 2002, approximately 20%, 20% and 19%, respectively, of our consolidated revenues and approximately 24%, 26% and 51%, respectively, of our consolidated cost of sales were derived from
transactions with ChevronTexaco and its subsidiaries. In addition, for the years ended December 31, 2004, 2003 and 2002, approximately 5%, 11% and 9%, respectively, of our consolidated revenues were derived from transactions with West Coast Power.
No other customer accounted for more than 10% of our consolidated revenues or consolidated cost of sales during 2004, 2003 or 2002.



EMPLOYEES



At December 31, 2004, we had approximately 643 employees at our administrative offices and approximately 1,580 employees at our operating facilities.
Approximately 844 employees at facilities operated by us are subject to collective bargaining agreements with various unions. We believe relations with our employees are satisfactory.



|Item 2. | Properti
es
|------- | -----------



We
have included descriptions of the location and general character of our principal physical operating properties by segment in Item 1. Business beginning on page 1. Those descriptions are incorporated herein by this reference.
Substantially all of our assets, including the physical operating properties we own, are pledged as collateral with respect to our amended credit facility and our second priority senior secured notes on a first lien and second lien, respectively.
Please read Note 11Debt beginning on page F-34 for further discussion of the amended credit facility.



26



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##### Table of Contents

##### Index to Financial Statements

Our principal executive office located in Houston, Texas is held under a lease that expires in December
2007. We also lease additional offices in the states of California, Florida, Georgia, Illinois, Massachusetts, and Texas.



|Item 3. | Legal Proceedings
|------- | -----------------



For a description of our material legal proceedings, please read Note 14Commitments and Contingencies beginning on page F-43, which is incorporated
herein by reference.



|Item 4. | Submission of Matters to a Vote of Security Holders
|------- | ---------------------------------------------------



Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.



PART II



|Item 5. | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities
|------- | -----------------------------------------------------------------------------------------------------------



All of our outstanding equity securities are held by our parent, Dynegy.
There is no established trading market for such securities and they are not traded on any exchange.



Securities Authorized for Issuance Under Equity Compensation Plans



We have no equity compensation plans pursuant to which our employees are granted stock options or other equity compensation. Our employees do, however,
receive stock-based compensation pursuant to plans maintained by our parent, Dynegy. Please read Dynegys Annual Report on Form 10-K for the fiscal year ended December 31, 2004 for further discussion of these plans.



|Item 6. | Selected Financial Data
|------- | -----------------------



The selected financial information presented below was derived from, and is qualified by reference to, our Consolidated Financial Statements, including
the notes thereto, contained elsewhere herein. The selected financial information should be read in conjunction with the Consolidated Financial Statements and related notes and Managements Discussion and Analysis of Financial Condition and
Results of Operations.



As discussed in the Explanatory Note to
the accompanying Consolidated Financial Statements, the historical information in the accompanying Consolidated Financial Statements has been restated. Please read the Explanatory Note to the accompanying Consolidated Financial Statements beginning
on page F-8 for additional information about this restatement. The selected financial data that follows has been adjusted to reflect this restatement.



27



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##### Index to Financial Statements

Dynegy Holdings Selected Financial Data



|                                                     |  |                                      |        |   |            |   |        |               |  |   |            |   |  |            |        |   |  |   |        |  
|---------------------------------------------------- |  | ------------------------------------ | ------ | - | ---------- | - | ------ | ------------- |  | - | ---------- | - |  | ---------- | ------ | - |  | - | ------ | -
|                                                     |  | Year Ended December 31,              |       
|                                                     |  | 2004                                 |        |   | 2003       |   |        | 2002          |  |   | 2001       |   |  | 2000       |       
|                                                     |  |                                      |        |   | (Restated) |   |        | (Restated)    |  |   |            |   |  | (Restated) |       
|                                                     |  | (in millions, except per share data) |       
|Statement of Operations Data (1):                    |  |                                      |        |   |            |   |        |               |  |   |            |   |  |            |        |   |  |   |        |  
|Revenues                                             |  | $                                    | 5,351  |   |            | $ | 4,714  |               |  | $ | 4,245      |   |  | $          | 7,789  |   |  | $ | 8,211  |  
|Depreciation and amortization expense                |  |                                      | (312   | ) |            |   | (330   | )             |  |   | (270       | ) |  |            | (294   | ) |  |   | (237   | )
|Goodwill impairment                                  |  |                                      |       |   |            |   |       |               |  |   | (640       | ) |  |            |       |   |  |   |       |  
|Impairment and other charges                         |  |                                      | (29    | ) |            |   | (4     | )             |  |   | (184       | ) |  |            |       |   |  |   |       |  
|General and administrative expenses                  |  |                                      | (307   | ) |            |   | (293   | )             |  |   | (255       | ) |  |            | (350   | ) |  |   | (226   | )
|Operating income (loss)                              |  |                                      | 56     |   |            |   | (255   | )             |  |   | (1,045     | ) |  |            | 776    |   |  |   | 650    |  
|Interest expense                                     |  |                                      | (359   | ) |            |   | (338   | )             |  |   | (187       | ) |  |            | (137   | ) |  |   | (95    | )
|Income tax benefit (expense)                         |  |                                      | 97     |   |            |   | 191    |               |  |   | 366        |   |  |            | (308   | ) |  |   | (199   | )
|Net income (loss) from continuing operations         |  |                                      | (97    | ) |            |   | (264   | )             |  |   | (992       | ) |  |            | 457    |   |  |   | 358    |  
|Income (loss) from discontinued operations (3)       |  |                                      | (7     | ) |            |   | (12    | )             |  |   | (100       | ) |  |            | (19    | ) |  |   | 40     |  
|Cumulative effect of change in accounting principles |  |                                      |       |   |            |   | 42     |               |  |   |           |   |  |            | 2      |   |  |   |       |  
|Net income (loss)                                    |  | $                                    | (104   | ) |            | $ | (234   | )             |  | $ | (1,092     | ) |  | $          | 440    |   |  | $ | 398    |  
|Cash Flow Data:                                      |  |                                      |        |   |            |   |        |               |  |   |            |   |  |            |        |   |  |   |        |  
|Cash flows from operating activities                 |  | $                                    | (160   | ) |            | $ | 760    |               |  | $ | 26         |   |  | $          | 176    |   |  | $ | 408    |  
|Cash flows from investing activities                 |  |                                      | (211   | ) |            |   | (423   | )             |  |   | 804        |   |  |            | (1,341 | ) |  |   | (951   | )
|Cash flows from financing activities                 |  |                                      | 289    |   |            |   | (652   | )             |  |   | (282       | ) |  |            | 1,300  |   |  |   | 528    |  
|Capital expenditures, acquisitions and investments   |  |                                      | (219   | ) |            |   | (209   | )             |  |   | (766       | ) |  |            | (2,600 | ) |  |   | (959   | )
|                                                     | 
|                                                     |  | December 31,                         |       
|                                                     |  | 2004                                 |        |   | 2003       |   |        | 2002          |  |   | 2001       |   |  | 2000       |       
|                                                     |  |                                      |        |   | (Restated) |   |        | (Restated)    |  |   | (Restated) |   |  | (Restated) |       
|                                                     |  |                                      |        |   |            |   |        | (in millions) |  |   |            |   |  |            |       
|Balance Sheet Data (2):                              |  |                                      |        |   |            |   |        |               |  |   |            |   |  |            |        |   |  |   |        |  
|Current assets                                       |  | $                                    | 3,082  |   |            | $ | 2,806  |               |  | $ | 7,050      |   |  | $          | 8,669  |   |  | $ | 10,548 |  
|Current liabilities                                  |  |                                      | 1,773  |   |            |   | 1,982  |               |  |   | 6,469      |   |  |            | 8,019  |   |  |   | 9,826  |  
|Property and equipment, net                          |  |                                      | 6,130  |   |            |   | 6,302  |               |  |   | 6,415      |   |  |            | 6,767  |   |  |   | 5,117  |  
|Total assets                                         |  |                                      | 10,158 |   |            |   | 10,293 |               |  |   | 16,521     |   |  |            | 19,594 |   |  |   | 19,071 |  
|Long-term debt (excluding current portion)           |  |                                      | 4,107  |   |            |   | 3,664  |               |  |   | 3,276      |   |  |            | 2,707  |   |  |   | 1,635  |  
|Notes payable and current portion of long-term debt  |  |                                      | 34     |   |            |   | 150    |               |  |   | 484        |   |  |            | 256    |   |  |   |       |  
|Subordinated debentures                              |  |                                      |       |   |            |   |       |               |  |   | 200        |   |  |            | 200    |   |  |   | 200    |  
|Minority interest (4)                                |  |                                      | 106    |   |            |   | 121    |               |  |   | 146        |   |  |            | 1,003  |   |  |   | 977    |  
|Total equity                                         |  |                                      | 2,998  |   |            |   | 3,154  |               |  |   | 3,358      |   |  |            | 4,430  |   |  |   | 3,909  |  

---

|(1) | The following acquisitions were accounted for in accordance with the purchase method of accounting and the results of operations attributable to the acquired businesses are included
in our financial statements and operating statistics beginning on the acquisitions effective date for accounting purposes:
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

| |  |  | Northern NaturalFebruary 1, 2002 and
| | - |  | -------------------------------------

| |  |  | BGSLDecember 1, 2001.
| | - |  | ----------------------

|(2) | The Northern Natural and BGSL acquisitions were each accounted for under the purchase method of accounting. Accordingly, the purchase price was allocated to the assets acquired and
liabilities assumed based on their estimated fair values as of the effective dates of each transaction. See note (1) above for respective effective dates.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Discontinued operations includes the results of operations from the following businesses:
|--- | -----------------------------------------------------------------------------------------

| |  |  | Northern Natural (sold third quarter 2002);
| | - |  | -------------------------------------------

| |  |  | U.K. StorageHornsea facility (sold fourth quarter 2002) and Rough facility (sold fourth quarter 2002);
| | - |  | -------------------------------------------------------------------------------------------------------

| |  |  | Global Liquids (sold fourth quarter 2002); and
| | - |  | ----------------------------------------------

| |  |  | U.K. CRM (substantially liquidated in first quarter 2003).
| | - |  | ----------------------------------------------------------

|(4) | The 2001 and 2000 amounts include amounts relating to the Black Thunder Secured Financing. This financing involved (i) our investment of $100 million in June 2000 in Catlin
Associates, L.L.C., an entity which holds indirect economic interests in some of our Midwest generation assets, including the coal-fired generation units in Illinois, and (ii) our obligation to purchase the $850 million interest held by a third
party on or before June 2005. We repaid the balance owed under this financing in August 2003.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Index to Financial Statements

|Item 7. | Managements Discussion and Analysis of Financial Condition and Results of Operations
|------- | -------------------------------------------------------------------------------------



The following discussion should be read together with the audited
consolidated financial statements and the notes thereto included in this report.



OVERVIEW



We are a
holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily in two areas of the energy industry: power generation and natural gas liquids. Because of the
diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. We also separately report the results of our customer risk management business, which primarily
consists of our four remaining power tolling arrangements as well as our gas transportation contracts, and legacy gas and power trading positions. Our consolidated financial results also reflect corporate-level expenses such as general and
administrative, interest and infrastructure depreciation and amortization, but because of their nature, these items are not reported as a separate segment.



Following is a brief discussion of each of our three current business segments, including a list of key factors that have affected, and are expected to
continue to affect, their respective earnings and cash flows. We also present a brief discussion of our corporate-level expenses. This Overview section concludes with a discussion of strategic growth opportunities and a summary of our
current liquidity position and items that could impact our liquidity position in 2005 and beyond. Please note that this Overview section is merely a summary and should be read together with the remainder of this Item 7. Managements
Discussion and Analysis of Financial Condition and Results of Operations, as well as our audited consolidated financial statements, including the notes thereto, and the other information included in this report.



Power Generation. Our power generation business owns or leases
approximately 11,700 MWs of net generating capacity located in six regions of the United States. Our power generating fleet is diversified by facility type (base load, intermediate and peaking), fuel source and geographic location. We generate
earnings and cash flows in this business through sales of energy and capacity.



The primary factors impacting our power generation earnings and cash flows are the prices for power, natural gas and coal, which in turn are largely driven by supply and demand. Demand for power can vary regionally
due to, among other things, weather and general economic conditions. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation. We also are
impacted by the relationship between prices for power and natural gas, commonly referred to as the spark spread, and its impact on the cost of generating electricity. However, we believe that our significant coal-fired and fuel oil
generating facilities partially mitigate our sensitivity to changes in the spark spread, in that coal and fuel oil prices are relatively stable and insensitive to changes in gas prices, and position us for potential increases in earnings and cash
flows in an environment where both power and gas prices increase. We have entered into long-term coal supply and transportation agreements for our Midwest fleet. Please read Liquidity and Capital ResourcesInternal Liquidity
SourcesCash Flows from Operations beginning on page 39 for a discussion of our views on the current pricing environment and its anticipated long-term recovery.



29



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##### Index to Financial Statements

Other factors that have impacted, and are expected to continue to impact, earnings and cash flows for
this business include:



| |  |  | our ability to control our capital expenditures, which primarily are limited to maintenance, safety, environmental and reliability projects, and to control other costs through
disciplined management and safe, efficient operations;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our ability to optimize our assets through hedging activities and similar transactions, which is affected by general market liquidity and the need to satisfy counterparties
collateral requirements given our non-investment grade credit ratings; and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our ability to enter into new sales contracts and to renew our existing contracts.
| | - |  | ----------------------------------------------------------------------------------



Natural Gas Liquids. Our natural gas liquids business owns natural gas gathering and processing, or upstream,
assets in key producing areas of Louisiana, New Mexico and Texas. This business also owns integrated downstream assets used to fractionate, store, terminal, transport, distribute and market natural gas liquids. These downstream assets generally are
connected to and supplied by our and third parties upstream assets and are located in Mont Belvieu, Texas, the hub of the U.S. natural gas liquids business, and West Louisiana.



We generate earnings and cash flows in the upstream business by selling our gathering, processing and treating services to
producers. We generate earnings and cash flows in our downstream business through sales of our fractionation, storage, transportation and terminalling services and sales of natural gas liquids through our marketing operations.



The earnings and cash flows that we generate in this business are sensitive
to natural gas and natural gas liquids prices and, to a lesser extent, the relationship between the two, commonly referred to as the frac spread. Our current contract mix has minimal exposure to frac spread risk. Please read Item 1.
BusinessSegment DiscussionNatural Gas LiquidsUpstream Business beginning on page 9 for a detailed discussion of our current upstream contract portfolio.



In addition to commodity prices, other factors that have impacted, and are expected to continue to impact, the earnings and
cash flows for this business include:



| |  |  | our ability to control our capital expenditures, which primarily are limited to maintenance, safety and reliability projects, and control other costs through disciplined management
and safe, efficient operations;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | reduced market liquidity and our obligation to post collateral to or prepay counterparties because of our non-investment grade credit ratings, which limit our ability to contract
forward physically for some of our natural gas liquids products;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | producer drilling activity, which is significantly affected by commodity prices;
| | - |  | --------------------------------------------------------------------------------



| |  |  | a varying frac spread environment and the resulting impact on volumes available for fractionation, distribution and marketing;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



| |  |  | the petrochemical industrys need for and utilization of our natural gas liquids as feedstocks and related natural gas liquids facilities to provide distribution and logistics
services;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our ability to manage our natural gas liquids inventories efficiently; and
| | - |  | --------------------------------------------------------------------------



| |  |  | our ability to meet customer demands for timely delivery and transportation.
| | - |  | ----------------------------------------------------------------------------



Customer Risk Management.Our customer risk management business primarily consists of the Gregory power tolling arrangement, which
expires in July 2005, the Kendall power tolling arrangement, the effect of which we have mitigated through November 2008, the Independence power tolling arrangement and the Sterlington power tolling arrangement, as well as our gas transportation
contracts and legacy gas and power



30



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##### Index to Financial Statements

trading positions. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract
TerminationsKendall beginning on page F-19 below for further discussion of the Kendall toll. Our Independence power tolling arrangement and the related gas transportation contracts became related party transactions upon Dynegys
consummation of the Sithe Energies acquisition. Please read Note 20Subsequent Events beginning on page F-70 for further discussion. We have significant, long-term fixed obligations associated with our tolling arrangements, which obligations
may substantially exceed the earnings and cash flows we expect to generate in connection with these arrangements. Our ability to mitigate partially the negative impact of these arrangements on our earnings and cash flows depends on the price of
power and the spark spread in the regions where the plants covered by those tolls are located. It also will be significantly impacted by our ability to restructure or terminate one or more of our remaining power tolling arrangements, which we expect
would require a significant cash payment.



Regarding our legacy
gas and power trading positions, we have substantially reduced the size of our portfolio relative to when we were primarily a marketing and trading company. Please read Item 1. BusinessSegment DiscussionCustomer Risk Management beginning
on page 17 for further discussion.



Other.
Beginning January 1, 2003, Other includes corporate-level items that were previously allocated to our operating segments. Significant items impacting future earnings and cash flows include:



| |  |  | interest expense, which increased beginning in 2003 as a result of our refinancing and restructuring activities and will continue to reflect our non-investment grade credit ratings;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | general and administrative costs, with respect to which we have implemented a number of initiatives that have yielded savings; general and administrative costs also will be impacted
by, among other things, (i) any future corporate-level litigation reserves or settlements and (ii) potential funding requirements under our pension plans; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | income taxes, with respect to which we currently only pay minimal state and foreign income taxes; income taxes will also be impacted by our ability to realize our significant
deferred tax assets, including loss carryforwards.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition, dividends associated with our outstanding preferred stock will continue to affect our earnings available to our common shareholders.



Strategic Growth Opportunities. With only a few significant legacy matters remaining to be addressed, more of our companys resources
are available to continue our efforts to operate our energy businesses safely, reliably and efficiently, to manage the costs across our organization and to deliver value to our investors. We are also continuing to focus on identifying and evaluating
strategic growth opportunities, particularly organic or bolt-on projects, such as the conversion of our Havana power generating facility to lower-cost and lower emission PRB coal, to improve the operational performance and efficiency of
certain assets, enabling us to realize costs savings and to capture even more of the benefit of increases in commodity prices. Such opportunities may also include merger and acquisition activities, which we discuss and evaluate as part of our
ongoing business strategy. In the power generation industry, in particular, we believe that consolidation is likely to occur within the next several years. We further believe that our efficient and scalable operations platform, together with our
multi-fuel capabilities and multi-region presence, position us to benefit from opportunities that might arise in connection with any acquisition or consolidation transactions. However, our desire or ability to pursue any such opportunities is
subject to a number of factors beyond our control. As such, we cannot guarantee that any such opportunities will be available to us, nor can we predict with any degree of certainty the impact of any such opportunities on our financial condition or
results of operations.



Liquidity. As of March
11, 2005, we had cash on hand of $204 million and available borrowing capacity of $611 million, for total liquidity of $815 million. During 2004, we continued to reduce our debt and other obligations while maintaining liquidity between $780 million
and $1.3 billion.



31



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##### Table of Contents

##### Index to Financial Statements

For the next twelve months, assuming continuation of the current commodity pricing environment, we expect
that our operating cash flows will be positive, but insufficient to satisfy our capital expenditures and debt maturities. However, we believe that our cash on hand together with capacity under our $700 million revolving credit facility, will be
sufficient to discharge these obligations. To further our deleveraging efforts, other capital-raising activities may be considered, including potential equity issuances by Dynegy.



Over the longer term and through the anticipated recovery of the U.S. power markets, we expect to maintain sufficient
liquidity to satisfy our debt and commercial obligations and provide collateral support through operating cash flows, capacity under our revolving credit facility (or any refinancing thereof), as well as proceeds from anticipated refinancings of
debt maturities.



Our ability to generate operating cash flows
will be impacted by a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for power and natural gas, and the success of our ongoing efforts to manage operating costs, particularly fuel
requirements, and capital expenditures. Our ability to refinance our substantial debt maturities is primarily dependent upon our ability to generate operating cash flows, which is subject to the factors described in the preceding sentence. Over the
longer term we believe that power prices will improve in some or all of the regions in which we operate as the supply-demand imbalance for power decreases. Much of our restructuring work has positioned us to benefit from earnings and growth
opportunities associated with an expected recovery in the U.S. power markets. Additionally, our NGL business is currently operating in a highly favorable pricing environment. Our future financial condition and results of operations will be
materially adversely affected if the U.S. power markets fail to recover in accordance with our expectations or if we experience significant, prolonged pricing deterioration below price levels experienced over the last few years in our NGL segment.



Our longer term liquidity position and financial condition
will also be significantly impacted by the availability of, and our ability to pursue, strategic growth opportunities, which may include bolt-on projects or industry consolidation. However, our desire or ability to pursue any such
opportunities is subject to a number of factors beyond our control. As such, we cannot guarantee that any such opportunities will be available to us, nor can we predict with any degree of certainty the impact of any such opportunities on our
financial condition or results of operations.



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



LIQUIDITY AND CAPITAL RESOURCES



Overview



Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed
capacity payments and contractual obligations, capital expenditures, legal settlements and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural
gas, coal and natural gas liquids, facility maintenance costs 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 that we engage in these activities prospectively.



Debt Obligations



During 2004, we continued our efforts to reduce our debt maturities and extend our maturity profile, which included the following transactions:



| |  |  | Replacement of our $1.1 billion credit facility, scheduled to mature in February 2005, with a new $1.3 billion credit facility comprised of a revolving credit facility and a term
loan, which are scheduled to mature in May 2007 and May 2010, respectively;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



32



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##### Index to Financial Statements

| |  |  | Prepayment of all outstanding indebtedness and other amounts owed under the ABG Gas Supply Financing, primarily through use of $154 million in proceeds from the May 2004 term loan;
and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Payment of $81 million in connection with the termination of the Tilton capital lease.
| | - |  | --------------------------------------------------------------------------------------



As a result of our efforts, our aggregate maturities for long-term debt as of December 31, 2004 were reduced to $24 million
in 2005, $28 million in 2006, $188 million in 2007 (excluding the maturity of our $700 million revolving credit facility), $231 million in 2008, $6 million in 2009 and approximately $3.7 billion thereafter. Maturities for 2005 represent our
principal payments on our term loan and our 8.125% senior notes and exclude the non-cash amortization of basis adjustments included in Notes payable and current portion of long-term debt on our consolidated balance sheets.



We have incurred significant debt service obligations in the course of
extending our debt maturities. We also are subject to covenants in the related transaction agreements that are substantially more restrictive than those typically found in financing agreements of borrowers with investment grade credit ratings,
including covenants limiting our ability to incur additional debt and sell certain assets. We are currently in compliance with these restrictive covenants, but our future financial condition and results of operations could be materially adversely
affected by our ability to comply with these restrictive covenants in the future.



The following table depicts our consolidated third-party debt obligations, including the principal-like maturities associated with the DNE leveraged lease, and the extent to which they are secured as of December 31,
2004 and 2003:



|                                       |  |                  |       |   |                  |   |       |  
|-------------------------------------- |  | ---------------- | ----- | - | ---------------- | - | ----- | -
|                                       |  | December 31,2004 |       |   | December 31,2003 |  
|                                       |  | (in millions)    |      
|First Secured Obligations              |  | $                | 1,551 |   |                  | $ | 1,208 |  
|Second Secured Obligations             |  |                  | 1,750 |   |                  |   | 1,750 |  
|Unsecured Obligations                  |  |                  | 1,606 |   |                  |   | 1,619 |  
|                                       |  |                  |       |   |                  |   |       |  
|Total Obligations                      |  | $                | 4,907 |   |                  | $ | 4,577 |  
|                                       |  |                  |       |   |                  |   |       |  
|Less: DNE Lease Financing (2)          |  |                  | (771  | ) |                  |   | (758  | )
|Other (1)                              |  |                  | 5     |   |                  |   | (5    | )
|                                       |  |                  |       |   |                  |   |       |  
|Total Notes Payable and Long-term Debt |  | $                | 4,141 |   |                  | $ | 3,814 |  
|                                       |  |                  |       |   |                  |   |       |  

---

|(1) | Consists of net premiums (discounts) on debt of $5 million at December 31, 2004 and December 31, 2003; and the $10 million difference between the carrying value of the Tilton
capital lease and the purchase obligation of $81 million at December 31, 2003.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Represents present value of future lease payments discounted at 10%.
|--- | --------------------------------------------------------------------



33



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##### Table of Contents

##### Index to Financial Statements

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 March 11, 2005, December 31, 2004 and December 31, 2003:



|                  |  |                |     |                   |   |                  |  |   |    
|----------------- |  | -------------- | --- | ----------------- | - | ---------------- |  | - | ---
|                  |  | March 11, 2005 |     | December 31, 2004 |   | December 31,2003
|                  |  | (in millions) 
|By Segment:       |  |                |     |                   |   |                  |  |   |    
|GEN               |  | $              | 176 |                   | $ | 192              |  | $ | 136
|CRM               |  |                | 84  |                   |   | 94               |  |   | 121
|NGL               |  |                | 186 |                   |   | 167              |  |   | 179
|Other             |  |                | 9   |                   |   | 7                |  |   | 8  
|                  |  |                |     |                   |   |                  |  |   |    
|Total             |  | $              | 455 |                   | $ | 460              |  | $ | 444
|                  |  |                |     |                   |   |                  |  |   |    
|By Type:          |  |                |     |                   |   |                  |  |   |    
|Cash              |  | $              | 375 |                   | $ | 376              |  | $ | 256
|Letters of Credit |  |                | 80  |                   |   | 84               |  |   | 188
|                  |  |                |     |                   |   |                  |  |   |    
|Total             |  | $              | 455 |                   | $ | 460              |  | $ | 444
|                  |  |                |     |                   |   |                  |  |   |    



The increase in
collateral postings for the GEN segment of $40 million is primarily a result of increased commodity prices, particularly the price of electricity, as well as increased coal purchases and collateral posted in connection with new electric capacity
sales transactions. Additionally, the increase for the NGL segment is primarily due to timing, largely offset by the return in 2004 of the collateral posted at year end 2003 related to the purchase of natural gas liquids inventory transported by
barge. This increase in our collateral postings was offset by reductions in collateral postings in our other segments, including the $37 million reduction of collateral posted in support of our CRM segment primarily resulting from (i) the
termination of the ABG Gas Supply contract in August 2004 and (ii) the execution of a master netting agreement with a significant counterparty, which were offset by $22.5 million of collateral posted in connection with an existing natural gas
transaction.



While the total amount of collateral posted
decreased, we have increased the proportion of cash used to satisfy counterparty collateral demands. As of December 31, 2003, approximately 58% of the aggregate collateral posted (or approximately $256 million) consisted of cash, compared to
approximately 82% cash collateral (or approximately $376 million) as of December 31, 2004 and 82% cash collateral (or approximately $375 million) as of March 11, 2005. This increase is the result of the termination of the ABG Gas Supply contract and
our ongoing efforts to post cash collateral in lieu of letters of credit, to the extent economical, to avoid paying the 4.00% per annum letter of credit fee payable under our revolving credit facility.



Going forward, we expect counterparties collateral demands to continue
to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness. Considering current commodity price estimates, our credit ratings, the timing of contract settlements, the
anticipated level of new capacity sales agreements and forward hedging transactions, we believe that collateral requirements will be between $375 million and $400 million at year-end 2005. We believe that we have sufficient capital resources to
satisfy counterparties collateral demands, including those for which no collateral is currently posted, for at least the next twelve months. Over the longer term, we expect to achieve incremental reductions associated with the completion of
our exit from the CRM business.



Disclosure of Contractual Obligations and
Contingent Financial Commitments



We incur contractual
obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contracts, such



34



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##### Index to Financial Statements

as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly
supported by related operating activities. Financial commitments represent contingent obligations, such as financial guarantees, that become payable only if specified events occur. Details on these obligations are set forth below.



Contractual Obligations



The following table summarizes our contractual obligations as of December
31, 2004. Cash obligations reflected are not discounted and do not include related interest, accretion or dividends.



|                                           |  |                        |       |      |   |      |  |      |     |      |   |      |  |            |     |  |   |     |  |   |      
|------------------------------------------ |  | ---------------------- | ----- | ---- | - | ---- |  | ---- | --- | ---- | - | ---- |  | ---------- | --- |  | - | --- |  | - | -----
|                                           |  | Payments Due by Period
|                                           |  | Total                  |       | 2005 |   | 2006 |  | 2007 |     | 2008 |   | 2009 |  | Thereafter
|Long-Term Debt (including Current Portion) |  | $                      | 4,141 |      | $ | 34   |  | $    | 28  |      | $ | 188  |  | $          | 231 |  | $ | 6   |  | $ | 3,654
|Operating Leases                           |  |                        | 1,619 |      |   | 92   |  |      | 93  |      |   | 140  |  |            | 158 |  |   | 161 |  |   | 975  
|Capacity Payments                          |  |                        | 2,242 |      |   | 208  |  |      | 191 |      |   | 194  |  |            | 200 |  |   | 201 |  |   | 1,248
|Conditional Purchase Obligations           |  |                        | 124   |      |   | 14   |  |      | 13  |      |   | 14   |  |            | 14  |  |   | 14  |  |   | 55   
|Pension Funding Obligations                |  |                        | 73    |      |   | 28   |  |      | 19  |      |   | 26   |  |            |    |  |   |    |  |   |     
|                                           |  |                        |       |      |   |      |  |      |     |      |   |      |  |            |     |  |   |     |  |   |      
|Total Contractual Obligations              |  | $                      | 8,199 |      | $ | 376  |  | $    | 344 |      | $ | 562  |  | $          | 603 |  | $ | 382 |  | $ | 5,932
|                                           |  |                        |       |      |   |      |  |      |     |      |   |      |  |            |     |  |   |     |  |   |      



Long-Term Debt
(including Current Portion). Total amounts of Long-Term Debt (including Current Portion) are included in the December 31, 2004 Consolidated Balance Sheet. For additional explanation, please read Note 11Debt beginning on page F-34.



Additionally, we have entered into various joint ventures
principally to share risk or optimize existing commercial relationships. These joint ventures maintain independent capital structures and, where necessary, have financed their operations on a non-recourse basis to us. Please read Note
9Unconsolidated Investments beginning on page F-30 for further discussion of these joint ventures.



Operating Leases.Operating leases includes the minimum lease payment obligations associated with our DNE leveraged lease. For
additional information, please read Liquidity and Capital ResourcesOff-Balance Sheet ArrangementsDNE Leveraged Lease beginning on page 37. Amounts also include minimum lease payment obligations associated with office
and office equipment leases.



In addition, we are party to two
charter party agreements relating to VLGCs previously utilized in our global liquids business. The aggregate minimum base commitments of the charter party agreements are approximately $13 million each year for the years 2005 through 2007, and
approximately $79 million through lease expiration. The charter party rates payable under the two charter party agreements float in accordance with market based rates for similar shipping services. The $13 million and $79 million numbers set forth
above are based on the minimum obligations set forth in the two charter party agreements. The primary term of one charter is through August 2013 while the primary term of the second charter is through August 2014. On January 1, 2003, in connection
with the sale of our global liquids business, we sub-chartered both VLGCs to a wholly owned subsidiary of Transammonia Inc. The terms of the sub-charters are identical to the terms of the original charter agreements. We are currently in negotiations
with the owners of the VLGCs and their lenders to obtain a novation and release of our operating subsidiary from the two charter party agreements and partial releases of our parent guarantees. Until such time as the novations and partial releases
are granted, we continue to rely on the sub-charters with a subsidiary of Transammonia to satisfy the obligations of our two charter party agreements. To date, the subsidiary of Transammonia has complied with the terms of the sub-charter agreements.



Capacity Payments.Capacity payments include
future payments aggregating $2.1 billion under our four remaining power tolling arrangements, including our Gregory tolling arrangement which expires in July 2005, as further described in Item 1. BusinessSegment DiscussionCustomer Risk
Management beginning on page 17.



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This amount includes the fixed payments associated with a derivative instrument related to the Independence tolling arrangement, which is reflected at its
fair value on our Consolidated Balance Sheets in Risk-Management Liabilities, as well as amounts relating to contracts that are accounted for on an accrual basis. At December 31, 2004, approximately $295 million of fixed payments have been reflected
in the fair value of the Independence derivative instrument. Effective February 1, 2005, Independence became a wholly owned subsidiary of Dynegy, our parent.



In November 2004, we entered into a back-to-back power purchase agreement under which a subsidiary of Constellation Energy receives our rights
to capacity and energy under the Kendall tolling arrangement for a four year term expiring effectively in November 2008. Although we are still obligated under the Kendall toll, we will receive approximately $161 million in aggregate cash payments
from Constellation to offset our fixed payment obligations under the Kendall toll through November 2008, which payment obligations are reflected in the table above. We paid Constellation $117.5 million in cash in connection with this transaction.
Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsKendall beginning on page F-19 below for further discussion.



We are exploring opportunities to renegotiate or terminate one or more of our
remaining long-term tolling arrangements on terms we consider economical. Please read Results of Operations2005 OutlookCRM Outlook beginning on page 59 for further discussion of the anticipated effects of these
arrangements on our future results of operations.



In addition,
capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $170 million.



Conditional Purchase Obligations.Amounts relate to our co-sourcing agreement with Accenture Ltd. This 10-year agreement runs through 2013
and may be cancelled after two years upon the payment of a termination fee which ranges from $6 million for the first quarter 2005, declining to $2 million through 2013. This termination fee is in addition to amounts due for services provided
through the termination date.



Pension Funding
Obligations.Amounts include estimated defined benefit pension funding obligations for 2005 ($28 million), 2006 ($19 million) and 2007 ($26 million). Although we expect to incur significant funding obligations subsequent to 2007, such
amounts have not been included in this table because our estimates are imprecise.



Contingent Financial Obligations



The following table provides a summary of our contingent financial obligations as of December 31, 2004 on an undiscounted basis. These obligations represent contingent obligations that may require a payment of cash
upon the occurrence of specified events.



|                            |  |                      |     |                 |   |           |  |           |   |                  |   |   |  |   |  
|--------------------------- |  | -------------------- | --- | --------------- | - | --------- |  | --------- | - | ---------------- | - | - |  | - | -
|                            |  | Expiration by Period
|                            |  | Total                |     | Less than 1Year |   | 1-3 Years |  | 3-5 Years |   | More than5 Years
|                            |  | (in millions)       
|Letters of Credit (1)       |  | $                    | 94  |                 | $ | 94        |  | $         |  |                  | $ |  |  | $ | 
|Surety Bonds (2) (4)        |  |                      | 52  |                 |   | 52        |  |           |  |                  |   |  |  |   | 
|Guarantees (3)              |  |                      | 4   |                 |   |          |  |           |  |                  |   | 4 |  |   | 
|                            |  |                      |     |                 |   |           |  |           |   |                  |   |   |  |   |  
|Total Financial Commitments |  | $                    | 150 |                 | $ | 146       |  | $         |  |                  | $ | 4 |  | $ | 
|                            |  |                      |     |                 |   |           |  |           |   |                  |   |   |  |   |  

---

|(1) | Amounts include outstanding letters of credit.
|--- | ----------------------------------------------



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|(2) | Surety bonds are generally on a rolling 12-month basis.
|--- | -------------------------------------------------------

|(3) | As part of the power purchase agreement with Constellation, under which Constellation effectively receives our rights to purchase approximately 570 MWs of capacity and energy
arising from our tolling contract with Kendall, we have guaranteed Constellation the receipt of $3.5 million in reactive power revenues over the four year period of the power purchase agreement. Receipt of these reactive power revenues is predicated
on, among other things, filing a reactive power tariff with the FERC.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | $40 million of the surety bonds were supported by collateral.
|--- | -------------------------------------------------------------



Off-Balance Sheet Arrangements



DNE Leveraged Lease. We established our presence in the Northeast region by acquiring the DNE power generating facilities in January 2001
for $950 million.



In May 2001, we entered into an asset-backed
sale-leaseback transaction relating to these facilities to provide us with long-term financing for our acquisition. In this transaction, which was structured as a sale-leaseback to minimize our operating cost of the facilities on an after-tax basis
and to transfer ownership to the purchaser, we sold for approximately $920 million four of the six generating units comprising these facilities to Danskammer OL LLC and Roseton OL LLC, each of which was newly formed by an unrelated third-party
investor, and we concurrently agreed to lease them back from these entities, which we refer to as the owner lessors. The owner lessors used $138 million in equity funding from the unrelated third-party investor to fund a portion of the purchase of
the respective facilities. The remaining $800.4 million of the purchase price and the related transaction expenses was derived from proceeds obtained in a private offering of pass-through trust certificates issued by two of our subsidiaries, Dynegy
Danskammer, L.L.C. and Dynegy Roseton, L.L.C., who serve as lessees of the applicable facilities. The pass-through trust certificate structure was employed, as it has been in similar financings historically executed in the airline and energy
industries, to optimize the cost of financing the assets and to facilitate a capital markets offering of sufficient size to enable the purchase of the lessor notes from the owner lessors. The pass-through trust certificates were sold to qualified
institutional buyers in a private offering and the proceeds were used to purchase debt instruments, referred to as lessor notes, from the owner lessors. The lease payments on the facilities support the principal and interest payments on the
pass-through trust certificates, which are ultimately secured by a mortgage on the underlying facilities.



As of December 31, 2004, future lease payments are $60 million for 2005 and 2006, $108 million for 2007, $144 million for 2008 and $141 million for 2009,
with $919 million in the aggregate due from 2010 through lease expiration. The Roseton lease expires on February 8, 2035 and the Danskammer lease expires on May 8, 2031. We have no option to purchase the leased facilities at the end of their
respective lease terms. We have guaranteed the lessees payment and performance obligations under their respective leases on a senior unsecured basis. At December 31, 2004, the present value (discounted at 10%) of future lease payments was $771
million.



The following table sets forth our lease expenses and
lease payments relating to these facilities for the periods presented.



|                            |  |               |    |      |   |      |  |   |   
|--------------------------- |  | ------------- | -- | ---- | - | ---- |  | - | --
|                            |  | 2004          |    | 2003 |   | 2002
|                            |  | (in millions)
|Lease Expense               |  | $             | 50 |      | $ | 50   |  | $ | 50
|Lease Payments (Cash Flows) |  | $             | 60 |      | $ | 60   |  | $ | 60



If one or more of the
leases were to be terminated because of an event of loss, because it had become illegal for the applicable lessee to comply with the lease or because a change in law had made the facility economically or technologically obsolete, we would be
required to make a termination payment in an amount sufficient to redeem the pass-through trust certificates related to the unit or facility for which the lease was terminated at par plus accrued and unpaid interest. As of December 31, 2004, the
termination payment at par would be approximately $1 billion for all of the DNE facilities, which exceeds the $920 million we received on the sale of



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##### Index to Financial Statements

the facilities. If a termination of this type were to occur with respect to all of the DNE facilities, it would be difficult for us to raise sufficient funds
to make this termination payment. Alternatively, if one or more of the leases were to be terminated because we determine, for reasons other than as a result of a change in law, that it has become economically or technologically obsolete or that it
is no longer useful to our business, we must redeem the related pass-through trust certificates at par plus a make-whole premium in an amount equal to the discounted present value of the principal and interest payments still owing on the
certificates being redeemed less the unpaid principal amount of such certificates at the time of redemption. For this purpose, the discounted present value would be calculated using a discount rate equal to the yield-to-maturity on the most
comparable U.S. treasury security plus 50 basis points.



Capital
Expenditures



We continue to tightly manage costs and
capital expenditures. We had approximately $219 million in capital expenditures during 2004. Our 2004 capital spending by segment was as follows (in millions):



|      |  |   |    
|----- |  | - | ---
|GEN   |  | $ | 145
|NGL   |  |   | 61 
|Other |  |   | 13 
|      |  |   |    
|Total |  | $ | 219
|      |  |   |    



Capital spending in
our GEN segment primarily consisted of maintenance capital projects, as well as approximately $41 million spent on development capital. Development capital spending primarily related to the conversion of our Havana facility to PRB coal. Capital
spending in our NGL segment primarily related to maintenance capital projects and wellconnects, as well as approximately $21 million in development capital. Development capital included approximately $13 million for gathering system expansion,
additional compression and plant de-bottlenecking in North Texas related to increased gas from the Barnett Shale formation and approximately $8 million for a significant upgrade in compression technology and efficiencies at our Monument gas
processing plant.



We expect capital expenditures for 2005 to
approximate $269 million. This primarily includes maintenance capital projects, environmental projects, contributions to equity investments and limited GEN and NGL development projects. The capital budget is subject to revision as opportunities
arise or circumstances change. Estimated funds budgeted for the aforementioned items by segment in 2005 are as follows (in millions):



|      |  |   |    
|----- |  | - | ---
|GEN   |  | $ | 180
|NGL   |  |   | 78 
|Other |  |   | 11 
|      |  |   |    
|Total |  | $ | 269
|      |  |   |    



We anticipate
increased capital spending in our GEN segment primarily due to an increase in long-term capital maintenance expenditures. We anticipate increased capital spending in the NGL segment primarily due to $6 million for gathering system expansion,
additional compression and plant de-bottlenecking in North Texas related to increased gas from the Barnett Shale formation and $20 million for a project under consideration at our Mont Belvieu facility.



As reflected in this section, the capital spending in our NGL segment
includes 100% of the expenditures of our consolidated partnerships, Versado Gas Processors, LLC and Cedar Bayou Fractionators, LP. Our ownership percentages of these partnerships are 63% and 88%, respectively, and net funding equal to our ownership
percentage is achieved through adjustments to partnership distributions. Adjusted for our partners share of capital expenditures, our expenditures would have been $52 million in 2004 and are expected to be $72 million in 2005.



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Our capital expenditures in 2005 and beyond will continue to be limited by negative covenants contained
in our debt instruments. These covenants place specific dollar limitations on our ability to incur capital expenditures. Please read Note 11DebtTerm Loan and Credit Facility beginning on page F-34 for further discussion of these
limitations. Our long term capital expenditures will also be significantly impacted by the Baldwin consent decree announced in March 2005. If ultimately approved by the Illinois federal district court, this consent decree would obligate us to, among
other things, invest $321 million through 2010, and $224 million from 2011 through 2012, respectively, in emission control projects at our Baldwin, Vermilion and Havana plants. Please read Note 14Commitments and ContingenciesSummary of
Material Legal ProceedingsBaldwin Station Litigation beginning on page F-45 for further discussion of this consent decree.



Financing Trigger Events



Our debt instruments and other financial obligations include provisions, which, if not met, could require early payment, additional collateral support or
similar actions. These trigger events include leverage ratios and other financial covenants, insolvency events, defaults on scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. We do
not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.



Commitments and Contingencies



Please read Note 14Commitments and Contingencies beginning on page
F-43, which is incorporated herein by reference, for a discussion of our commitments and contingencies.



Internal Liquidity Sources



Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our $700 million revolving credit facility, which is scheduled to mature in May 2007.



Current Liquidity.The following table summarizes our
consolidated revolver capacity and liquidity position at March 11, 2005, December 31, 2004 and December 31, 2003:



|                                                              |  |                |     |     |                   |   |     |                  |  |   |       |  
|------------------------------------------------------------- |  | -------------- | --- | --- | ----------------- | - | --- | ---------------- |  | - | ----- | -
|                                                              |  | March 11, 2005 |     |     | December 31, 2004 |   |     | December 31,2003 | 
|                                                              |  |                |     |     | (in millions)     |   |     |                  | 
|Total Revolver Capacity                                       |  | $              | 700 | (1) |                   | $ | 700 | (1)              |  | $ | 1,100 |  
|Outstanding Letters of Credit Under Revolving Credit Facility |  |                | (89 | )   |                   |   | (94 | )                |  |   | (188  | )
|                                                              |  |                |     |     |                   |   |     |                  |  |   |       |  
|Unused Revolver Capacity                                      |  |                | 611 |     |                   |   | 606 |                  |  |   | 912   |  
|Cash                                                          |  |                | 204 | (2) |                   |   | 245 | (2)              |  |   | 328   |  
|                                                              |  |                |     |     |                   |   |     |                  |  |   |       |  
|Total Available Liquidity                                     |  | $              | 815 |     |                   | $ | 851 |                  |  | $ | 1,240 |  
|                                                              |  |                |     |     |                   |   |     |                  |  |   |       |  

---

|(1) | Please read Note 11DebtTerm Loan and Credit Facility beginning on page F-34 for a discussion of our credit facility.
|--- | ----------------------------------------------------------------------------------------------------------------------

|(2) | The March 11, 2005 and December 31, 2004 amounts include approximately $46 million and $47 million, respectively, of cash that remains in Canada and the U.K. that is associated
primarily with contingent liabilities relating to our former Canadian and U.K. marketing and trading operations.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Cash Flows from Operations. We had operating cash outflows of $160 million in 2004. This consisted of $697 million in operating cash
flows from our GEN and NGL segments, reflecting positive earnings for the period offset by reductions in working capital from increased cash collateral postings. The cash flows from our operating segments were substantially offset by $857 million of
cash outflows relating to our CRM business and



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##### Index to Financial Statements

corporate-level expenses. Please read Results of OperationsYear Ended 2004 Compared to Year Ended 2003Operating Income (Loss)
beginning on page 46 and Cash Flow Disclosures beginning on page 59 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 tightly manage
our operating costs, including costs for fuel and maintenance. With respect to fuel costs, in January 2004, we entered into a new rail transportation contract that reduced the fees associated with fuel procurement at our coal-fired generation
facilities in the Midwest; however, these fee reductions were substantially offset by increased coal prices in the Northeast and higher costs associated with the purchase of emission credits. Our ability to achieve fuel-related and other targeted
cost savings in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, will impact our future operating cash flows. Please read Results of Operations2005 OutlookGEN
Outlook beginning on page 56 for further discussion.



In addition, our CDWR power purchase agreement expired by its terms in December 2004. Please read Item 1. BusinessSegment DiscussionPower Generation beginning on page 2 for a discussion of West Coast Powers current
contractual arrangements. Our share of West Coast Powers earnings during 2004 totaled $165 million, excluding impairments of $85 million, approximately 70% of which was derived from the CDWR agreement. In Californias current energy
market, the West Coast Power generating facilities which previously supported the CDWR contract are significantly less profitable under the RMR contracts or as merchant facilities, and we may consider other alternatives if necessary, including
shutting down units if we no longer consider them commercially viable. Based on our ongoing evaluation of strategic alternatives for our West Coast Power assets, we determined that it was not economically feasible to continue to operate our Long
Beach generation facility beyond the expiration of the CDWR contract. Therefore, we retired the asset effective January 1, 2005. Please read Results of Operations2005 OutlookGEN Outlook beginning on page 56 for further
discussion of the CDWR agreement and the impairments relating to its expiration.



Cash on Hand. At March 11, 2005 and December 31, 2004, we had cash on hand of $204 million and $245 million, respectively, as compared to $328 million at the end of 2003. This increase in cash on
hand at December 31, 2004 as compared to the end of 2003 is primarily attributable to the proceeds from our May 2005 term loan as well as proceeds from assets sales.



Revolver Capacity. In May 2004, we entered into a new $1.3 billion credit facility, consisting of a
$600 million term loan and a $700 million revolving credit facility. This $700 million revolving credit facility, which is scheduled to mature in May 2007, is our primary credit facility. We currently have no drawn amounts under this facility,
although as of March 11, 2005, we had $89 million in letters of credit issued under the facility. Our ability to borrow and/or issue letters of credit under a revolving credit facility could become increasingly important to our liquidity and
financial condition, particularly if we are unable to generate operating cash flows relative to our substantial debt obligations and ongoing operating requirements. Please read Note 11DebtTerm Loan and Credit Facility beginning on page
F-34 for further discussion of our credit facility.



External Liquidity
Sources



Our primary external liquidity sources are
proceeds from asset sales and other types of capital-raising transactions, including potential equity issuances.



Asset Sale Proceeds.In an effort to maximize our return on investment and to further clarify our business strategy, we have sold assets
that we do not consider core to our operations, including our ownership interests in certain non-strategic domestic power generation facilities (e.g., Commonwealth, Hartwell, Michigan Power and Oyster Creek) as well as our ownership interests in
Indian Basin and our Sherman natural gas processing facility. As we have previously disposed of substantially all of our non-core assets, we do not currently anticipate receiving a material amount of proceeds from asset sales, if any, during 2005.



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The aggregate loss of earnings in 2004 associated with these assets was not material and was more than
offset by net gains on sale in 2004. During 2004, we received aggregate cash proceeds of $246 million from these asset sales. However, beginning in 2005, the lost earnings of approximately $14 million on an annual basis from such assets will no
longer be offset by gains on sale.



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 businesses, each of 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 legal
judgments or regulatory requirements, as well as strategic decisions relating to litigation settlements or contract terminations (including settlement of one or more of our remaining power tolling arrangements), which would necessitate additional
capital in the near-term.



These transactions may include
capital markets transactions. Dynegys ability to issue public securities is enhanced by its effective shelf registration statement, under which it has approximately $430 million in remaining availability. However, the receptiveness of the
capital markets to a public offering cannot be assured and may be negatively impacted by, among other things, Dynegys non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond its
control. Any issuance of equity likely would have other effects as well, including shareholder dilution. Further, our and/or Dynegys ability to issue debt securities is limited by our and Dynegys financing agreements, including our
credit facility. Please read Note 11DebtTerm Loan and Credit Facility beginning on page F-34 for further discussion.



Conclusion



During 2004, we received approximately $246 million in aggregate sale proceeds from the disposition of non-core assets. We also extended a significant
debt maturity through the replacement of our $1.1 billion revolving credit facility, scheduled to mature in February 2005, with a $700 million revolving credit facility and $600 million term loan scheduled to mature in May 2007 and May 2010,
respectively. Using proceeds from the $600 million term loan, together with cash on hand, we extinguished some of our substantial debt obligations, including our ABG Gas Supply Financing.



For the next twelve months, assuming continuation of the current commodity pricing environment, we expect that our operating
cash flows will be positive, but insufficient to satisfy our capital expenditures, debt maturities and interest expenses. However, we believe that our cash on hand and capacity under our $700 million revolving credit facility, will be sufficient to
discharge these obligations. To further the consolidated enterprises deleveraging efforts, other capital-raising activities may be considered, including potential equity issuances by Dynegy.



Over the longer term and through the anticipated recovery of the U.S. power
markets, we expect to maintain sufficient liquidity to satisfy our substantial debt and commercial obligations and provide collateral support through operating cash flows, capacity under our revolving credit facility (or any refinancing thereof), as
well as proceeds from anticipated refinancings of debt maturities. Our substantial debt and commercial obligations include increased interest expense, the fixed payment obligations associated with our remaining power tolling arrangements in our CRM
business (which we expect will continue to reduce our operating cash flows absent early termination or settlement) and counterparty collateral requirements, as well as our significant potential payment obligations relating to our securities
litigation and other legal and regulatory matters. We expect that our liquidity position will trend downward as these obligations are satisfied or extinguished.



Our ability to generate operating cash flows will be impacted by a number of factors, some of which are beyond our control, including weather,
commodity prices, particularly for power and natural gas, and the success of our ongoing efforts to manage operating costs, particularly fuel requirements, and capital expenditures. Our ability to refinance our substantial debt maturities is
primarily dependant upon our ability to generate operating



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##### Index to Financial Statements

cash flows, which is subject to the factors described in the preceding sentence. Over the longer term we believe that power prices will improve in some or
all of the regions in which we operate as the supply-demand imbalance for power decreases. Much of our restructuring work has extended our significant debt maturities to 2007 and beyond, positioning us to benefit from earnings and growth
opportunities associated with an expected recovery in the U.S. power markets. Additionally, our NGL business is currently operating in a highly favorable pricing environment. Our future financial condition and results of operations will be
materially adversely affected if the U.S. power markets fail to recover in accordance with our expectations or if we experience significant, prolonged pricing deterioration below price levels experienced over the last few years in our NGL segment.



Our longer term liquidity position and financial condition
will also be significantly impacted by the availability of, and our ability to pursue, strategic growth opportunities, which may include organic or bolt-on projects, as well as industry consolidation. However, as indicated above, our
desire or ability to pursue any such opportunities is subject to a number of factors beyond our control. As such, we cannot guarantee that any such opportunities will be available to us, nor can we predict with any degree of certainty the impact of
any such opportunities on our financial condition or results of operations.



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



RESULTS OF OPERATIONS



Overview and Discussion of Comparability of Results. In this
section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for 2004, 2003 and 2002. At the end of this section, we have included our 2005 outlook for each segment.



As reflected in this report, we have changed our reporting segments. Prior to
2003, we reported results for the following three business segments: WEN, DMS and T&D. Beginning January 1, 2003, we have been reporting our operations in the following segments: GEN, NGL, and CRM. Other reported results include corporate
overhead. All corporate overhead included in other reported results was allocated to our three former reporting segments prior to January 1, 2003. Beginning January 1, 2003, all direct general and administrative expenses and other income (expense)
items incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred. In addition, all interest expense was allocated to our four former reporting segments prior to January 1, 2003.



Prior to January 1, 2003, the GEN and CRM segments were operated together as
an asset-based third-party marketing, trading and risk-management business, then referred to as the WEN segment. Please read Note 18Segment Information beginning on page F-64 for a discussion of the impact of comparing segment results period
over period. Regarding our results of operations for 2004, 2003 and 2002, the impact of acquisition and disposition activity reduces the comparability of some of our historical financial and volumetric data. Lastly, recent accounting pronouncements
have affected our financial results, particularly those of our CRM business, so as to further reduce the comparability of some of our historical financial data. For example, the rescission of EITF Issue 98-10, effective January 1, 2003, has reduced
the number of contracts accounted for on a mark-to-market basis in the 2004 and 2003 periods as compared to the 2002 period. Please read Results of OperationsYear Ended 2004 Compared to Year Ended 2003Cumulative Effect of
Change in Accounting Principles beginning on page 51 for further discussion.



42



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##### Table of Contents

##### Index to Financial Statements

Summary Financial Information.The following tables provide summary financial data
regarding our consolidated and segmented results of operations for 2004, 2003 and 2002, respectively. The financial data for the years ended December 31, 2003 and 2002 has been restated to reflect the effect of the item described in the Explanatory
Note to the accompanying Consolidated Financial Statements. The restatement relates to our deferred income tax accounts. Please read the Explanatory Note beginning on page F-8 for further discussion of this restatement item.



Year Ended December 31, 2004



|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|----------------------------------------------- |  | ------------- | --- | --- | - | --- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ---- | -
|                                                |  | GEN           |     | NGL |   |     | CRM |  |   | Other andEliminations |   |  | Total |     
|                                                |  | (in millions) |    
|Operating income (loss)                         |  | $             | 162 |     | $ | 287 |     |  | $ | (118                  | ) |  | $     | (275 | ) |  | $ | 56   |  
|Earnings from unconsolidated investments        |  |               | 116 |     |   | 10  |     |  |   |                      |   |  |       |     |   |  |   | 126  |  
|Other items, net                                |  |               |    |     |   | (22 | )   |  |   | (3                    | ) |  |       | 8    |   |  |   | (17  | )
|Interest expense                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (359 | )
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Loss from continuing operations before taxes    |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (194 | )
|Income tax benefit                              |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 97   |  
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Loss from continuing operations                 |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (97  | )
|Loss from discontinued operations, net of taxes |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (7   | )
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Net loss                                        |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  | $ | (104 | )
|                                                |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  



Year Ended December
31, 2003



|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|------------------------------------------------------------------ |  | ------------- | --- | --- | - | --- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ---- | -
|                                                                   |  | GEN           |     | NGL |   |     | CRM |  |   | Other andEliminations |   |  | Total |     
|                                                                   |  | (Restated)    |    
|                                                                   |  | (in millions) |    
|Operating income (loss)                                            |  | $             | 198 |     | $ | 170 |     |  | $ | (385                  | ) |  | $     | (238 | ) |  | $ | (255 | )
|Earnings (losses) from unconsolidated investments                  |  |               | 136 |     |   | (2  | )   |  |   | (2                    | ) |  |       |     |   |  |   | 132  |  
|Other items, net                                                   |  |               | 1   |     |   | (17 | )   |  |   | 31                    |   |  |       | (9   | ) |  |   | 6    |  
|Interest expense                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (338 | )
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Loss from continuing operations before taxes                       |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (455 | )
|Income tax benefit                                                 |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 191  |  
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Loss from continuing operations                                    |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (264 | )
|Loss from discontinued operations, net of taxes                    |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (12  | )
|Cumulative effect of change in accounting principles, net of taxes |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 42   |  
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Net loss                                                           |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  | $ | (234 | )
|                                                                   |  |               |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  



43



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##### Table of Contents

##### Index to Financial Statements

Year Ended December 31, 2002



|                                                  |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   |        |  
|------------------------------------------------- |  | ------------- | ---- | - | --- | - | --- | --- |  | - | --------------------- | - | ----- | - | - |  | - | ------ | -
|                                                  |  | GEN           |      |   | NGL |   |     | CRM |  |   | Other andEliminations |   | Total |  
|                                                  |  | (Restated)    |     
|                                                  |  | (in millions) |     
|Operating income (loss)                           |  | $             | (171 | ) |     | $ | 77  |     |  | $ | (951                  | ) |       | $ |  |  | $ | (1,045 | )
|Earnings (losses) from unconsolidated investments |  |               | (45  | ) |     |   | 14  |     |  |   | (21                   | ) |       |   |  |  |   | (52    | )
|Other items, net                                  |  |               | 9    |   |     |   | (34 | )   |  |   | (49                   | ) |       |   |  |  |   | (74    | )
|Interest expense                                  |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   | (187   | )
|                                                  |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   |        |  
|Loss from continuing operations before taxes      |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   | (1,358 | )
|Income tax benefit                                |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   | 366    |  
|                                                  |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   |        |  
|Loss from continuing operations                   |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   | (992   | )
|Loss from discontinued operations, net of taxes   |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   | (100   | )
|                                                  |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   |        |  
|Net loss                                          |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  | $ | (1,092 | )
|                                                  |  |               |      |   |     |   |     |     |  |   |                       |   |       |   |   |  |   |        |  



The following table
provides summary segmented operating statistics for 2004, 2003 and 2002, respectively:



|                                                  |  |                         |         |      |   |         |  |   |        
|------------------------------------------------- |  | ----------------------- | ------- | ---- | - | ------- |  | - | -------
|                                                  |  | Year Ended December 31,
|                                                  |  | 2004                    |         | 2003 |   | 2002   
|Power Generation                                  |  |                         |         |      |   |         |  |   |        
|Million megawatt hours generatedgross            |  |                         | 36.8    |      |   | 36.2    |  |   | 36.4   
|Million megawatt hours generatednet              |  |                         | 34.9    |      |   | 34.3    |  |   | 34     
|Average natural gas priceHenry Hub ($/MMbtu) (1) |  | $                       | 5.89    |      | $ | 5.28    |  | $ | 3.35   
|Average on-peak market power prices ($/MWh)       |  |                         |         |      |   |         |  |   |        
|Cinergy                                           |  | $                       | 43      |      | $ | 37      |  | $ | 27     
|Commonwealth Edison                               |  |                         | 42      |      |   | 37      |  |   | 26     
|Southern                                          |  |                         | 49      |      |   | 41      |  |   | 30     
|New YorkZone G                                   |  |                         | 62      |      |   | 61      |  |   | 46     
|ERCOT                                             |  |                         | 51      |      |   | 45      |  |   | 29     
|SP-15                                             |  |                         | 55      |      |   | 52      |  |   | 35     
|Natural Gas Liquids                               |  |                         |         |      |   |         |  |   |        
|Gross NGL production (MBbls/d):                   |  |                         |         |      |   |         |  |   |        
|Field plants                                      |  |                         | 57.3    |      |   | 59.6    |  |   | 56.0   
|Straddle plants                                   |  |                         | 26.6    |      |   | 25.6    |  |   | 35.9   
|                                                  |  |                         |         |      |   |         |  |   |        
|Total gross NGL production                        |  |                         | 83.9    |      |   | 85.2    |  |   | 91.9   
|                                                  |  |                         |         |      |   |         |  |   |        
|Natural gas (residue) sales (Bbtu/d)              |  |                         | 182.8   |      |   | 174.4   |  |   | 188.4  
|Natural gas inlet volumes (MMCFD):                |  |                         |         |      |   |         |  |   |        
|Field plants                                      |  |                         | 535.6   |      |   | 591.0   |  |   | 569.3  
|Straddle plants                                   |  |                         | 990.0   |      |   | 1,103.1 |  |   | 1,511.9
|                                                  |  |                         |         |      |   |         |  |   |        
|Total natural gas inlet volumes                   |  |                         | 1,525.6 |      |   | 1,694.1 |  |   | 2,081.2
|                                                  |  |                         |         |      |   |         |  |   |        
|Fractionation volumes (MBbls/d)                   |  |                         | 202.5   |      |   | 185.3   |  |   | 215.2  
|Natural gas liquids sold (MBbls/d)                |  |                         | 282.5   |      |   | 311.7   |  |   | 498.8  
|Average commodity prices:                         |  |                         |         |      |   |         |  |   |        
|Crude oilWTI ($/Bbl)                             |  | $                       | 41.43   |      | $ | 31.01   |  | $ | 25.75  
|Natural gasHenry Hub ($/MMbtu) (2)               |  | $                       | 6.13    |      | $ | 5.38    |  | $ | 3.22   
|Natural gas liquids ($/Gal)                       |  | $                       | 0.71    |      | $ | 0.55    |  | $ | 0.40   
|Fractionation spread ($/MMBtu)daily              |  | $                       | 2.18    |      | $ | 0.79    |  | $ | 1.13   

---

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

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



44



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##### Table of Contents

##### Index to Financial Statements

The following tables summarize significant items on a pre-tax basis, with the exception of the 2004 and
2003 tax items, affecting net loss for the periods presented.



|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |      |   |  |   |        |  
|---------------------------------------------------- |  | ---------------------------- | ---- | - | --- | - | --- | --- |  | - | ----- | - |  | ----- | ---- | - |  | - | ------ | -
|                                                     |  | Year Ended December 31, 2004 |     
|                                                     |  | GEN                          |      |   | NGL |   |     | CRM |  |   | Other |   |  | Total |     
|                                                     |  | (in millions)                |     
|Discontinued operations                              |  | $                            |     |   |     | $ | 1   |     |  | $ | 19    |   |  | $     |     |   |  | $ | 20     |  
|Kendall toll restructuring                           |  |                              |     |   |     |   |    |     |  |   | (115  | ) |  |       |     |   |  |   | (115   | )
|Impairment of West Coast Power                       |  |                              | (85  | ) |     |   |    |     |  |   |      |   |  |       |     |   |  |   | (85    | )
|Legal and settlement charges                         |  |                              | (7   | ) |     |   | 2   |     |  |   | (13   | ) |  |       | (92  | ) |  |   | (110   | )
|Acceleration of financing costs                      |  |                              |     |   |     |   |    |     |  |   |      |   |  |       | (14  | ) |  |   | (14    | )
|Gas transportation contracts                         |  |                              |     |   |     |   |    |     |  |   | 88    |   |  |       |     |   |  |   | 88     |  
|Gain on sale of Indian Basin                         |  |                              |     |   |     |   | 36  |     |  |   |      |   |  |       |     |   |  |   | 36     |  
|Gain on sale of Hackberry LNG                        |  |                              |     |   |     |   | 17  |     |  |   |      |   |  |       |     |   |  |   | 17     |  
|Gain on sale of Sherman                              |  |                              |     |   |     |   | 16  |     |  |   |      |   |  |       |     |   |  |   | 16     |  
|Gain on sale of Oyster Creek                         |  |                              | 15   |   |     |   |    |     |  |   |      |   |  |       |     |   |  |   | 15     |  
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |      |   |  |   |        |  
|Total                                                |  | $                            | (77  | ) |     | $ | 72  |     |  | $ | (21   | ) |  | $     | (106 | ) |  | $ | (132   | )
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |      |   |  |   |        |  
|                                                     | 
|                                                     |  | Year Ended December 31, 2003 |     
|                                                     |  | GEN                          |      |   | NGL |   |     | CRM |  |   | Other |   |  | Total |     
|                                                     |  | (in millions)                |     
|Southern Power tolling settlement                    |  | $                            |     |   |     | $ |    |     |  | $ | (133  | ) |  | $     |     |   |  | $ | (133   | )
|Sithe power tolling contract                         |  |                              |     |   |     |   |    |     |  |   | (121  | ) |  |       |     |   |  |   | (121   | )
|Legal charges                                        |  |                              |     |   |     |   |    |     |  |   |      |   |  |       | (50  | ) |  |   | (50    | )
|Batesville tolling settlement                        |  |                              |     |   |     |   |    |     |  |   | (34   | ) |  |       |     |   |  |   | (34    | )
|Kroger settlement                                    |  |                              |     |   |     |   |    |     |  |   | (30   | ) |  |       |     |   |  |   | (30    | )
|Discontinued operations                              |  |                              |     |   |     |   | (2  | )   |  |   | (12   | ) |  |       | (3   | ) |  |   | (17    | )
|Impairment of generation investments                 |  |                              | (26  | ) |     |   |    |     |  |   |      |   |  |       |     |   |  |   | (26    | )
|Acceleration of financing costs                      |  |                              |     |   |     |   |    |     |  |   |      |   |  |       | (24  | ) |  |   | (24    | )
|West Coast Power goodwill impairment                 |  |                              | (20  | ) |     |   |    |     |  |   |      |   |  |       |     |   |  |   | (20    | )
|Impairment of equity investment                      |  |                              |     |   |     |   | (12 | )   |  |   |      |   |  |       |     |   |  |   | (12    | )
|Gain on sale of Hackberry LNG                        |  |                              |     |   |     |   | 25  |     |  |   | 2     |   |  |       |     |   |  |   | 27     |  
|Cumulative effect of change in accounting principles |  |                              | 24   |   |     |   |    |     |  |   | 43    |   |  |       |     |   |  |   | 67     |  
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |      |   |  |   |        |  
|Total                                                |  | $                            | (22  | ) |     | $ | 11  |     |  | $ | (285  | ) |  | $     | (77  | ) |  | $ | (373   | )
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |      |   |  |   |        |  
|                                                     | 
|                                                     |  | Year Ended December 31, 2002 |     
|                                                     |  | GEN                          |      |   | NGL |   |     | CRM |  |   | Other |   |  | Total |     
|                                                     |  | (in millions)                |     
|Discontinued operations                              |  | $                            |     |   |     | $ | (37 | )   |  | $ | (51   | ) |  | $     | (25  | ) |  | $ | (113   | )
|Goodwill impairment                                  |  |                              | (315 | ) |     |   |    |     |  |   | (325  | ) |  |       |     |   |  |   | (640   | )
|Restructuring costs                                  |  |                              | (42  | ) |     |   | (19 | )   |  |   | (73   | ) |  |       |     |   |  |   | (134   | )
|Impairment of generation investments                 |  |                              | (117 | ) |     |   |    |     |  |   |      |   |  |       |     |   |  |   | (117   | )
|Generation equity earnings (loss)                    |  |                              | (50  | ) |     |   |    |     |  |   |      |   |  |       |     |   |  |   | (50    | )
|Impairment of technology investments                 |  |                              | (2   | ) |     |   | (2  | )   |  |   | (12   | ) |  |       |     |   |  |   | (16    | )
|Tolling settlement accrual                           |  |                              |     |   |     |   |    |     |  |   | (25   | ) |  |       |     |   |  |   | (25    | )
|ChevronTexaco contract settlement                    |  |                              |     |   |     |   |    |     |  |   | (22   | ) |  |       |     |   |  |   | (22    | )
|Enron settlement                                     |  |                              | (6   | ) |     |   | (4  | )   |  |   | (9    | ) |  |       |     |   |  |   | (19    | )
|Other (1)                                            |  |                              | (23  | ) |     |   | (3  | )   |  |   | (37   | ) |  |       |     |   |  |   | (63    | )
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |      |   |  |   |        |  
|Total                                                |  | $                            | (555 | ) |     | $ | (65 | )   |  | $ | (554  | ) |  | $     | (25  | ) |  | $ | (1,199 | )
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |      |   |  |   |        |  

---

|(1) | Other includes a pre-tax charge of approximately $25 million related to the write-off of our investment in Dynegydirect and a pre-tax charge of approximately
$14 million associated with the impairment of a generation turbine. These amounts are included in Impairment and other charges. Other also includes various other individually insignificant items.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



45



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##### Table of Contents

##### Index to Financial Statements

Year Ended 2004 Compared to Year Ended 2003



Operating Income (Loss)



Operating income was $56 million in 2004, compared to a loss of $255 million in 2003.



GEN.Operating income for our GEN segment was $162 million in
2004, compared to $198 million in 2003.



In the Midwest region,
where we produce approximately 60% of our generated volumes, results increased $27 million year over year. Increased prices contributed an additional $23 million for 2004 compared to 2003. Additionally, we experienced a $28 million reduction in coal
transportation costs in the Midwest region, resulting from a transportation contract which took effect at the beginning of 2004. However, improved pricing was partially offset by an increase in operating expenses for the Midwest of approximately $12
million, resulting from the timing of maintenance expenditures, as well as increases in labor costs. Additionally, we reported $17 million less capacity revenue in 2004 as compared with 2003. Volumes were down slightly, from 21.1 million MWh for
2003 to 20.7 million MWh for 2004. This decrease was largely due to reduced production at our Havana facility, resulting from our management of fuel inventories in anticipation of our switch to PRB coal. Please read 2005 OutlookGEN
Outlook beginning on page 56 for a discussion of the current fuel and transportation environment.



Improved earnings in the Midwest region were offset by the Northeast region, where results decreased from $49 million in 2003 to $20 million in 2004. This
decrease was primarily the result of pricing effects year over year, as increased fuel costs more than offset an increase in power prices. This resulted in a $21 million reduction in earnings. Additionally, we realized $11 million less revenue in
2004 under a transitional power purchase agreement, which expired in October 2004. Operating expense in the Northeast was up $3 million year over year as a result of increased labor and tax expense. However, these reductions in earnings were
partially offset by a 7% increase in volumes, which contributed an additional $6 million, largely the result of the dual fuel capabilities of our Roseton unit.



Results in the Southeast region were down $25 million, from $26 million in 2003 to $1 million in 2004. This reduction in earnings was primarily the
result of the loss of capacity revenues related to a contract that expired at the end of 2003.



Results in the ERCOT region decreased $11 million, from a loss of $8 million in 2003 to a loss of $19 million in 2004, primarily as a result of increased natural gas prices and the impact of these increased prices on
a long-term power and steam sales contract.



GENs
reported operating income for 2004 also includes approximately $7 million of mark-to-market income related to purchases and sales that did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a
mark-to-market basis. GENs results for 2003 include approximately $7 million of mark-to-market income related to derivative contracts that did not qualify as hedges. Mark-to-market income in 2004 included a $3 million charge to earnings in
connection with hedge ineffectiveness.



In March 2004, we
tested our CoGen Lyondell facility for an impairment based on the identification of a triggering event as defined by SFAS No. 144. After performing this test, we concluded that no impairment was necessary as the estimated undiscounted cash flows
exceeded the book value of the asset.



NGL.Operating income for the NGL segment was $287 million in 2004, compared to $170 million in 2003.



The significant improvement in operating income was driven by natural gas, crude oil and natural gas liquids prices, which increased to historically high
levels during periods of the year, and a frac spread sufficiently



46



---

##### Table of Contents

##### Index to Financial Statements

high to make natural gas liquids recovery profitable under all contract settlements during the last five months of 2004. During the entire year, we
capitalized on the pricing opportunities presented through strong asset runtime across all NGL segments.



Significantly higher commodity prices contributed approximately $79 million to our results as compared to 2003. Of the increase, $52 million related to
POP contracts in field processing, $24 million was derived from our POL contracts at our straddle processing plants and $3 million was generated from natural gas liquids marketing contracts.



Frac spreads were significantly higher in 2004 compared to 2003. During the
last five months of 2004, the spread between natural gas liquids prices and natural gas prices reached levels sufficient to support increased liquids recovery industry-wide, reversing an eighteen-month trend. During the year, higher frac spreads
generated incremental results of approximately $37 million as compared to 2003. The increase relates to the following: $2 million from additional volumes processed in our Stingray processing plant under economic keep-whole settlement terms; $24
million from contract settlements for existing gas volumes under hybrid contracts that switched from fee to percentage of liquids settlements; and $11 million due to increased industry-wide natural gas liquids recovery which brought additional
volumes to our fee-based liquids gathering systems, fractionators, storage and distribution systems and marketing activities.



Gathering and processing operating results increased by $50 million for 2004 compared to 2003, primarily benefiting from 14% higher absolute commodity
prices for natural gas and 29% higher absolute commodity prices for natural gas liquids year over year. At our field plants, results increased $42 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from
higher prices. However, declines in gross and net natural gas liquids production due to sale of our non-operating joint interest in the Indian Basin plant in April 2004, sale of our Sherman plant in November 2004 and impacts of pipeline, compressor
and process unit maintenance at our facilities partially offset the commodity price gains. At our straddle plants, operating results increased $8 million, due largely to the impact of higher natural gas liquids prices under our POL contract
settlements. Additionally, during the last five months of 2004, higher frac spreads made it profitable to recover liquids under KW agreements and caused hybrid contracts to switch from fee to POL settlements. The Stingray facility, our only plant
that settles under a keep-whole contract structure, operated from the end of July through the remainder of 2004, while it was idled during all of 2003. Offsetting these increased volumes was the negative impact of Hurricane Ivan on producers
volumes available to process at some of our straddle plants that resulted in a reduction in operating results of $17 million. Overall straddle plant inlet volumes decreased 10% and net barrels produced increased 3%.



Results of our fractionation, storage and terminalling and transportation and
logistics businesses increased $13 million for 2004 compared to 2003. Volumes increased at both of our fractionators due to industry-wide increased liquids production primarily as a result of higher frac spreads. These higher volumes also drove
increased operating income in our supporting storage and natural gas liquids pipeline operations.



Wholesale marketing results were slightly favorable for 2004 compared to 2003 due to the impacts of higher natural gas liquids prices, offset by the loss
of a refinery service contract. Results for 2003 benefited from extremely cold weather in the first quarter.



NGL marketing services and distribution results increased approximately $13 million for 2004 compared to 2003. Marketing fees were approximately $3
million higher due to the higher natural gas liquids prices year over year, offset by the impact of lower volumes primarily because of reduced market liquidity. As part of our normal operations, contractual terms with a natural gas liquids pipeline
changed, and we terminated an inactive natural gas liquids sales contract. Both of these contractual changes reduced the amount of natural gas liquids volumes required to be held in reserve to serve our customers. Since the volumes held in reserve
as deadstock were valued at below current market prices, the release of volumes required to be held in reserve allowed us to recognize an $8 million gain on sales at current market prices. Due to a sharp decline in prices during the last half of



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##### Index to Financial Statements

December 2004, distribution and marketing services recorded a negative non-cash lower of cost or market adjustment of $4 million compared to a similar
negative adjustment of $9 million in 2003, for a positive variance of $5 million year over year.



Operating income for 2004 included pre-tax gains on sales of assets of $69 million, including a $36 million gain associated with the sale of our
non-operating interest in the Indian Basin processing plant, a gain of $16 million from the sale of our Sherman processing plant and a $17 million gain on the sale of our final financial interest in our Hackberry LNG project, offset by increased
depreciation expense of $6 million due to an adjustment to accumulated depreciation and an asset impairment of $5 million further discussed below. Operating income for 2003 included a $25 million gain on sale of our ownership interest in the
Hackberry LNG facility and a $3 million gain associated with the expiration of an environmental indemnity obligation. Please see Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract
TerminationsHackberry LNG Project beginning on page F-21 for further discussion.



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



CRM.Operating loss for the CRM segment
was $118 million in 2004, compared to $385 million in 2003.



Results for 2004 were impacted by the following items:



| |  |  | $88 million gain associated with the exit of four natural gas transportation agreements in support of our third-party marketing and trading business; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | $115 million charge associated with our entry into a back-to-back power purchase agreement with a subsidiary of Constellation Energy in November 2004 to mitigate the
effect of the Kendall tolling arrangement through November 2008.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



This segments results for 2004 also reflect the impact of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold and include $10 million in gains
associated with the mark-to-market value of certain legacy gas contracts which had previously been accounted for on an accrual basis.



Results for 2003 were impacted by the following pre-tax losses:



| |  |  | $133 million charge associated with the settlement of power tolling arrangements with Southern Power, for which we paid $155 million;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------



| |  |  | $121 million mark-to-market loss on contracts associated with the Independence power tolling arrangement;
| | - |  | ---------------------------------------------------------------------------------------------------------



| |  |  | $34 million charge associated with the cash settlement of the Batesville tolling arrangement; and
| | - |  | -------------------------------------------------------------------------------------------------



| |  |  | $30 million charge associated with the settlement of power supply agreements with Kroger, for which we received approximately $110 million.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------



Additionally, 2003 results include gains from the sale of natural gas
inventories of $61 million, offset by charges associated with the settlement of legacy contracts of $21 million and changes in the value of our remaining marketing and trading activity.



Other. Other operating loss was $275 million in 2004, compared to $238 million in 2003. The losses in 2004 and
2003 primarily relate to general and administrative expenses and depreciation and amortization



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##### Index to Financial Statements

expenses which are incurred at a corporate level. The higher loss in 2004 related primarily to increased legal and settlement charges, costs related to
compliance with Section 404 of the Sarbanes-Oxley Act and higher professional fees.



Operating loss for 2004 includes approximately $92 million of expenses related to legal and settlement charges. Please read Note 4Restructuring and Impairment ChargesSeverance and Other Restructuring Costs
beginning on page F-24 for a discussion of the settlement charges. Operating loss for 2003 includes legal charges of $50 million. The legal charges in both periods resulted from additional activities during each period that affected
managements assessment of the probable and estimable loss associated with the applicable proceedings.



Earnings from Unconsolidated Investments.



Our earnings from unconsolidated investments were approximately $126 million during 2004 compared to $132 million in 2003. Both the 2004 and 2003 results
include significant impairment charges related to these investments, primarily associated with our GEN segment.



GEN. GENs earnings from unconsolidated investments were approximately $116 million during 2004 compared to $136 million in 2003.



Our West Coast Power investment was the primary driver of
equity earnings for the two periods. Total earnings from the investment of $165 million in 2004 were partially offset by an impairment charge of $85 million triggered by the expiration of West Coast Powers CDWR contract, resulting in net
earnings of $80 million. Please read Item 1. BusinessSegment DiscussionPower GenerationWest regionWestern Electricity Coordinating Council (WECC) beginning on page 7 for further discussion of West Coast Powers CDWR
contract. West Coast Powers equity earnings of approximately $137 million in 2003 were partially offset by a $20 million charge associated with our 50% share of a goodwill impairment charge recorded by West Coast Power in the fourth quarter
2003. Exclusive of impairments, results at our West Coast Power investment improved from 2003 to 2004 primarily as a result of higher realized margins resulting from hedges put in place in connection with the execution of our CDWR contract.



Earnings for 2004 also include a gain of $15 million on the
sale of our 50% interest in the Oyster Creek facility. In addition to the gain on sale, we reported $5 million of earnings from the Oyster Creek investment. In July 2004, we sold our 50% interest in the Michigan Power generating facility. However,
we recorded impairments of approximately $8 million related to the anticipated sale of Michigan Power, which offset our share of Michigan Powers earnings for 2004. The net loss related to Michigan Power recorded in 2004 was $2 million. In
September 2004, we sold our 50% interest in the Hartwell facility, resulting in a gain of approximately $2 million. Our 2004 earnings from Hartwell, including this gain, were $4 million. Our 2004 earnings from Commonwealth were approximately $2
million. Our 2004 earnings also included $7 million from our investment in Rocky Road, as well as $5 million from our investment in Black Mountain.



Earnings for 2003 also include a $16 million impairment of U.S. investments.



NGL. NGLs earnings from unconsolidated investments were approximately $10 million during 2004 compared
to a loss of $2 million in 2003. NGLs 2003 results were negatively impacted by a $12 million pre-tax impairment on our minority investment in GCF related to the difference between our book value and indicative bids received related to the
possible sale of our minority investment.



CRM.CRMs losses from unconsolidated investments were zero during 2004 compared to $2 million in 2003. As of December 31, 2003, CRM has no material unconsolidated investments. As such, future results are expected to be immaterial.



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##### Index to Financial Statements

Other Items, Net



Other items, net consists of other income and expense items, net, minority interest income (expense) and accumulated
distributions associated with trust preferred securities. Other items, net totaled $(17) million and $6 million for 2004 and 2003, respectively.



The 2004 results included the following items:



| |  |  | $25 million minority interest deduction; partially offset by
| | - |  | ------------------------------------------------------------



| |  |  | $7 million in interest income.
| | - |  | ------------------------------



The 2003 results included the following items:



| |  |  | $12 million in interest income; offset by
| | - |  | -----------------------------------------



| |  |  | $8 million charge for accumulated distributions associated with trust preferred securities.
| | - |  | -------------------------------------------------------------------------------------------



Interest Expense



Interest expense totaled $359 million for 2004, compared with $338 million for 2003. The increase in 2004, as compared to 2003, is primarily attributable
to the following:



| |  |  | Higher average interest rates on borrowings, including the new notes issued in connection with our August 2003 refinancing (approximately $46 million of the increase); and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Higher average principal balances in the 2004 period (approximately $15 million of the increase); offset by
| | - |  | -----------------------------------------------------------------------------------------------------------



| |  |  | Decreased amortization of debt issuance costs (approximately $28 million); and
| | - |  | ------------------------------------------------------------------------------



| |  |  | Lower letter of credit fees (approximately $12 million). The lower letter of credit fees resulted from the restructuring of our credit facility in May 2004, with respect to which
such fees are lower than those contained in our previous facility.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Income Tax Benefit



We reported an income tax benefit from continuing operations of $97 million in 2004, compared to an income tax benefit from continuing operations of $191 million in 2003. These amounts reflect effective rates of 50%
and 42%, respectively. The 2004 tax benefit includes a $15 million benefit related to a reduction in a deferred tax capital losses valuation allowance associated with gains on asset sales. Excluding this item from the 2004 calculation would result
in an effective tax rate of 42%. In general, differences between these adjusted effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to
book-tax basis differences.



Please see Note 13Income
Taxes beginning on page F-40 for further discussion of our income taxes.



Discontinued Operations



Discontinued operations include Northern Natural in Other and Eliminations, our global liquids business in our NGL segment and our U.K. natural gas storage assets and our U.K. CRM business in the CRM segment.



The largest contributor to the pre-tax gain of $20 million ($7 million
after-tax loss) for 2004 is the U.K. CRM business, primarily due to $20 million in tax expenses related to the conclusion of prior year tax audits partially offset by translation gains recognized on the repatriation of cash from the U.K. Please read
Note 13Income Taxes beginning on page F-40 for further discussion.



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##### Index to Financial Statements

The largest contributor to the pre-tax loss of $17 million ($12 million after-tax) for 2003 is $12
million in pre-tax losses on operations of U.K. CRM and the U.K. natural gas storage assets. This loss is associated with costs relating to our exit from these foreign operations.



Cumulative Effect of Change in Accounting Principles



We reflected EITF Issue 02-03s rescission of EITF Issue 98-10
effective January 1, 2003 as a cumulative effect of change in accounting principle. The net impact was a pre-tax benefit of $33 million ($21 million after-tax), of which a benefit of $43 million was recognized in our CRM segment and a charge of $10
million was recognized in our GEN segment. We also adopted SFAS No. 143 effective January 1, 2003 and recognized a pre-tax benefit of $57 million ($36 million after-tax) associated with its implementation in our GEN segment. Finally, we adopted
certain provisions of FIN No. 46R in the fourth quarter 2003 and recognized a pre-tax charge of $23 million ($15 million after-tax) in our GEN segment related to our CoGen Lyondell facility.



Please read Note 2Accounting Policies beginning on page F-10 for
further discussion of our adoption of recent accounting policies.



Year
Ended 2003 Compared to Year Ended 2002



Operating
Loss



Operating loss was $255 million in 2003 and
$1,045 million in 2002.



GEN.Operating income
for the GEN segment was $198 million in 2003, compared with a loss of $171 million in 2002.



Operating loss for 2002 included the following charges:



| |  |  | $315 million impairment of goodwill (please see Note 10Goodwill beginning on page F-33 for further discussion);
| | - |  | ----------------------------------------------------------------------------------------------------------------



| |  |  | $42 million charge associated with this segments allocated portion of costs incurred in connection with our corporate restructuring and related work force reductions (please
see Note 4Restructuring and Impairment ChargesSeverance and Other Restructuring Costs beginning on page F-24 for further discussion);
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | $14 million associated with the impairment of a turbine; and
| | - |  | ------------------------------------------------------------



| |  |  | $6 million associated with fees related to a voluntary action that altered the accounting for certain lease obligations.
| | - |  | ------------------------------------------------------------------------------------------------------------------------



Operating income for 2003 included general and administrative expense of $61
million and depreciation and amortization expense of $185 million. In comparison, operating loss for 2002 included general and administrative expense of $65 million and depreciation and amortization expense of $154 million. Please see
Other beginning on page 54 for a consolidated discussion of general and administrative expense and depreciation and amortization expense.



Operating income in 2003 included a $34 million benefit related to pricing and a $51 million benefit due to generated volumes versus 2002. GENs
results for 2003 reflect higher power prices on average as compared to 2002. This was primarily driven by higher demand in the Midwest and Northeast regions given colder than expected weather conditions during the first half of 2003. Average on-peak
prices in the Midwest and Northeast regions during 2003 increased 39% and 33%, respectively, from the corresponding prices for 2002. The earnings from our peaking generation facilities, which include both capacity and energy sales, were unfavorably
impacted by compressed natural gas spark spreads and overcapacity in the generation marketplace. Overall, volumes



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##### Index to Financial Statements

remained relatively flat to 2002; however, the net MWh in the Midwest and Northeast were 21.1 million and 5.7 million, respectively, for 2003 compared to
20.4 million and 3.6 million, respectively, for 2002.



Operating loss for 2002 included approximately $30 million associated with favorable fuel supply contracts that expired in 2002. Additionally, revenues associated with the DNE facilities decreased approximately $20 million in 2003 as
compared to 2002. This decrease primarily reflects reduced income recognized through amortization of a liability established for a transitional power purchase agreement acquired from the seller of the DNE facilities as part of their acquisition,
which agreement expired in October 2004. Finally, 2003 operating income included an $11 million charge related to a comprehensive settlement agreement with a manufacturer of turbines in which we agreed in principle to forfeit a prepayment in the
amount of $11 million.



GENs reported operating income
for the 2003 and 2002 periods included approximately $7 million and $8 million, respectively, of mark-to-market income related to derivative contracts that did not qualify as hedges.



In December 2003, we tested certain 100% owned assets for impairment in accordance with SFAS No. 144, based on the
identification of certain trigger events. These triggers indicated that our Bluegrass, Calcasieu, Riverside, Rockingham and Rolling Hills peaking facilities could be impaired due to decreased spark spreads and other market factors. After performing
these tests, we concluded that no impairment was necessary as the estimated undiscounted cash flows exceeded the book value of the respective asset.



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



NGL.Operating income for the NGL segment was $170 million in 2003, compared to $77 million in 2002. Operating
income for 2003 included general and administrative expense of $37 million and depreciation and amortization expense of $81 million. 2003 operating income also included a $25 million gain associated with the sale of our Hackberry LNG project. Please
see Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationHackberry LNG Project beginning on page F-21 for further discussion. Operating income for 2002 included $19 million in
charges relating to this segments allocated portion of costs incurred in connection with our corporate restructuring and related work force reductions, as well as general and administrative expense of $36 million and depreciation and
amortization expense of $88 million. Please see Other beginning on page 54 for a consolidated discussion of general and administrative expense and depreciation and amortization expense.



The increase in operating income in 2003 as compared to 2002 relates
primarily to the upstream business. For 2003 we experienced higher natural gas and natural gas liquids prices, which resulted in a significant increase in processing plant margins at our field plants. In addition to favorable pricing, volumes of
natural gas liquids produced at our field plants were 6% higher in 2003 as compared to 2002. This was primarily due to increased production in the highly active drilling area in North Texas. Our 2003 straddle plant volumes were much lower as
compared to 2002 because of the low frac spread for 2003, which resulted in our decision to by-pass unprofitable gas or to shut-down some of our plants that are subject to significant frac spread risk and whose contract mix is substantially made up
of KW contracts.



In our downstream business, volumes available
for fractionation declined to 185 MBbls in 2003 compared to 215 MBbls per day in 2002 as a direct result of reduced natural gas liquids recovery from both our own and from third-party gas processing plants due to the low frac spread. Additionally,
some of our competitors recent expansion of Mont Belvieu area fractionation capacity beyond the availability of raw natural gas liquids supplies has increased competition for supplies, leading to lower fees charged for fractionation service in
the area.



In our wholesale marketing operations, profits were
higher due to margin increases resulting from weather-driven propane sales in the first quarter of 2003 and the impact of higher commodity prices on contracts where



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##### Index to Financial Statements

we retain a percentage of the sales price as our fee for marketing natural gas liquids on behalf of others, such as in our refinery services agreements and
our natural gas liquids marketing agreements with ChevronTexaco. NGLs marketing results declined from prior period levels as a result of reduced overall market liquidity and customer concerns relating to our liquidity and non-investment grade
credit status. Finally, downstream operating income for 2002 included income of approximately $18 million related to our Canadian crude business, which was sold in August 2002. Although our marketed volumes declined from approximately 498,800
barrels per day in 2002 to approximately 311,700 barrels per day during 2003 due to reduced domestic marketing opportunities and the divestiture of our global liquids business, effective January 1, 2003, this decline had little impact on our
operating income, as the financial impact of our global liquids business is included in discontinued operations for all periods presented. The global liquids business sold an average of 95,500 barrels per day in 2002.



CRM.Operating loss for the CRM segment was $385 million in
2003 compared to $951 million in 2002.



Results for 2003 were
impacted by the following pre-tax losses:



| |  |  | $133 million charge associated with the settlement of power tolling arrangements with Southern Power, for which we paid $155 million;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------



| |  |  | $121 million mark-to-market loss on contracts associated with the Independence power tolling arrangement;
| | - |  | ---------------------------------------------------------------------------------------------------------



| |  |  | $34 million charge associated with the cash settlement of the Batesville tolling arrangement; and
| | - |  | -------------------------------------------------------------------------------------------------



| |  |  | $30 million charge associated with the settlement of power supply agreements with Kroger, for which we received approximately $110 million.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------



In addition, 2003 results include losses associated with fixed payments on
power tolling arrangements in excess of realized margins on power generated and sold pursuant to these arrangements. These items were offset by gains totaling approximately $61 million associated with sales of natural gas in storage which had
previously been recorded at fair value, partially offset by $21 million of charges associated with settlements of legacy contracts. Please read Note 2Accounting PoliciesRevenue Recognition beginning on page F-14 for additional details.



Results for 2002 were impacted by the following items:



| |  |  | $325 million charge for the impairment of goodwill (for further information, please see Note 10Goodwill beginning on page F-33);
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------



| |  |  | $73 million in costs associated with our corporate restructuring and related work force reductions (for further information, please see Note 4Restructuring and Impairment
ChargesSeverance and Other Restructuring Costs beginning on page F-24);
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | $25 million in charges associated with the settlement of tolling contracts;
| | - |  | ---------------------------------------------------------------------------



| |  |  | $25 million in charges associated with the write-off of our investment in Dynegydirect; and
| | - |  | -------------------------------------------------------------------------------------------



| |  |  | $7 million in losses associated with the sale of our Canadian physical gas business to Seminole.
| | - |  | ------------------------------------------------------------------------------------------------



In addition, 2002 results included general and administrative expense of $154 million and depreciation and amortization
expense of $28 million. Please see Other below for a consolidated discussion of general and administrative expense and depreciation and amortization expense. Finally, 2002 results were negatively impacted by reduced gas marketing
volumes as a result of reduced market liquidity and our lower credit ratings.



During 2002, our CRM segment was actively managed as part of our ongoing strategy and its results included, in part, settlement with third parties of physical power and other trading positions purchased from our GEN
segment at an internally determined transfer price. Please read Note 18Segment Information beginning on page F-64 for further discussion.



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Other. Other operating loss was $238 million in 2003, compared to zero in 2002. The loss in
2003 primarily relates to general and administrative expenses and depreciation and amortization expenses which are incurred at a corporate level. Prior to 2003, these costs were allocated to the segments.



Consolidated general and administrative expenses were $293 million in 2003,
compared to $255 million in 2002. The $38 million increase year over year is principally the result of the $50 million second quarter 2003 litigation reserve and higher professional fees, offset by significantly lower compensation costs in the 2003
period resulting from the work force reductions.



Consolidated
depreciation and amortization expenses were $330 million in 2003, compared to $270 million in 2002. The $60 million increase year over year is primarily due to increased depreciation of generation assets due to an increased asset base. Increases in
our asset base include the construction of the Renaissance, Bluegrass and Foothills facilities in 2002 and the completion of Rolling Hills in 2003.



Earnings (Losses) from Unconsolidated Investments



Our earnings from unconsolidated investments were approximately $132 million during 2003 compared to losses of $52 million in 2002. Both 2002 and 2003
results include significant impairment charges related to these investments, primarily associated with the GEN segment.



GEN. GENs earnings from unconsolidated investments were approximately $136 million during 2003 compared to a loss of $45 million in
2002.



Our West Coast Power investment was the primary driver
of equity earnings for both periods. West Coast Power provided earnings of $117 million in 2003 compared to $17 million in 2002. Earnings for 2003 include a $20 million charge associated with our 50% share of a goodwill impairment charge recorded by
West Coast Power in the fourth quarter 2003. Earnings for 2002 include a $50 million charge associated with our 50% share of a bad debt allowance recognized by West Coast Power, as well as a $33 million charge to write down our investment to fair
value. Exclusive of these items, West Coast Powers improved results from 2002 to 2003 were driven by increased earnings under the CDWR contract.



In 2003, we recorded a $16 million impairment of our investments in Michigan Power, Commonwealth and Black Mountain, because of our determination that
current market value was less than the book values of the investments. In 2002, we recorded a $117 million impairment of U.S. investments, of which $33 million related to West Coast Power, as discussed above. We assessed the carrying value of our
generation portfolio on an asset-by-asset basis and determined that the fair value of some of our U.S. investments was less than our book value. The diminution in the fair value of these investments was primarily a result of depressed energy prices.



NGL. NGLs losses from unconsolidated
investments were approximately $2 million during 2003 compared to earnings from unconsolidated investments of $14 million in 2002. NGLs 2003 results were negatively impacted by a $12 million pre-tax impairment on our minority investment in GCF
related to the difference between our book value and indicative bids received related to the possible sale of our minority investment. In addition, WTLPS, which we sold to ChevronTexaco in August 2002, contributed approximately $6 million to our
results for 2002.



CRM.CRMs losses from
unconsolidated investments were $2 million during 2003 compared to $21 million in 2002. As of December 31, 2003, CRM had no material unconsolidated investments. As such, future results are expected to be immaterial. The 2002 loss is primarily
comprised of charges allocated to the CRM segment for impairments associated with technology investments.



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Other Items, Net



Other items, net consists of other income and expense items, net, minority interest income (expense) and accumulated
distributions associated with trust preferred securities. Other items, net totaled $6 million and $(74) million for 2003 and 2002, respectively.



The 2003 results included the following items:



| |  |  | $12 million in interest income; offset by
| | - |  | -----------------------------------------



| |  |  | $8 million charge for accumulated distributions associated with trust preferred securities.
| | - |  | -------------------------------------------------------------------------------------------



The 2002 results included the following items:



| |  |  | $25 million in interest income;
| | - |  | -------------------------------



| |  |  | $36 million minority interest deduction, primarily related to ABG Gas Supply and Black Thunder;
| | - |  | -----------------------------------------------------------------------------------------------



| |  |  | $22 million charge relating to the cancellation of our natural gas purchases and sales contract with ChevronTexaco;
| | - |  | -------------------------------------------------------------------------------------------------------------------



| |  |  | $19 million charge associated with the settlement of the Enron litigation relating to the termination of our proposed merger;
| | - |  | -----------------------------------------------------------------------------------------------------------------------------



| |  |  | $13 million charge for accumulated distributions associated with trust preferred securities;
| | - |  | --------------------------------------------------------------------------------------------



| |  |  | $10 million charge primarily related to our settlements with the CFTC ($4 million) and SEC ($3 million); and
| | - |  | ------------------------------------------------------------------------------------------------------------



| |  |  | Remaining amounts consisting of individually insignificant items.
| | - |  | -----------------------------------------------------------------



Interest Expense



Interest expense totaled $338 million for 2003, compared with $187 million for 2002. The significant increase in 2003, as compared to 2002, is primarily
attributable to the following higher average interest rates on borrowings, including the new notes issued in connection with our August 2003 refinancing, and higher average principal balances in the 2003 period. The increase is also due to the
following:



| |  |  | Interest expense for 2002 does not include approximately $41 million of interest expense which was allocated to our discontinued businesses;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Increased amortization of debt issuance costs (approximately $38 million of the increase, of which approximately $24 million relates to accelerated amortization of previously
incurred financing costs and the settlement value of the associated interest rate hedge instruments); and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Higher letter of credit fees (approximately $15 million of the increase). The higher letter of credit fees resulted from the restructuring of our credit facility in April 2003, with
respect to which such fees are higher than those contained in our previous facility.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Income Tax Benefit



We reported an income tax benefit from continuing operations of $191 million in 2003, compared to an income tax benefit from continuing operations of $366
million in 2002. These amounts reflect effective rates of 42% and 27%, respectively. The 2002 effective rate was impacted significantly by the $640 million goodwill impairment relating to the CRM and GEN segments in 2002. As there was no tax basis
in $405 million of the goodwill, there were no tax benefits associated with the charges. Excluding this item from the 2002 calculations would result in an effective tax rate of 38%. In general, differences between the adjusted effective rate and the
statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences.



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##### Index to Financial Statements

Please see Note 13Income Taxes beginning on page F-40 for further discussion of our income taxes.



Discontinued Operations



Discontinued operations include Northern Natural in Other and Eliminations,
our global liquids business in the NGL segment and our U.K. natural gas storage assets and our U.K. CRM business in the CRM segment.



The largest contributor to the pre-tax loss of $17 million ($12 million after-tax) for 2003 is $12 million in pre-tax losses on operations of U.K. CRM and
the U.K. natural gas storage assets. This loss is associated with costs relating to our exit from these foreign operations.



During 2002, the $113 million pre-tax loss ($100 million after-tax) from discontinued operations was primarily comprised of $51 million in pre-tax losses
($49 million after-tax) from CRM. The CRM pre-tax loss consisted of $115 million in losses associated with the U.K. CRM business offset by $64 million in income from our U.K. natural gas storage assets. The global liquids pre-tax loss of $37 million
($29 million after-tax) included a pre-tax charge of approximately $12 million associated with the impairment of an LPG investment in the global liquids business. The remaining $25 million loss related to the write-off of a logistics and accounting
computer system and other costs associated with the wind-down of the business. In addition, discontinued operations includes $25 million in pre-tax losses ($22 million after tax) from Northern Natural. In August 2002, we sold Northern Natural to
MidAmerican and incurred a pre-tax loss of approximately $63 million associated with the sale. Discontinued operations for the other segment in 2002 also includes $38 million in pre-tax earnings associated with operating results from Northern
Natural prior to its sale.



Cumulative Effect of
Change in Accounting Principles



We reflected EITF
Issue 02-03s rescission of EITF Issue 98-10 effective January 1, 2003 as a cumulative effect of a change in accounting principle. The net impact was a pre-tax benefit of $33 million ($21 million after-tax), of which a benefit of $43 million
was recognized in our CRM segment and a charge of $10 million was recognized in our GEN segment. We also adopted SFAS No. 143 effective January 1, 2003 and recognized a pre-tax benefit of $57 million ($36 million after-tax) associated with its
implementation in our GEN segment. Finally, we adopted certain provisions of FIN No. 46R in the fourth quarter 2003 and recognized a pre-tax charge of $23 million ($15 million after-tax) in our GEN segment related to our CoGen Lyondell
facility.



On January 1, 2002, we adopted SFAS No. 142.
In connection with its adoption, we realized a cumulative effect loss of approximately $234 million associated with a write-down of goodwill associated with our discontinued communications business.



2005 Outlook



The following summarizes our 2005 outlook for our three reportable segments.



GEN Outlook.We expect that this segments
future financial results will continue to reflect sensitivity to commodity prices and weather conditions. We will continue our efforts to manage price risk through the optimization of fuel procurement and the marketing of power generated from our
assets, including through forward sales and related transactions, consistent with our views on market recovery in the regions we serve. Our sensitivity to commodity prices and our ability to manage this sensitivity is subject to a number of factors,
including general market liquidity, particularly in forward years, our ability to provide necessary collateral support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings. Additionally,
because we may seek to manage price risk through forward sales and related transactions, at times we may be unable to capture opportunities presented by rising prices.



The operation of our generation facilities is highly dependent on our ability to procure coal as a fuel. Power generators in
the Midwest and the Northeast have experienced significant pressures on available coal supplies



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that are either transportation or supply related. Our long-term supply and transportation agreements for our Midwest fleet mitigate these concerns. In the
Northeast, we have accumulated sufficient inventories to allow us to operate our assets. While we believe our physical inventories and contractual commitments provide us with a stable fuel supply, we are subject to physical delivery risks outside of
our control.



As discussed in Item 1. BusinessSegment
DiscussionPower Generation beginning on page 2 we enter into sales of capacity from our generation assets, which provide a revenue stream independent of energy sales. During 2004, we have seen increases in the market for capacity-related
products from our peaking and intermediate generation facilities.



Throughout 2004, a substantial portion of our operating margin and earnings from unconsolidated investments was under contract or hedged. The primary contracts included the CDWR contract held by West Coast Power and the Illinois Power power
purchase agreement, both of which terminated in December 2004. Our future results of operations will be significantly impacted by the expiration of the CDWR contract. West Coast Power, whose equity earnings were primarily derived from the CDWR
contract, has been our largest contributor to earnings from unconsolidated investments. As a result of the expiration of the CDWR contract, future earnings from the investment will be substantially reduced. Please read Item 1. BusinessSegment
DiscussionPower Generation beginning on page 2 for a discussion of West Coast Powers current contractual arrangements. Based on our ongoing evaluation of strategic alternatives for our West Coast Power assets, we determined that it was
not economically feasible to continue to operate our Long Beach generation facility beyond the expiration of the CDWR contract. Therefore, we retired the asset as of January 1, 2005. Additionally, the expiration of the CDWR contract in December 2004
had a negative impact on the fair value of our investment in West Coast Power. As a result, we recorded an impairment of $73 million in 2004. Our 2004 equity earnings also included a charge of $12 million, representing our 50% share of West Coast
Powers impairment of certain generation assets. This impairment was also triggered by the expiration of the CDWR contract. Please read Note 14Commitments and ContingenciesSummary of Material Legal ProceedingsFERC and Related
Regulatory InvestigationsRequest for Refunds beginning on page F-47 for further discussion of the legal challenges to the CDWR contract. Please also read Liquidity and Capital ResourcesInternal Liquidity SourcesCash
Flows from Operations beginning on page 39 for a discussion of our efforts to seek a replacement of the CDWR contract.



Our former power purchase agreement between DMG and Illinois Power terminated in December 2004. In September 2004, in connection with Dynegys sale
of Illinois Power to Ameren, DPM entered into a new two-year power purchase agreement with Illinois Power with expected volumes comparable to the former agreement. Under the terms of this new agreement, which became effective January 1, 2005, we
have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48.00 per kW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. Under the new agreement, we are no longer the provider of last resort for
Illinois Power, which exposed us to volume and price uncertainties under the former agreement. Under the former agreement, we received contract revenues based on a higher fixed capacity payment and lower variable energy payments. Accordingly,
GENs operating income under the new agreement will be impacted more significantly by deviations from expected energy purchases by Illinois Power. We expect that any reduction in operating income under this new agreement will be mitigated by no
longer serving as the provider of last resort.



During
2004, we sold our 50% interests in the Oyster Creek, Michigan Power, Hartwell, and Commonwealth facilities. Our 2004 results include an aggregate $14 million of earnings from these investments and $17 million of net gains on sales. For 2003, these
investments contributed $17 million to earnings. However, beginning in 2005, the lost earnings from these assets will no longer be offset by gains on sale.



NGL Outlook.The financial outlook for our NGL segment is sensitive to natural gas and natural gas liquids prices. The pricing environment
for 2005 is expected to be strong with high volatility for commodities driving our market, similar to 2004, when we experienced high volatility in both natural gas and natural gas liquids prices. Provided the strong pricing environment persists
throughout 2005, our upstream contract settlements



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under POP and POL contracts will continue to benefit. However, high natural gas prices without a comparable upward movement in natural gas liquids prices
would reduce frac spreads to levels where it is no longer profitable to extract natural gas liquids. If frac spreads are reduced to unprofitable levels, our hybrid contracts, sensitive to frac spreads, will switch from POL settlements to fee
settlements, which would negatively impact our earnings in a high natural gas liquids price environment. Frac spread volatility will impact natural gas liquids volumes produced from our own and third party natural gas processing plants as frac
spread economics either do or do not support natural gas liquids extraction. In 2005, the U.S. and world economies are expected to grow, though not as rapidly as 2004. This growth will continue to support demand for products from the petrochemical
industry, which experienced a dramatic improvement in 2004. The industrys improvement was due in part to strong world-wide ethylene and propylene demand, driving higher natural gas liquids feedstock consumption, and helping to improve frac
spreads. This increased demand for natural gas liquids feedstocks will continue to benefit our results.



There seems to be a widely held belief that, long term, natural gas prices will remain high enough relative to natural gas liquids prices to depress the
frac spread below levels required for liquids extraction, reducing natural gas liquid volumes requiring fractionation. As a result, there remains aggressive competition between fractionators for available volumes, driving fees paid for fractionation
services to historic lows. In October 2004, we lost a substantial fractionation customer at our Mont Belvieu fractionator when the previous contract reached the end of its primary term. The customer had committed the volumes to a competitor as part
of a larger asset sale. We continue to aggressively compete for replacement volumes albeit in a highly competitive market.



Straddle plant gas processing will continue to be impacted by uncertainty surrounding natural gas quality specifications for liquefiable hydrocarbons.
Other than occasional short-term periods of favorable natural gas liquids extraction economics, market conditions for straddle plant gas processing have been generally poor since late 2000. Pipeline companies have operational and safety concerns
related to the heavier natural gas liquids, like butane and natural gasoline, that are left in the natural gas entering their systems instead of being extracted. While industry stakeholders respond to recent FERC decisions directing pipeline
companies to address this issue in their tariff, there is a lack of clarity around when and where processing is required, especially during periods of poor extraction economics. The result is a patchwork of pipeline policies and practices that leave
producers and processors without clearly defined ground rules, making contracting gas supply and planning straddle plant operations difficult. Resolution of the issue is currently being pursued through the Natural Gas Council, FERC and other
affected stakeholders.



Drilling for natural gas throughout our
core processing areas in New Mexico, West Texas, North Texas and offshore Louisiana continues to increase, consistent with natural gas prices that have averaged $6/MMBtu. Continued exploration and production at these commodity price levels will
benefit our upstream business by providing additional volumes for gathering and processing. In the Permian, continued property sales by major exploration and production companies to smaller independent producers will contribute to increased activity
and exploration. If natural gas prices were to decline significantly in the future, resulting in reduced drilling activities, this segments results could be adversely affected.



While we have not experienced significant turnover in customer contracts as a result of our non-investment grade credit
ratings, we have been required to provide collateral or other adequate assurance of our obligations in connection with many of our commercial relationships. On occasion, we have been unable to satisfy efficiently a potential new customers
concerns about our credit ratings. We expect similar collateral requirements until such time as our credit ratings measurably improve.



At this time it is our strategy to not sell forward future natural gas liquids production; however, any change in this strategy resulting in a desire to
hedge future natural gas liquids production during 2005 may again be limited by reduced market liquidity and our obligation to post collateral. As commodity prices rise, we are required by counterparties to post additional collateral.



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We intend to continue prudently expanding our North Texas gathering system, working collaboratively with
our producer customers. Additional compression and pipeline reach along with plant debottlenecking are expected to add volumes to our expanded Chico gas processing plant In addition, we continue to review our asset portfolio to maximize return on
investment. In 2004, we identified and sold several assets that were not strategic to our core operations, including our final financial interest in Hackberry LNG, our interest in the Indian Basin plant and our Sherman facility. We may pursue sale
of other assets if the price is sufficient to mitigate the anticipated impact on future earnings. Please see Liquidity and Capital ResourcesExternal Liquidity SourcesAsset Sale Proceeds beginning on page 40 for further
discussion.



CRM Outlook.Our CRM business
future results of operations will be significantly impacted by our ability to complete our exit from this business. During 2004, we were successful in reaching agreements to exit four of our natural gas transportation agreements. In November 2004,
we entered into a back-to-back power purchase agreement with a subsidiary of Constellation, under which we will receive $161 million in payments through November 2008 to offset our fixed payment obligations under our Kendall tolling
arrangement, while positioning us to take advantage of the market recovery expected in 2008 and beyond. In January 2005, Dynegy completed its purchase from Exelon Corporation of all of the outstanding capital stock of ExRes SHC, Inc., the parent
company of Sithe Energies and Independence. Please read Note 20Subsequent Events beginning on page F-70 for further discussion. The acquisition transformed the tolling and swap contracts into Dynegy intercompany (and our affiliate) agreements.
Other than the reporting of the transactions with Independence as affiliate transactions, we do not anticipate any other material impact to us from the transaction. Our Gregory tolling arrangement expires by its terms in July 2005.



Our Sterlington tolling arrangement remains in place through 2017. We are
exploring opportunities to assign or renegotiate the terms of this arrangement, but we cannot guarantee that we will be successful. If we do not renegotiate or terminate this remaining arrangement, it will continue to impact negatively our near- and
long-term earnings and cash flows based on the current pricing environment. Any renegotiation or termination of this long-term contract would likely result in significant cash payments and a charge to earnings in the applicable period. For a
discussion of our annual and long-term obligations under these arrangements, please read Disclosure of Contractual Obligations and Contingent Financial Commitments beginning on page 34 and Item 1. BusinessSegment
DiscussionCustomer Risk Management beginning on page 17.



CASH FLOW DISCLOSURES



The following tables
include data from the operating section of the 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 the consolidated
statements of operations:



|                             |  |               |     |     |   |     |  |   |                     |   |  |              |      |   |  |   |      |  
|---------------------------- |  | ------------- | --- | --- | - | --- |  | - | ------------------- | - |  | ------------ | ---- | - |  | - | ---- | -
|                             |  | GEN           |     | NGL |   | CRM |  |   | Other &Eliminations |   |  | Consolidated |     
|                             |  | (in millions) |    
|Year Ended December 31, 2004 |  | $             | 419 |     | $ | 278 |  | $ | (371                | ) |  | $            | (486 | ) |  | $ | (160 | )
|                             |  |               |     |     |   |     |  |   |                     |   |  |              |      |   |  |   |      |  
|Year Ended December 31, 2003 |  | $             | 418 |     | $ | 186 |  | $ | 496                 |   |  | $            | (340 | ) |  | $ | 760  |  
|                             |  |               |     |     |   |     |  |   |                     |   |  |              |      |   |  |   |      |  
|Year Ended December 31, 2002 |  | $             | 258 |     | $ | 24  |  | $ | (318                | ) |  | $            | 62   |   |  | $ | 26   |  
|                             |  |               |     |     |   |     |  |   |                     |   |  |              |      |   |  |   |      |  



Operating Cash
Flow. Our cash flow used in operations totaled $160 million for the 12 months ended December 31, 2004. During the period, our GEN and NGL segments provided positive cash flow from operations. GEN provided cash flow from operations of $419
million due primarily to positive earnings for the period and increased business activity, partially offset by increased cash collateral posted in lieu of letters of credit; NGL provided cash flow from operations of $278 million due primarily to
positive earnings, partially offset by increased prepayments due to higher sales. Our CRM segment used approximately $371 million in cash



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due primarily to fixed payments associated with the power tolling arrangements and related gas transportation agreements, a $117.5 million payment related to
the restructuring of the Kendall toll, increased cash collateral posted in lieu of letters of credit and our exit from four long-term natural gas transportation contracts. Other & Eliminations includes a use of approximately $486 million in cash
due primarily to interest payments to service debt, settlement payments and general and administrative expenses.



Cash provided in 2003 primarily relates to collateral returns, settlements of risk management assets and sales of natural gas storage in excess of $500
million from our CRM business, an $85 million income tax refund and solid operational performances from our GEN and NGL segments. Despite a relatively weak commodity price environment, our GEN segment provided cash flows in excess of $400 million
largely due to effective commercial and operational management and our coal- and dual-fired generation assets. Similarly, our NGL segment contributed cash flows from operations in excess of $180 million due to a strong commodity price environment,
particularly in the upstream business, offset by increases in prepayments and lower downstream results due to industry-wide reductions in volumes available for fractionation. General and administrative costs offset these positive operational cash
flows during 2003.



For 2002, our cash flow provided by
operations was $26 million. When compared to 2003, the primary driver of our operating cash outflows was our required posting during 2002 of significant amounts of collateral under the terms of our CRM commercial contracts due to the degradation of
our credit ratings.



Capital Expenditures and Investing
Activities. Net cash used in investing activities during 2004 totaled $211 million. Capital spending of $219 million was comprised primarily of $145 million and $61 million in the GEN and NGL segments, respectively. The capital spending for
our GEN segment related primarily to maintenance capital projects, as well as approximately $41 million related to developmental projects. Capital spending in our NGL segment related primarily to maintenance capital projects and wellconnects, as
well as approximately $21 million on developmental projects.



Net cash proceeds from asset sales of $246 million consisted of the following items:



| |  |  | $147 million from the sale of our equity investments in the Oyster Creek, Hartwell, Michigan Power and Commonwealth generating facilities;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | $48 million from the sale of Indian Basin;
| | - |  | ------------------------------------------



| |  |  | $34 million from the sale of Sherman; and
| | - |  | -----------------------------------------



| |  |  | $17 million from the sale of our remaining financial interest in the Hackberry LNG project.
| | - |  | -------------------------------------------------------------------------------------------



Cash used in investing activities for 2003 totaled $423 million. Our capital spending totaled $205 million and was primarily
comprised of routine capital maintenance of our existing asset base. Of this amount, we spent approximately $40 million on the construction of Rolling Hills, which began commercial operations in June 2003. Our proceeds from asset sales totaled
approximately $58 million and primarily relate to our sale of Hackberry LNG Terminal LLC ($35 million) and SouthStar ($20 million).



During 2002, cash provided by investing activities totaled $804 million. Our capital spending totaled $735 million and was primarily comprised of
improvements to the existing asset base. Of this amount, we spent approximately $195 million on the construction of Rolling Hills. Additionally, we incurred $54 million in capital expenditures associated with information technology. Business
acquisitions of $20 million relate to our acquisition of Northern Natural, net of cash acquired. We received $715 million in proceeds from asset sales primarily from the sales of Northern Natural in August 2002, the Hornsea gas storage facility in
September 2002 ($189 million) and the Rough gas storage facility in November 2002 ($500 million). Other investing activities include proceeds from the sale of Northern Natural bonds.



Financing Activities. Net cash provided by financing activities during 2004 totaled $289 million. Our
financing cash outflows were primarily related to repayments of long-term debt totaling $267 million and



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consisted primarily of the following payments: (1)$185 million under our ABG Gas Supply financing; and (2)$78 million on the Tilton capital lease. These
repayments of long-term debt were offset by proceeds from our $600 million secured term loan, net of issuance costs of $19 million. We made distributions to minority interest owners totaling $32 million.



During 2003, cash used for financing activities totaled $652 million. The
following summarizes significant items:



| |  |  | Repayments of $128 million, net, under our revolving credit facilities;
| | - |  | -----------------------------------------------------------------------



| |  |  | Long-term debt proceeds, net of issuance costs, for 2003 totaled $1.9 billion and consisted of: (1) $311 million associated with the October 2003 follow-on offering of our senior
notes; (2) $1,393 million associated with our August 2003 refinancing transaction, and (3) $159 million from the Term A loan drawn in connection with the April 2003 credit facility restructuring;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Repayments of long-term debt totaled $2.4 billion and consisted of: (1) $696 million prepayment of the outstanding balance under the Black Thunder financing; (2) $609 million
purchase of our previously outstanding 2005/2006 senior notes; (3) $360 million prepayment of the Term B loan outstanding under our April 2003 restructured credit facility; (4) $200 million prepayment of the Term A loan outstanding under our April
2003 restructured credit facility; (5) $200 million in payments under the Renaissance and Rolling Hills interim financing; (6) $165 million payment in full for the GEN facility capital lease; (7) $74 million in payments under the ABG Gas Supply
financing; (8) $62 million in payments under the Black Thunder secured financing prior to its prepayment; and
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Distributions to minority interest owners totaling $21 million.
| | - |  | ---------------------------------------------------------------



During 2002, cash used for financing activities totaled $282 million. The following summarizes significant items:



| |  |  | Net long-term debt proceeds consisted primarily of our February 2002 issuance of $500 million of 8.75% senior notes due February 2012 and proceeds from the ABG Gas Supply
financing;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Repayments of long-term borrowings consisted of: (1) $90 million relating to the April 2002 purchase of Northern Naturals senior unsecured notes due 2005; (2) $92
million in principal payments related to the Black Thunder financing; (3) $200 million relating to the July 2002 6.875% senior note repayment; and (4) $59 million in repayments under the ABG Gas Supply financing;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In July 2002, we completed a $200 million interim financing secured by interests in our Renaissance and Rolling Hills merchant power generation facilities. In June 2002, we
completed a $250 million interim financing representing an advance on a portion of the proceeds from the sale of our U.K. natural gas storage facilities. In September 2002, we sold the entity that owned the Hornsea storage facility, and, in October
2002, we repaid approximately $189 million of this interim financing with the proceeds. In November 2002, we sold the entities that owned the Rough facilities and repaid the remaining balance of this financing with a portion of the proceeds; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Repayments of commercial paper borrowings and revolving credit facilities totaled approximately $614 million in the aggregate and borrowings totaled an aggregate of
approximately $136 million under the revolving credit facilities.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



SEASONALITY



Our
revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power, natural gas, and natural gas liquids. Power marketing operations and generating
facilities have higher volatility and demand, respectively, in the summer cooling months. This trend may change over time as demand for natural gas increases in the summer months as a result of increased gas-fired electricity generation. Our liquids
businesses are also subject to seasonal factors impacting both volumes and prices.



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CRITICAL ACCOUNTING POLICIES



Our Accounting Department is responsible for the development and application of accounting policy and control procedures.
This department conducts these activities independent of any active management of our risk exposures, is independent of our business segments and reports to the Chief Financial Officer.



The process of preparing financial statements in accordance with GAAP requires our management to make estimates and
judgments. It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments. We have identified the following six critical accounting policies
that require a significant amount of estimation and judgment and are considered to be important to the portrayal of our financial position and results of operations:



| |  |  | Revenue Recognition;
| | - |  | --------------------



| |  |  | Valuation of Tangible and Intangible Assets;
| | - |  | --------------------------------------------



| |  |  | Estimated Useful Lives;
| | - |  | -----------------------



| |  |  | Accounting for Contingencies, Guarantees and Indemnifications;
| | - |  | --------------------------------------------------------------



| |  |  | Accounting for Income Taxes; and
| | - |  | --------------------------------



| |  |  | Valuation of Pension Assets and Liabilities.
| | - |  | --------------------------------------------



Revenue Recognition



We utilize two comprehensive accounting models in reporting our consolidated financial position and results of operations as required by GAAPan
accrual model and a fair value model. We determine the appropriate model for our operations based on guidance provided in applicable accounting standards and positions adopted by the FASB or the SEC. We have applied these accounting policies on a
consistent basis during the three years in the period ended December 31, 2004, except as required by the adoption of EITF Issue 02-03, which rescinded EITF Issue 98-10.



The accrual model has historically been used to account for substantially all of the operations conducted in our GEN and NGL
segments. These segments consist largely of the ownership and operation of physical assets that we use in various generation, processing and delivery operations. The business of these segments includes the generation of electricity, the separation
of natural gas liquids into their component parts from a stream of natural gas and the transportation or transmission of commodities through pipelines or over transmission lines. End sales from these businesses result in physical delivery of
commodities to our wholesale, commercial, industrial and retail customers. We recognize revenue from these transactions when the product or service is delivered to a customer.



The fair value model has historically been used to account for certain forward physical and financial transactions,
occurring primarily in the CRM and GEN segments, which meet criteria defined by the FASB or the EITF. The criteria are complex, but generally require these contracts to relate to future periods, to contain fixed price and volume components and to
have terms that require or permit net settlement of the contract in cash or the equivalent. The FASB determined that the fair value model is the most appropriate method for accounting for these types of contracts. In part, this conclusion is based
on the cash settlement provisions in these agreements, as well as the volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, which impact the valuation of these contracts. Since these transactions may be settled
in cash or the equivalent, the value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current prices and rates as of each balance sheet date.



We estimate the fair value of our marketing portfolio using a liquidation
value approach assuming that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is



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computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a time value of money adjustment and deduction of reserves
for credit and price. The estimated prices in this valuation are based either on (1) prices obtained from market quotes, when there are an adequate number of quotes to consider the period liquid, or, if market quotes are unavailable, or the market
is not considered to be liquid, (2) prices from a proprietary model which incorporates forward energy prices derived from market quotes and values from previously executed transactions. The amounts recorded as revenue change as these estimates are
revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control.



Typically, derivative contracts can be accounted for in three different ways: (1) as an accrual contract, if the criteria for the normal purchase
normal sale exemption are met and documented; (2) as a cash flow or fair value hedge, if the criteria are met and documented; or (3) as a mark-to-market contract with changes in fair value recognized in current period earnings. Generally, we
only mark-to-market through earnings our derivative contracts if they do not qualify for the normal purchase normal sale exemption or as a cash flow hedge. Because derivative contracts can be accounted for in three different ways, and as
the normal purchase normal sale exemption and cash flow hedge accounting are elective, the accounting treatment used by another party for a similar transaction could be different than the accounting treatment we use.



Valuation of Tangible and Intangible Assets



We evaluate long-lived assets, such as property, plant and equipment,
investments and goodwill, when events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows sufficient to indicate that the carrying value of such assets may not be recoverable. Factors we
consider important, which could trigger an impairment analysis, include, among others:



| |  |  | significant underperformance relative to historical or projected future operating results;
| | - |  | ------------------------------------------------------------------------------------------



| |  |  | significant changes in the manner of our use of the assets or the strategy for our overall business;
| | - |  | ----------------------------------------------------------------------------------------------------



| |  |  | significant negative industry or economic trends; and
| | - |  | -----------------------------------------------------



| |  |  | significant declines in stock value for a sustained period.
| | - |  | -----------------------------------------------------------



We assess the carrying value of our property, plant and equipment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of
Long-Lived Assets. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the related discounted cash flows of the assets and recording a loss if the resulting estimated fair value is less
than the book value. For assets identified as held for sale, the book value is compared to the estimated fair value, which may also include estimates based upon comparables or quoted market prices, to determine if an impairment loss is required.
Please see Note 4Restructuring and Impairment Charges beginning on page F-23 for discussion of impairment charges we recognized for 2004, 2003 and 2002.



We follow the guidance of APB 18, The Equity Method of Accounting for Investments in Common Stock, SFAS No. 115, Accounting for
Certain Investments in Debt and Equity Securities, and EITF No. 02-14, Whether an Investor Should Apply the Equity Method of Accounting to Investments Other Than Common Stock, when reviewing our investments. The book value of the
investment is compared to the estimated fair value, based either on discounted cash flow projections or quoted market prices, if available, to determine if an impairment is required. We record a loss when the decline in value is considered other
than temporary.



We follow the guidance set forth in SFAS No.
142, Goodwill and Other Intangible Assets, when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis or when certain events warrant an assessment. Our evaluation is based,
in part, on our estimate of future cash flows. Please see Note 10Goodwill beginning on page F-33 for discussion of impairment charges we recognized in 2002.



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Our assessments regarding valuation of tangible and intangible assets are subject to estimates and
judgment of management. Market conditions, energy prices, estimated useful lives of the assets, discount rate assumptions and legal factors impacting our business may have a significant effect on the estimates and judgment of management. If
different judgments were applied, estimates could differ significantly. Actual results could vary materially from these estimates.



Estimated Useful Lives



The estimated useful lives of our long-lived assets are used to compute depreciation expense, future asset retirement obligations and are also used in
impairment testing. Estimated useful lives are based, among other things, on the assumption that we provide an appropriate level of capital expenditures while the assets are still in operation. Without these continued capital expenditures, the
useful lives of these assets could decrease significantly. Estimated lives could be impacted by such factors as future energy prices, environmental regulations, various legal factors and competition. If the useful lives of these assets were found to
be shorter than originally estimated, depreciation expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in carrying values of tangible and intangible assets may result.



Accounting for Contingencies, Guarantees and Indemnifications



We are involved in numerous lawsuits, claims, proceedings, joint venture
audits and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, Accounting for Contingencies, we record a loss contingency for these matters when it is probable that a liability has been incurred and
the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on the balance sheet. These reserves are based on estimates and judgments made by
management with respect to the likely outcome of these matters, including any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Our estimates and judgment could change based on new information, changes
in laws or regulations, changes in managements plans or intentions, the outcome of legal proceedings, settlements or other factors. If different estimates and judgments were applied with respect to these matters, it is likely that reserves
would be recorded for different amounts. Actual results could vary materially from theses reserves.



Liabilities are recorded when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement
of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best
estimate of our final pro-rata share of such liability. These assumptions involve the judgments and estimates of management and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes
recognized immediately in earnings.



We follow the guidance of
FIN No. 45 Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others for disclosure and accounting of various guarantees and indemnifications entered into during the
course of business. When a guarantee or indemnification subject of FIN No. 45 is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial
impact under certain circumstances, however management also considers the probability of such circumstances occurring when estimating the fair value. Actual results may materially differ from the estimated fair value of such guarantees and
indemnifications.



Under the provisions of SFAS No. 143,
Asset Retirement Obligations, we are required to record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount, when the liability is incurred. Significant judgment
is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flow change, the change may have a material impact on our
results of operations.



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##### Index to Financial Statements

Accounting for Income Taxes



We follow the guidance in SFAS No. 109, Accounting for Income Taxes, which requires that we use the asset and
liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.



As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in
which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of certain items, such as depreciation, for tax and accounting
purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.



We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more
likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether,
based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available
information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.



Management believes future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize
assets for which no reserve has been established. While we have considered these factors in assessing the need for a valuation allowance, there is no assurance that a valuation allowance would not need to be established in the future if information
about future years change. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.



Please see Note 13Income Taxes beginning on page F-40 for further discussion of our accounting for income taxes and
any change in our valuation allowance.



Valuation of Pension Assets and
Liabilities



Our pension and post-retirement benefit costs
are developed from actuarial valuations. Inherent in these valuations are key assumptions provided by us to our actuaries, including the discount rate and expected long-term rate of return on plan assets. Material changes in our pension and
post-retirement benefit costs may occur in the future due to changes in these assumptions, changes in the number of plan participants and changes in the level of benefits provided.



The discount rate is subject to change each year, consistent with changes in applicable high-quality, long-term corporate
bond indices. Long-term interest rates declined during 2004. Accordingly, at December 31, 2004, we used a discount rate of 5.75%, a decline of 25 basis points from the 6.0% rate used as of December 31, 2003. This decline in the discount rate had an
immaterial impact on the underfunded status of our pension plans.



The expected long-term rate of return on pension plan assets is selected by taking into account the expected duration of the projected benefit obligation for the plans, the asset mix of the plans and the fact that the plan assets are
actively managed to mitigate downside risk. Based on these factors, our expected long-term rate of return as of January 1, 2005 is 8.25%, compared with 8.75% during 2004. This change did not impact 2004 pension expense, but it will adversely impact
pension expense beginning in 2005. We expect 2005 pension expense to be approximately $1 million higher than 2004 pension expense, due to the decrease in the expected long-term rate of return, coupled with the decreased discount rate discussed above
and the passage of time.



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On December 31, 2004, our annual measurement date, the accumulated benefit obligation related to our
pension plans exceeded the fair value of the pension plan assets (such excess is referred to as an unfunded accumulated benefit obligation). This difference is attributed to (1) an increase in the accumulated benefit obligation that resulted from
the decrease in the discount rate and the expected long-term rate of return and (2) a decline in the fair value of the plan assets due to a sharp decrease in the equity markets through December 31, 2002, which was partially recovered during 2003 and
2004. As a result, in accordance with SFAS No. 87, Employers Accounting for Pensions, as of December 31, 2004, we have recognized a charge to accumulated other comprehensive loss of $13 million (net of taxes of $7 million), which
decreases stockholders equity. The charge to stockholders equity for the excess of additional pension liability over the unrecognized prior service cost represents a net loss not yet recognized as pension expense.



A relatively small difference between actual results and assumptions used by
management may have a material effect on our financial statements. Assumptions used by another party could be different than our assumptions. The following table summarizes the sensitivity of pension expense and our projected benefit obligation, or
PBO, to changes in the discount rate and the expected long-term rate of return on pension assets:



|                                                              |  |                               |       |   |                      |   |      |  
|------------------------------------------------------------- |  | ----------------------------- | ----- | - | -------------------- | - | ---- | -
|                                                              |  | Impact onPBO,December 31,2005 |       |   | Impacton 2005Expense |  
|                                                              |  | (in millions)                 |      
|Increase in Discount Rate50 basis points                     |  | $                             | (13.9 | ) |                      | $ | (1.2 | )
|Decrease in Discount Rate50 basis points                     |  |                               | 15.5  |   |                      |   | 1.3  |  
|Increase in Expected Long-term Rate of Return50 basis points |  |                               |      |   |                      |   | (0.5 | )
|Decrease in Expected Long-term Rate of Return50 basis points |  |                               |      |   |                      |   | 0.5  |  



We expect to make $28 million in cash
contribution related to our pension plans during 2005. In addition, it is likely that we will be required to continue to make contributions to the pension plan beyond 2005. Although it is difficult to estimate these potential future cash
requirements due to uncertain market conditions, we currently expect that the cash requirements would be approximately $19 million in 2006 and $26 million in 2007. Please see Note 17Employee Compensation, Savings and Pension Plans beginning on
page F-59 for further discussion of our pension related assets and liabilities.



RECENT ACCOUNTING PRONOUNCEMENTS



See Note 2Accounting PoliciesAccounting Principles Adopted beginning on page F-17 for a discussion of recently issued accounting pronouncements affecting us. Specifically, we adopted certain provisions of FIN No. 46R on January
1, 2004, and we adopted other portions of FIN No. 46R effective December 31, 2003. We adopted SFAS No. 150 and EITF Issue 03-11 effective July 1, 2003. We adopted FIN No. 45 and SFAS No. 143 effective January 1, 2003. We adopted the net presentation
provisions of EITF Issue 02-03 in the third quarter 2002 and we adopted the provision within EITF Issue 02-03 that rescinds EITF Issue 98-10 effective January 1, 2003.



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##### Index to Financial Statements

RISK-MANAGEMENT DISCLOSURES



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



|                                                                                 |  |                                              |      |  
|-------------------------------------------------------------------------------- |  | -------------------------------------------- | ---- | -
|                                                                                 |  | As of and for theYear EndedDecember 31, 2004 |     
|                                                                                 |  | (in millions)                                |     
|Balance Sheet Risk-Management Accounts                                           |  |                                              |      |  
|Fair value of portfolio at January 1, 2004                                       |  | $                                            | (137 | )
|Risk-management gains recognized through the income statement in the period, net |  |                                              | 6    |  
|Cash paid related to risk-management contracts settled in the period, net        |  |                                              | 85   |  
|Changes in fair value as a result of a change in valuation technique (1)         |  |                                              |     |  
|Non-cash adjustments and other (2)                                               |  |                                              | (87  | )
|                                                                                 |  |                                              |      |  
|Fair value of portfolio at December 31, 2004                                     |  | $                                            | (133 | )
|                                                                                 |  |                                              |      |  
|Income Statement Reconciliation                                                  |  |                                              |      |  
|Risk-management gains recognized through the income statement in the period, net |  | $                                            | 6    |  
|Physical business recognized through the income statement in the period, net (3) |  |                                              | (129 | )
|Non-cash adjustments and other                                                   |  |                                              | 13   |  
|                                                                                 |  |                                              |      |  
|Net recognized operating loss                                                    |  | $                                            | (110 | )
|                                                                                 |  |                                              |      |  
|Cash Flow Statement                                                              |  |                                              |      |  
|Cash paid related to risk-management contracts settled in the period, net        |  | $                                            | (85  | )
|Estimated cash paid related to physical business settled in the period, net (3)  |  |                                              | (129 | )
|Timing and other, net (4)                                                        |  |                                              | 54   |  
|                                                                                 |  |                                              |      |  
|Cash paid during the period                                                      |  | $                                            | (160 | )
|                                                                                 |  |                                              |      |  
|Risk-Management cash flow adjustment for the year ended December 31, 2004 (5)    |  | $                                            | (50  | )
|                                                                                 |  |                                              |      |  

---

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

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

|(3) | This amount includes capacity payments on our power tolling arrangements and the $115 million charge associated with our entry into a back-to-back power purchase
agreement offset by the $88 million gain recognized by our exit from four gas transportation contracts.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

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



The net risk management liability of $133 million is the aggregate of the
following line items on the 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 table depicts the mark-to-market value and cash flow components, based on contract terms, of our net risk-management assets and liabilities at December 31, 2004. As opportunities arise to monetize positions that we believe
will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below.



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Net Risk-Management Asset and Liability Disclosures



|                   |  |               |     |   |      |   |    |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |    |  
|------------------ |  | ------------- | --- | - | ---- | - | -- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- |  | - | --- | - |  | - | -- | -
|                   |  | Total         |     |   | 2005 |   |    | 2006 |  |   | 2007 |   |  | 2008 |     |   | 2009 |   |     | Thereafter | 
|                   |  | (in millions) |    
|Mark-to-Market (1) |  | $             | (96 | ) |      | $ | (7 | )    |  | $ | (8   | ) |  | $    | (48 | ) |      | $ | (21 | )          |  | $ | (10 | ) |  | $ | (2 | )
|Cash Flow (2)      |  |               | (99 | ) |      |   | (5 | )    |  |   | (7   | ) |  |      | (51 | ) |      |   | (23 | )          |  |   | (12 | ) |  |   | (1 | )

---

|(1) | Mark-to-market 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 December 31, 2004 of $133 million on the consolidated balance sheets includes the $96 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) | Cash Flow reflects 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 December 31, 2004, based on our valuation methodology.



Net Fair Value of Risk-Management Portfolio



|                           |  |               |     |   |      |   |    |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |    |  
|-------------------------- |  | ------------- | --- | - | ---- | - | -- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- |  | - | --- | - |  | - | -- | -
|                           |  | Total         |     |   | 2005 |   |    | 2006 |  |   | 2007 |   |  | 2008 |     |   | 2009 |   |     | Thereafter | 
|                           |  | (in millions) |    
|Market Quotations (1)      |  | $             | (62 | ) |      | $ | (7 | )    |  | $ | (8   | ) |  | $    | (35 | ) |      | $ | (11 | )          |  | $ | (3  | ) |  | $ | 2  |  
|Prices Based on Models (2) |  |               | (34 | ) |      |   |   |      |  |   |     |   |  |      | (13 | ) |      |   | (10 | )          |  |   | (7  | ) |  |   | (4 | )
|                           |  |               |     |   |      |   |    |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |    |  
|Total                      |  | $             | (96 | ) |      | $ | (7 | )    |  | $ | (8   | ) |  | $    | (48 | ) |      | $ | (21 | )          |  | $ | (10 | ) |  | $ | (2 | )
|                           |  |               |     |   |      |   |    |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |    |  

---

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

|(2) | See discussion of our use of long-term models in Critical Accounting Policies beginning on page 62.
|--- | -----------------------------------------------------------------------------------------------------



Derivative Contracts



The absolute notional contract amounts associated with our commodity risk-management, interest rate and foreign currency
exchange contracts are discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 70.



UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION



This Form 10-K 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 annual 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,



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expect and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:



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



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



| |  |  | our ability to continue execution of the cost-savings measures we have identified;
| | - |  | ----------------------------------------------------------------------------------



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



| |  |  | our ability to access the capital markets as and when needed;
| | - |  | -------------------------------------------------------------



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



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



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



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



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



| |  |  | the timing and extent of changes in weather and commodity prices, including the relationships between prices for power and natural gas or other power generating fuels, commonly
referred to as the spark spread, and the frac spread;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | our ability to fund the environmental and emission control projects mandated by the Baldwin consent decree following its approval by the Illinois federal district court;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions, and our ability to engage in
capital-raising transactions;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our financial condition, including our ability to satisfy our significant debt maturities and debt service obligations;
| | - |  | -----------------------------------------------------------------------------------------------------------------------



| |  |  | our ability to realize our significant deferred tax assets, including loss carryforwards;
| | - |  | -----------------------------------------------------------------------------------------



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



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



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



| |  |  | increased interest expense and restrictive covenants resulting from our non-investment grade credit rating;
| | - |  | -----------------------------------------------------------------------------------------------------------



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



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##### Index to Financial Statements

| |  |  | our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) tightly and generate earnings and cash flow
from our asset-based businesses in relation to our substantial debt and other obligations;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



| |  |  | the effects of our ongoing efforts to improve our internal control structure, particularly with respect to those matters discussed under Item 9AControls and Procedures, and to
achieve compliance with Section 404 of Sarbanes-Oxley within the prescribed period;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | general political conditions and developments in the United States and in foreign countries whose affairs affect our asset-based businesses including any extended period of war or
conflict.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition, there may be other
factors that could cause our actual results to be materially different from the results referenced in the forward-looking statements, some of which are included elsewhere in this Form 10-K. Many of these factors will be important in determining our
actual future results. Consequently, no forward-looking statement can be guaranteed. Our actual future results may vary materially from those expressed or implied in any forward-looking statements.



All forward-looking statements contained in this Form 10-K are qualified in
their entirety by this cautionary statement. Forward-looking statements speak only as of the date they are made, and we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this Form
10-K, except as otherwise required by applicable law.



|Item 7A. | Quantitative and Qualitative Disclosures About Market Risk
|-------- | ----------------------------------------------------------



We are exposed to commodity price variability related to our power generation and natural gas liquids businesses. In
addition, fuel requirements at our power generation, gas processing and fractionation facilities represent additional commodity price risks to us. In order to manage these commodity price risks, we routinely utilize various fixed-price forward
purchase and sales contracts, futures and option contracts traded on the New York Mercantile Exchange and swaps and options traded in the over-the-counter financial markets to:



| |  |  | manage and hedge our fixed-price purchase and sales commitments;
| | - |  | ----------------------------------------------------------------



| |  |  | reduce our exposure to the volatility of cash market prices; and
| | - |  | ----------------------------------------------------------------



| |  |  | hedge our fuel requirements for our generating facilities and natural gas processing plants.
| | - |  | --------------------------------------------------------------------------------------------



The potential for changes in the market value of our commodity, interest rate and currency portfolios is referred to as
market risk. A description of each market risk category is set forth below:



| |  |  | Commodity price risks result from exposures to changes in spot prices, forward prices and volatilities in commodities, such as electricity, natural gas, natural gas liquids and
other similar products;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Index to Financial Statements

| |  |  | Interest rate risks primarily result from exposures to changes in the level, slope and curvature of the yield curve and the volatility of interest rates; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Currency rate risks result from exposures to changes in spot prices, forward prices and volatilities in currency rates.
| | - |  | -----------------------------------------------------------------------------------------------------------------------



In the past, we have attempted to manage these market risks through
diversification, controlling position sizes and executing hedging strategies. The ability to manage an exposure may, however, be limited by adverse changes in market liquidity, our credit capacity or other factors.



VaR.In addition to applying business judgment, senior
management uses a number of quantitative tools to monitor our exposure to market risk. These tools include stress and scenario analyses performed periodically that measure the potential effects of various market events.



The modeling of the risk characteristics of our mark-to-market portfolio
involves a number of assumptions and approximations. We estimate VaR using a JP Morgan RiskMetricsapproach assuming a one-day holding period. Inputs for the VaR calculation are prices, positions, instrument valuations and the variance-covariance matrix. While management believes that these assumptions and approximations are
reasonable, there is no uniform industry methodology for estimating VaR, and different assumptions and/or approximations could produce materially different VaR estimates.



We use historical data to estimate our VaR and, to better reflect current asset and liability volatilities, this historical
data is weighted to give greater importance to more recent observations. Given our reliance on historical data, VaR is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market
conditions. An inherent limitation of VaR is that past changes in market risk factors, even when weighted toward more recent observations, may not produce accurate predictions of future market risk. VaR should be evaluated in light of this and the
methodologys other limitations.



VaR represents the
potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon within a specified confidence level. For the VaR numbers reported below, a one-day time horizon and a 95% confidence level were used.
This means that there is a one in 20 statistical chance that the daily portfolio value will fall below the expected maximum potential reduction in portfolio value at least as large as the reported VaR. Thus, a change in portfolio value greater than
the expected change in portfolio value on a single trading day would be anticipated to occur, on average, about once a month. Gains or losses on a single day can exceed reported VaR by significant amounts. Gains or losses can also accumulate over a
longer time horizon such as a number of consecutive trading days.



In addition, we have provided our VaR using a one-day time horizon and a 99% confidence level. The purpose of this disclosure is to provide an indication of earnings volatility using a higher confidence level. Under this presentation, there
is a one in 100 statistical chance that the daily portfolio value will fall below the expected maximum potential reduction in portfolio value at least as large as the reported VaR. We have also disclosed a two-year comparison of daily VaR in order
to provide context for the one-day amounts.



The following
table sets forth the aggregate daily VaR of the mark-to-market portion of our risk-management portfolio primarily associated with the GEN and CRM segments.



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##### Index to Financial Statements

Daily and Average VaR for Risk-Management Portfolio



|                                                             |  |                  |   |                  |   |  
|------------------------------------------------------------ |  | ---------------- | - | ---------------- | - | -
|                                                             |  | December 31,2004 |   | December 31,2003
|                                                             |  | (in millions)   
|One Day VaR95% Confidence Level                             |  | $                | 5 |                  | $ | 4
|One Day VaR99% Confidence Level                             |  | $                | 7 |                  | $ | 6
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $                | 4 |                  | $ | 6



Credit
Risk. Credit risk represents the loss that we would incur if a counterparty fails to perform pursuant to the terms of its contractual obligations. To reduce our credit exposure, we execute agreements that permit us to offset receivables,
payables and mark-to-market exposure. We attempt to further reduce credit risk with certain counterparties by obtaining third-party guarantees or collateral as well as the right of termination in the event of default.



Our Credit Department, based on guidelines approved by the Board of
Directors, establishes our counterparty credit limits. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. Our credit risk system provides current credit exposure to counterparties on a daily
basis.



The following table represents our credit exposure at
December 31, 2004 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.



Credit Exposure Summary



|                                |  |                         |     |                             |   |       |  |   |    
|------------------------------- |  | ----------------------- | --- | --------------------------- | - | ----- |  | - | ---
|                                |  | InvestmentGrade Quality |     | Non-InvestmentGrade Quality |   | Total
|                                |  | (in millions)          
|Type of Business:               |  |                         |     |                             |   |       |  |   |    
|Financial Institutions          |  | $                       | 146 |                             | $ |      |  | $ | 146
|Commercial/Industrial/End Users |  |                         | 63  |                             |   | 25    |  |   | 88 
|Utility and Power Generators    |  |                         | 21  |                             |   |      |  |   | 21 
|Oil and Gas Producers           |  |                         | 4   |                             |   |      |  |   | 4  
|                                |  |                         |     |                             |   |       |  |   |    
|Total                           |  | $                       | 234 |                             | $ | 25    |  | $ | 259
|                                |  |                         |     |                             |   |       |  |   |    



Of the $25 million in
credit exposure to non-investment grade counterparties, approximately 96% ($24 million) is collateralized or subject to other credit exposure protection.



Interest Rate Risk. Interest rate risk primarily results from variable rate debt obligations. Although changing interest rates impact the
discounted value of future cash flows, and therefore the value of our risk management portfolios, the relative near-term nature and size of our risk management portfolios minimizes the impact. Management continues to monitor our exposure to
fluctuations in interest rates and may execute swaps or other financial instruments to change our risk profile for this exposure.



As of December 31, 2004, our fixed rate debt instruments as a percentage of total debt instruments was equal to 69%. Based on sensitivity analysis of the
variable rate financial obligations in our debt portfolio as of December 31, 2004, 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 December 31,
2005 would either decrease or increase income before taxes by approximately $15 million. Hedging instruments that impact such interest rate exposure are included in the sensitivity analysis. Over time, we may seek to reduce the percentage of fixed
rate financial obligations in our debt portfolio through the use of swaps or other financial instruments.



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Foreign Currency Exchange Rate Risk.Foreign currency risk arises from our investments in
affiliates and subsidiaries owned and operated in foreign countries. Such risk is also a result of risk management transactions with customers in countries outside the United States. Management continually monitors our exposure to fluctuations in
foreign currency exchange rates. When possible, contracts are denominated in or indexed to the U.S. dollar.



At December 31, 2004, our primary foreign currency exchange rate exposures were the Canadian Dollar and European Euro. Additionally, as further discussed
in Liquidity and Capital ResourcesInternal Liquidity SourcesCurrent Liquidity beginning on page 39, at December 31, 2004, approximately $47 million cash denominated in the U.K. Pound, the Euro and the Canadian Dollar remains
in the U.K. and Canada.



Derivative Contracts.
The absolute notional financial contract amounts associated with our commodity risk-management and interest rate contracts were as follows at December 31, 2004 and December 31, 2003, respectively:



Absolute Notional Contract Amounts



|                                                                     |  |                  |        |                  |   |      
|-------------------------------------------------------------------- |  | ---------------- | ------ | ---------------- | - | -----
|                                                                     |  | December 31,2004 |        | December 31,2003
|Natural Gas (Trillion Cubic Feet)                                    |  |                  | 1.084  |                  |   | 2.364
|Electricity (Million Megawatt Hours)                                 |  |                  | 11.652 |                  |   | 8.713
|Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)   |  | $                | 525    |                  | $ | 25   
|Fixed Interest Rate Received on Swaps (%)                            |  |                  | 4.331  |                  |   | 5.706
|Cash Flow Hedge Interest Rate Swaps (In Millions of U.S. Dollars)    |  | $                |       |                  | $ | 405  
|Fixed Interest Rate Paid on Swaps (%)                                |  |                  |       |                  |   | 3.448
|Interest Rate Risk-Management Contract (In Millions of U.S. Dollars) |  | $                | 25     |                  | $ | 306  
|Fixed Interest Rate Paid (%)                                         |  |                  | 5.998  |                  |   | 5.570



|Item 8. | Financial Statements and Supplementary Data
|------- | -------------------------------------------



Our financial statements and financial statement schedules are set forth at pages F-1 through F-92 inclusive, found at the
end of this annual report, and are incorporated herein by reference.



|Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
|------- | ------------------------------------------------------------------------------------



Not applicable.



|Item 9A. | 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 enterprises SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work
completed relating to our participation in Dynegys efforts to achieve compliance with Section 404 of the Sarbanes-Oxley Act of 2002, or SOX 404, which is further described below. Finally, this evaluation considered the material weakness in tax
accounting and tax reconciliation processes, procedures and controls disclosed by Dynegy in Item 9A of its 2004 Form 10-K beginning on page 85, and the resulting ineffectiveness of Dynegys disclosure controls and procedures and internal
control over financial reporting.



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Based on this evaluation, our CEO and CFO concluded that, as of December 31, 2004, as a result of (i)
Dynegys material weakness and ineffective disclosure controls and procedures referenced above and (ii) our material weakness 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. Due to the material weakness discussed below, in preparing our financial statements at and for the year ended December 31, 2004, we
performed additional procedures relating to the tax provision designed to ensure that such financial statements were fairly presented in all material respects in accordance with generally accepted accounting principles.



Changes in Internal Controls.Other than as noted below, there were no
changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of our internal controls performed during the last fiscal quarter that have
materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.



We are a wholly owned subsidiary of Dynegy Inc. and the primary holding company for Dynegys GEN and NGL segments. We are not subject to the
disclosure requirements promulgated under SOX 404 until we file our Annual Report on Form 10-K for the year ended December 31, 2006. Because we comprise a significant part of Dynegy as a consolidated enterprise, however, our internal controls over
financial reporting have been reviewed in connection Dynegys efforts to achieve compliance with SOX 404.



Our management, and the management of Dynegy, is responsible for establishing and maintaining adequate internal control over financial reporting. Our
internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.



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. As of December 31, 2004, we did not maintain effective control over the calculation 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 and review of the quarterly and annual tax provisions were not adequate to ensure that the deferred tax provision and
classification of deferred tax balances were prepared in accordance with generally accepted accounting principles. This control deficiency resulted in year-end audit adjustments to correct the income tax benefit recognized in 2004 and the related
deferred income tax asset account. Also, errors were discovered in our previously completed tax basis balance sheet review which misstated the deferred tax liability account at December 31, 2003 and the corresponding tax benefit for 2003, 2002 and
periods prior to 2002. As a result, we restated our 2003 and 2002 annual financial statements and 2004 and 2003 interim financial statements in this 2004 Annual Report on Form 10-K. Further, this control deficiency could have resulted in a
misstatement of the tax provision and deferred tax balances resulting in a material misstatement to the annual or interim consolidated financial statements that may not have been prevented or detected. Therefore, we have concluded that this control
deficiency constitutes a material weakness.



Prior to the
fourth quarter 2004, we identified deficiencies in our tax accounting and tax reconciliation processes, procedures and controls. Although we had processes, procedures and controls in place relating to the preparation and review of the quarterly and
annual tax provisions, we subsequently determined that such processes, procedures and controls were not adequate to ensure that the deferred tax provision and classification of deferred tax balances were prepared in accordance with generally
accepted accounting principles. As a result, we restated our 2003 and 2002 annual financial statements and 2004 and 2003 interim financial statements in this 2004 Annual Report on Form 10-K. We have taken the following steps to improve our internal
controls around our tax accounting and tax reconciliation processes, procedures and controls:



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



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



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##### Index to Financial Statements

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



We believe we have taken steps
necessary to remediate this material weakness relating to taxes, although certain of the corrective processes, procedures and controls were not in place as of December 31, 2004. Additionally, other processes, procedures and controls were not in
place for an adequate period of time to conclude that they were operating effectively as of December 31, 2004. Accordingly, we will continue to monitor the effectiveness of these processes, procedures and controls and will make any changes
management determines appropriate.



In addition, during the
course of completing the work relating to the consolidated enterprises compliance with SOX 404, deficiencies in our internal control over financial reporting were identified, including matters relating to system access and system
implementation controls, segregation of duties and documentation of controls and procedures and their effective operation and monitoring. While we do not consider these deficiencies material weaknesses, we believe they should be remediated. Among
other things, we have taken, and are taking, the following actions:



| |  |  | Improved controls related to logging and system access; and
| | - |  | -----------------------------------------------------------



| |  |  | Improved controls related to balance sheet classifications.
| | - |  | -----------------------------------------------------------



|Item 9B. | Other Information
|-------- | -----------------



Baldwin Consent Decree.Since November 1999, DMG has been the subject of an NOV from the EPA and a complaint filed by the EPA and the DOJ in
federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations related to certain maintenance, repair and replacement activities at our Baldwin generating station. We have reached agreement with the EPA,
the DOJ, the State of Illinois and the environmental group intervenors on terms to settle the litigation. A consent decree was signed by all parties and lodged with the U.S. District Court for the Southern District of Illinois on March 7, 2005, and
is subject to final approval of the Court following public comment. The consent decree requires us to (i) pay a $9 million civil penalty; (ii) fund several environmental projects in the additional aggregate amount of $15 million; and (iii) invest
$321 million through 2010, and $224 million from 2011 through 2012, respectively, in emission control projects at our Baldwin, Vermilion and Havana plants. Please read Note 14Commitments and ContingenciesSummary of Material Legal
ProceedingsBaldwin Station Litigation beginning on page F-45 for further discussion of this lawsuit and consent decree.



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PART III



|Item 10. | Directors and Executive Officers of the Registrant
|-------- | --------------------------------------------------



Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.



|Item 11. | Executive Compensation
|-------- | ----------------------



Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.



|Item 12. | Security Ownership of Certain Beneficial Owners and Management
|-------- | --------------------------------------------------------------



Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.



|Item 13. | Certain Relationships and Related Transactions
|-------- | ----------------------------------------------



Omitted pursuant to General Instruction (I)(2)(c) of Form 10-K.



|Item 14. | Principal Accountant Fees and Services
|-------- | --------------------------------------



We are an indirect, wholly owned subsidiary of Dynegy and do not have a separate audit committee. Information regarding principal accountant fees and
services for Dynegy and its consolidated subsidiaries, including us, will be contained in its upcoming proxy statement under the heading Independent AuditorsPrincipal Accounting Fees and Services.



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PART IV



|Item 15. | Exhibits, Financial Statement Schedules
|-------- | ---------------------------------------



|(a) | The following documents, which we have filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, are by this reference incorporated in and made a part of this
annual report:
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 1. | Financial StatementsOur consolidated financial statements are incorporated under Item 8. of this annual report.
| | -- | ----------------------------------------------------------------------------------------------------------------



| | 2. | Financial Statement SchedulesFinancial Statement Schedules are incorporated under Item 8. of this annual report.
| | -- | -----------------------------------------------------------------------------------------------------------------



| | 3. | ExhibitsThe following instruments and documents are included as exhibits to this annual report. All management contracts or compensation plans or arrangements set forth in
such list are marked with a .
| | -- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                       
|------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                           
|              | 
|3.1           |  | Restated Certificate of Incorporation of Dynegy Holdings Inc. (incorporated by reference to Exhibit 3.1 to the Annual Report on Form
10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Holdings Inc., File No. 0-29311).                                                                                                                                                                                                    
|              | 
|3.2           |  | Amended and Restated Bylaws of Dynegy Holdings Inc. (incorporated by reference to Exhibit 3.2 to the Annual Report on Form 10-K for
the Fiscal Year Ended December 31, 1999 of Dynegy Holdings Inc., File No. 0-29311).                                                                                                                                                                                                              
|              | 
|4.1           |  | Statement of Resolution Establishing Series of Series C Convertible Preferred Stock of Dynegy Inc. (incorporated by reference to
Exhibit 4.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                                                    
|              | 
|4.2           |  | Indenture, dated as of December 11, 1995, by and among NGC Corporation, the Subsidiary Guarantors named therein and the First
National Bank of Chicago, as Trustee (incorporated by reference to exhibits to the Registration Statement on Form S-3 of NGC Corporation, Registration No. 33-97368).                                                                                                                                  
|              | 
|4.3           |  | First Supplemental Indenture, dated as of August 31, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein and
The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996
of NGC Corporation, File No. 1-11156).  
|              | 
|4.4           |  | Second Supplemental Indenture, dated as of October 11, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein
and The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30,
1996 of NGC Corporation, File No. 1-11156).
|              | 
|4.5           |  | Subordinated Debenture Indenture between NGC Corporation and The First National Bank of Chicago, as Debenture Trustee, dated as of
May 28, 1997 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).                                                                                                                   
|              | 
|4.6           |  | Amended and Restated Declaration of Trust among NGC Corporation, Wilmington Trust Company, as Property Trustee and Delaware Trustee,
and the Administrative Trustees named therein, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No.
1-11156).                                                      



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|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                         
|------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                                                             
|              | 
|4.7           |  | Series A Capital Securities Guarantee Agreement executed by NGC Corporation and The First National Bank of Chicago, as Guarantee
Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).                                                                                  
|              | 
|4.8           |  | Common Securities Guarantee Agreement of NGC Corporation dated as of May 28, 1997 (incorporated by reference to Exhibit 4.10 to the
Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).                                                                                                                                                                  
|              | 
|4.9           |  | Registration Rights Agreement, dated as of May 28, 1997, among NGC Corporation, NGC Corporation Capital Trust I, Lehman Brothers,
Salomon Brothers Inc. and Smith Barney Inc. (incorporated by reference to Exhibit 4.11 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).                                                                      
|              | 
|4.10          |  | Fourth Supplemental Indenture among NGC Corporation, Destec Energy, Inc. and The First National Bank of Chicago, as Trustee, dated as
of June 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.12 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1997 of NGC Corporation, File No.
1-11156).                
|              | 
|4.11          |  | Fifth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago,
as Trustee, dated as of September 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC
Corporation, File No. 1-11156). 
|              | 
|4.12          |  | Sixth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago,
as Trustee, dated as of January 5, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC
Corporation, File No. 1-11156).    
|              | 
|4.13          |  | Seventh Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago,
as Trustee, dated as of February 20, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.20 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC
Corporation, File No. 1-11156).
|              | 
|4.14          |  | Indenture, dated as of September 26, 1996, restated as of March 23, 1998, and amended and restated as of March 14, 2001, between
Dynegy Holdings Inc. and Bank One Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 of Dynegy Holdings Inc., File No.
0-29311).                                
|              | 
|4.15          |  | Exchange and Registration Rights Agreement (Preferred Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc.
(incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                          
|              | 
|4.16          |  | Amended and Restated Registration Rights Agreement (Common Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc.
(incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                     



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|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|              | 
|4.17          |  | Amended and Restated Shareholder Agreement dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by
reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                                                                        
|              | 
|4.18          |  | Indenture dated as of August 11, 2003 among Dynegy Holdings Inc., the guarantors named therein, Wilmington Trust Company, as trustee,
and Wells Fargo Bank Minnesota, N.A., as collateral trustee, including the form of promissory note for each series of notes issuable pursuant to the Indenture (incorporated by reference to Exhibit 4.8 to the Quarterly Report on Form 10-Q for the
Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).
|              | 
|4.19          |  | Indenture dated August 11, 2003 between Dynegy Inc., Dynegy Holdings Inc. and Wilmington Trust Company, as trustee, including the
form of debenture issuable pursuant to the Indenture (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                              
|              | 
|4.20          |  | Registration Rights Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein
(incorporated by reference to Exhibit 4.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                                               
|              | 
|4.21          |  | First Supplemental Indenture dated July 25, 2003 to that certain Indenture, dated as of September 26, 1996, between Dynegy Holdings
Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).                                                                                                                                           
|              | 
|4.22          |  | Eighth Supplemental Indenture dated July 25, 2003 that certain Indenture, dated as of December 11, 1995, between Dynegy Holdings Inc.
and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).                                                                                                                                              
|              | 
|4.23          |  | Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P.
and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.22 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).                                                                                                                   
|              | 
|4.24          |  | First Supplemental Indenture dated as of January 1, 1993 to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence
Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.23 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy
Inc., File No. 1-15659).                                                   
|              | 
|4.25          |  | Second Supplemental Indenture dated as of October 23, 2001 to the Trust Indenture dated as of January 1, 1993, among
Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.23 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy
Inc., File No. 1-15659).                                                              
|              | 
|              |  | There have not been filed or incorporated as exhibits to this annual report, other debt instruments defining the
rights of holders of our long-term debt, none of which relates to authorized indebtedness that exceeds 10% of our consolidated assets. We hereby agree to furnish a copy of any such instrument not previously filed to the SEC upon
request.                                                                                                      
|              | 
|10.1          |  | Dynegy Inc. Amended and Restated 1991 Stock Option Plan (incorporated by reference to Exhibit 10.3 to the Annual Report on Form 10-K
for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156).                                                                                                                                                                                                                                              



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|              |  |                                                                                                                                                                                                                                                               
|------------- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                   
|              | 
|10.2          |  | Dynegy Inc. 1998 U.K. Stock Option Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the Fiscal
Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156).                                                        
|              | 
|10.3          |  | Dynegy Inc. Amended and Restated Employee Equity Option Plan (incorporated by reference to Exhibit 10.5 to the Annual Report on Form
10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156).                                   
|              | 
|10.4          |  | Dynegy Inc. 1999 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the Fiscal
Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156).                                                      
|              | 
|10.5          |  | Dynegy Inc. 2000 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K for the Fiscal
Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156).                                                      
|              | 
|10.6          |  | Dynegy Inc. 2001 Non-Executive Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form
S-8 of Dynegy Inc., Registration No. 333-76080).                                                                       
|              | 
|10.7          |  | Dynegy Inc. 2002 Long Term Incentive Plan (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A
of Dynegy Inc., File No. 1-15659, filed with the SEC on April 9, 2002).                                               
|              | 
|10.8          |  | Extant, Inc. Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy
Inc., Registration No. 333-47422).                                                                                    
|              | 
|10.9          |  | Employment Agreement, effective October 23, 2002, between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit
10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2002 of Dynegy Inc., File No. 1-15659).  
|              | 
|10.10         |  | Employment Agreement, effective March 11, 2003, between Carol F. Graebner and Dynegy Inc. (incorporated by reference to Exhibit 10.15
to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).     
|              | 
|10.11         |  | Contract for Consulting Services dated March 19, 2004 between Dynegy Inc. and Daniel L. Dienstbier (incorporated by reference to
Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2004 of Dynegy Inc., File No. 1-15659). 
|              | 
|10.12         |  | Dynegy Inc. Deferred Compensation Plan for Certain Directors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on
Form 10-Q for the Quarterly Period Ended March 31, 2000 of Dynegy Inc., File No. 1-15659).                              
|              | 
|10.13         |  | Dynegy Inc. 401(k) Savings Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.1 to the
Registration Statement on Form S-8 of Dynegy Inc., Registration No. 383-76570).                                       
|              | 
|10.14         |  | First Amendment to the Dynegy Inc. 401(k) Savings Plan, effective February 11, 2002 (incorporated by reference to Exhibit 10.19 to
the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).           
|              | 
|10.15         |  | Second Amendment to the Dynegy Inc. 401(k) Savings Plan, effective January 1, 2002 (incorporated by reference to Exhibit 10.20 to the
Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).            
|              | 
|10.16         |  | Third Amendment to the Dynegy Inc. 401(k) Savings Plan, effective October 1, 2003 (incorporated by reference to Exhibit 10.21 to the
Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).             



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|              |  |                                                                                                                                                                                                                                                                                                                                                           
|------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                               
|              | 
|10.17         |  | Amendment to the Dynegy Inc. 401(k) Savings Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.18 to the Annual
Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                               
|              | 
|10.18         |  | Dynegy Inc. 401(k) Savings Plan Trust Agreement (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-8
of Dynegy Inc., Registration No. 333-76570).                                                                                                                                                                      
|              | 
|10.19         |  | Dynegy Inc. Deferred Compensation Plan (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-8 of Dynegy
Inc., Registration No. 333-76080).                                                                                                                                                                                
|              | 
|10.20         |  | Dynegy Inc. Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 4.7 to the Registration Statement on
Form S-8 of Dynegy Inc., Registration No. 333-76080).                                                                                                                                                                
|              | 
|10.21         |  | Dynegy Inc. Short-Term Executive Stock Purchase Loan Program (incorporated by reference to Exhibit 10.19 to the Annual Report on Form
10-K for the Year Ended December 31, 2001 of Dynegy Inc., File No. 1-15659).                                                                                                                                     
|              | 
|10.22         |  | Dynegy Inc. Deferred Compensation Plan for Certain Directors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                           
|              | 
|10.23         |  | Dynegy Inc. Executive Severance Pay Plan, as amended effective September 30, 2003 (incorporated by reference to Exhibit 10.1 to the
Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                 
|              | 
|10.24         |  | Second Supplement to the Dynegy Inc. Executive Severance Pay Plan (incorporated by reference to Exhibit 10.28 to the Annual Report on
Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                         
|              | 
|10.25         |  | First Amendment to The Dynegy Inc. Executive Severance Pay Plan effective May 19, 2004 (incorporated by reference to Exhibit 10.25 to
the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).                                                                                                    
|              | 
|10.26         |  | Dynegy Inc. Mid-Term Incentive Performance Award Program (incorporated by reference to Exhibit 10.29 to the Annual Report on Form
10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                  
|              | 
|10.27         |  | Dynegy Northeast Generation, Inc. Savings Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on
Form S-8 of Dynegy Inc., Registration No. 333-111985).                                                                                                                                                            
|              | 
|10.28         |  | Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, effective January 1, 2004 (incorporated by reference to
Exhibit 10.31 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).                                                                                      
|              | 
|10.29         |  | Dynegy Inc. Severance Pay Plan, as amended effective September 30, 2003 (incorporated by reference to Exhibit 10.2 to the Quarterly
Report on Form 10-Q for the Quarterly Period Ended September 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                           
|              | 
|10.30         |  | Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower Realty Company,
Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to Exhibit 10.69 to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).                    
|              | 
|10.31         |  |  First Amendment to Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower
Realty Company, Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to Exhibit 10.70 to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).



81



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##### Index to Financial Statements

|              |  |                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|              | 
|*10.32        |  | Master Natural Gas Liquids Purchase Agreement, dated as of September 1, 1996, between Warren Petroleum Company, Limited Partnership
and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).                                                                                                                                
|              | 
|10.33         |  | Amended and Restated Credit Agreement dated as of May 28, 2004 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 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 1, 2004, File No.
1-15659).                                                                                     
|              | 
|10.34         |  | Shared Security Agreement, dated April 1, 2003, among Dynegy Holdings, Inc., various grantors named therein, Wilmington Trust
Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.32 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).                                                                                                   
|              | 
|10.35         |  | Non-Shared Security Agreement, dated April 1, 2003, among Dynegy Inc., various grantors named therein and Bank One, N.A. as
collateral agent (incorporated by reference to Exhibit 10.33 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).                                                                                                                                                                  
|              | 
|10.36         |  | Collateral Trust and Intercreditor Agreement, dated as of April 1, 2003, among Dynegy Holdings Inc., various grantors named therein,
Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No.
1-15659).                                                                           
|              | 
|10.37         |  | Amendment No. 1 to Collateral Trust and Intercreditor Agreement, dated as of May 28, 2004, among Dynegy Holdings Inc., various
grantors named therein, JPMorgan Chase Bank, as collateral agent, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the
Quarterly Period Ended June 30, 2004 of Dynegy Inc., File No. 1-15659).     
|              | 
|10.38         |  | Series B Preferred Stock Exchange Agreement dated as of July 28, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by
reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                                                                   
|              | 
|10.39         |  | Indemnity Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and Chevron U.S.A. Inc. (incorporated by reference
to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                                                                           
|              | 
|10.40         |  | Intercreditor Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein, Wilmington Trust Company,
as corporate trustee, John M. Beeson, Jr., as individual trustee, Bank One, NA, as collateral agent, and Wells Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the
Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).
|              | 
|10.41         |  | Second Lien Shared Security Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein and Wells
Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                  
|              | 
|10.42         |  | Second Lien Non-Shared Security Agreement dated August 11, 2003 among Dynegy Inc., various grantors named therein and Wells Fargo
Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                       



82



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##### Index to Financial Statements

|              |  |                                                                                                                                                                                                                                                                                                                                                                               
|------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                                                                                   
|              | 
|10.43         |  | Purchase Agreement dated August 1, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein
(incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                     
|              | 
|10.44         |  | Purchase Agreement dated August 1, 2003 among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named
therein (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                   
|              | 
|10.45         |  | Purchase Agreement dated September 30, 2003 among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named
therein (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 15, 2003, File No. 1-15659).                                                                                      
|              | 
|10.46         |  | Purchase Agreement dated February 2, 2004 among Dynegy Inc., Illinova Corporation, Illinova Generating Company and Ameren Corporation
(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 4, 2004, File No. 1-15659).                                                                                               
|              | 
|10.47         |  | Power Purchase Agreement dated September 30, 2004 between Illinois Power Company and Dynegy Power Marketing, Inc. (incorporated by
reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2004 of Dynegy Inc., File No. 1-15659).                                                                                       
|              | 
|10.48         |  | Escrow Agreement dated as of September 30, 2004 among Illinova Corporation, Ameren Corporation and JPMorgan Chase Bank, as escrow
agent (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2004 of Dynegy Inc., File No. 1-15659).                                                                 
|              | 
|10.49         |  | Stock Purchase Agreement dated as of November 1, 2004 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power
Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.48 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).                                       
|              | 
|10.50         |  | Amendment to Stock Purchase Agreement (Special Payroll Payment) dated as of January 28, 2005 among Dynegy New York Holdings Inc.,
Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No.
1-15659).
|              | 
|10.51         |  | Amendment to Stock Purchase Agreement dated as of January 31, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New
England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).                          
|              | 
|10.52         |  | Amendment to Stock Purchase Agreement (Luz Sale) dated as of January 31, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc.,
Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).               
|              | 
|10.53         |  | Tenth Amendment to Amended and Restated Base Gas Sales Agreement, dated as of June 29, 2001, by and between Enron North America Corp.
and Sithe/Independence Power Partners, L.P. (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).                               



83



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##### Index to Financial Statements

|              |  |                                                                                                                                                                                                                                                                                                                      
|------------- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                          
|              | 
|10.54         |  | Power Purchase Agreement dated as of November 17, 2004, between Dynegy Power Marketing, Inc. and Constellation Energy Commodities
Group, Inc. (incorporated by reference to Exhibit 10.53 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).          
|              | 
|10.55         |  | Assignment and Assumption Agreement dated as of November 17, 2004 between Dynegy Power Marketing, Inc. and Constellation Energy
Commodities Group, Inc. (incorporated by reference to Exhibit 10.54 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2004 of Dynegy Inc., File No. 1-15659).
|              | 
|14.1          |  | Dynegy Inc. Code of Ethics for Senior Financial Professionals (incorporated by reference to Exhibit 14.1 to the Annual Report on Form
10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).                                                                                           
|              | 
|**23.1        |  | Consent of PricewaterhouseCoopers LLP.                                                                                                                                                                                                                                                                              
|              | 
|**23.2        |  | Consent of PricewaterhouseCoopers LLP (West Coast Power LLC).                                                                                                                                                                                                                                                       
|              | 
|**31.1        |  | Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.                                                                                                                                                               
|              | 
|**31.2        |  | Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.                                                                                                                                                               
|              | 
|32.1         |  | Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.                                                                                                                                                         
|              | 
|32.2         |  | Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.                                                                                                                                                         



|* | Exhibit omits certain information that we have filed separately with the SEC pursuant to a confidential treatment request pursuant to Rule 406 promulgated under the Securities Act
of 1933, as amended.
|- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|** | 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.
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



84



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##### Index to Financial Statements

SIGNATURES



Pursuant to the
requirements of Section 13 or 15(d) 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: March 23, 2005 |  |  |  | By:                  |  | /S/    BRUCE A.
WILLIAMSON                               
|                     |  |  |  |                      |  | Bruce A. Williamson President and Chief Executive Officer



Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant in the capacities and on the dates indicated.



|                                              |  |                                                                                              |  |               
|--------------------------------------------- |  | -------------------------------------------------------------------------------------------- |  | --------------
|                                              |  |                                                                                             
|/S/    BRUCE A.
WILLIAMSONBruce A.
Williamson |  | President, Chief Executive Officer and Director (Principal Executive Officer)                |  | March 23, 2005
|                                              |  |                                                                                             
|/S/    NICK J.
CARUSONick J.
Caruso           |  | Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer) |  | March 23, 2005
|                                              |  |                                                                                             
|/S/    TERRY A.
HARTTerry A. Hart             |  | Senior Vice President and Controller (Principal Accounting Officer)                          |  | March 23, 2005
|                                              |  |                                                                                             
|/S/    CAROL F.
GRAEBNERCarol F.
Graebner     |  | Director                                                                                     |  | March 23, 2005



85



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                                                      |  |     
|------------------------------------------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                                                      |  | Page
|Consolidated Financial Statements                                                                                                     |  |     
|Report of Independent Registered Public Accounting Firm                                                                               |  | F-2 
|Consolidated Balance Sheets as of December 31, 2004 and 2003 (Restated)                                                               |  | F-3 
|Consolidated Statements of Operations for the years ended December 31, 2004, 2003 (Restated) and 2002 (Restated)                      |  | F-4 
|Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 (Restated) and 2002 (Restated)                      |  | F-5 
|Consolidated Statements of Changes in Stockholders Equity for the years ended December 31, 2004, 2003 (Restated) and 2002 (Restated) |  | F-6 
|Consolidated Statements of Comprehensive Loss for the years ended December 31, 2004, 2003 (Restated) and 2002 (Restated)              |  | F-7 
|Notes to Consolidated Financial Statements (Restated)                                                                                 |  | F-8 
|                                                                                                                                      | 
|Financial Statement Schedule                                                                                                          |  |     
|Schedule II  Valuation and Qualifying Accounts                                                                                       |  | F-73
|                                                                                                                                      | 
|West Coast Power LLC Consolidated Financial Statements*                                                                               |  | F-75

---

|* | West Coast Powers consolidated financial statements are included herein pursuant to Rule 3-09 of Regulation S-X.
|- | -----------------------------------------------------------------------------------------------------------------



F-1



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##### Table of Contents

##### Index to Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Board of Directors and Stockholder of Dynegy Holdings Inc.:



In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material
respects, the financial position of Dynegy Holdings Inc. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity
with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Companys management. Our responsibility is to express an opinion on
these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for
our opinion.



As discussed in Note 14, the Company is the
subject of substantial litigation. The Companys ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount of the resolution of such litigation. The consolidated financial statements
do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, Accounting for Contingencies, that might result from the ultimate resolution of such matters.



As discussed in the Explanatory Note beginning on page F-8, the 2003 and 2002
consolidated financial statements have been restated to reflect adjustments to the deferred income tax accounts.



As discussed in Note 2, the Company adopted certain provisions of Financial Accounting Standards Board Interpretation No. 46, Consolidation of
Variable Interest Entitiesan interpretation of ARB 51 (revised December 2003), as of January 1, 2004 and other portions effective December 31, 2003. As discussed in Note 2, the Company adopted the provisions of Statement of Financial
Accounting Standards No. 143, Accounting for Asset Retirement Obligations, as of January 1, 2003. As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting Standards No. 150, Accounting for
Certain Financial Instruments with Characteristics of both Liabilities and Equity, as of July 1, 2003. As discussed in Note 2, the Company adopted the net presentation provisions of Emerging Issues Task Force Issue No. 02-3, Accounting
for Contracts Involved in Energy Trading and Risk Management Activities as of January 1, 2002 and the provision related to the rescission of Emerging Issues Task Force Issue No. 98-10, Accounting for Contracts Involved in Energy Trading
and Risk Management Activities, as of January 1, 2003. As discussed in Note 2, the Company adopted Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation using the prospective method of
transition prescribed by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based CompensationTransition and Disclosure as of January 1, 2003.



/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 23, 2005



F-2



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



CONSOLIDATED BALANCE SHEETS

See Explanatory Note

(in millions)



|                                                                                           |  |                  |        |   |                  |   |        |  
|------------------------------------------------------------------------------------------ |  | ---------------- | ------ | - | ---------------- | - | ------ | -
|                                                                                           |  | December 31,2004 |        |   | December 31,2003 |  
|ASSETS                                                                                     |  |                  |        |   | (Restated)       |  
|Current Assets                                                                             |  |                  |        |   |                  |   |        |  
|Cash and cash equivalents                                                                  |  | $                | 245    |   |                  | $ | 328    |  
|Accounts receivable, net of allowance for doubtful accounts of $169 and $174, respectively |  |                  | 804    |   |                  |   | 806    |  
|Accounts receivable, affiliates                                                            |  |                  | 859    |   |                  |   | 338    |  
|Inventory                                                                                  |  |                  | 233    |   |                  |   | 194    |  
|Assets from risk-management activities                                                     |  |                  | 565    |   |                  |   | 803    |  
|Deferred income taxes                                                                      |  |                  | 73     |   |                  |   | 124    |  
|Prepayments and other current assets                                                       |  |                  | 303    |   |                  |   | 213    |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Total Current Assets                                                                       |  |                  | 3,082  |   |                  |   | 2,806  |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Property, Plant and Equipment                                                              |  |                  | 7,822  |   |                  |   | 7,691  |  
|Accumulated depreciation                                                                   |  |                  | (1,692 | ) |                  |   | (1,389 | )
|                                                                                           |  |                  |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                         |  |                  | 6,130  |   |                  |   | 6,302  |  
|Other Assets                                                                               |  |                  |        |   |                  |   |        |  
|Unconsolidated investments                                                                 |  |                  | 414    |   |                  |   | 577    |  
|Assets from risk-management activities                                                     |  |                  | 313    |   |                  |   | 434    |  
|Deferred income taxes                                                                      |  |                  | 12     |   |                  |   | 13     |  
|Goodwill                                                                                   |  |                  | 15     |   |                  |   | 15     |  
|Other long-term assets                                                                     |  |                  | 192    |   |                  |   | 146    |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Total Assets                                                                               |  | $                | 10,158 |   |                  | $ | 10,293 |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS
EQUITY                                                       |  |                  |        |   |                  |   |        |  
|Current Liabilities                                                                        |  |                  |        |   |                  |   |        |  
|Accounts payable                                                                           |  | $                | 555    |   |                  | $ | 563    |  
|Accounts payable, affiliates                                                               |  |                  | 23     |   |                  |   | 22     |  
|Accrued interest                                                                           |  |                  | 122    |   |                  |   | 107    |  
|Accrued liabilities and other current liabilities                                          |  |                  | 423    |   |                  |   | 317    |  
|Liabilities from risk-management activities                                                |  |                  | 616    |   |                  |   | 823    |  
|Notes payable and current portion of long-term debt                                        |  |                  | 34     |   |                  |   | 79     |  
|Current portion of long-term debt to affiliates                                            |  |                  |       |   |                  |   | 71     |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Total Current Liabilities                                                                  |  |                  | 1,773  |   |                  |   | 1,982  |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Long-term debt                                                                             |  |                  | 3,907  |   |                  |   | 3,464  |  
|Long-term debt to affiliates                                                               |  |                  | 200    |   |                  |   | 200    |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Long-Term Debt                                                                             |  |                  | 4,107  |   |                  |   | 3,664  |  
|Other Liabilities                                                                          |  |                  |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                |  |                  | 395    |   |                  |   | 551    |  
|Deferred income taxes                                                                      |  |                  | 462    |   |                  |   | 329    |  
|Other long-term liabilities                                                                |  |                  | 317    |   |                  |   | 492    |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Total Liabilities                                                                          |  |                  | 7,054  |   |                  |   | 7,018  |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Minority Interest                                                                          |  |                  | 106    |   |                  |   | 121    |  
|Commitments and Contingencies (Note 14)                                                    |  |                  |        |   |                  |   |        |  
|Stockholders Equity                                                                       |  |                  |        |   |                  |   |        |  
|Additional paid-in capital                                                                 |  |                  | 2,413  |   |                  |   | 2,419  |  
|Accumulated other comprehensive income (loss), net of tax                                  |  |                  | (13    | ) |                  |   | 33     |  
|Accumulated deficit                                                                        |  |                  | (434   | ) |                  |   | (330   | )
|Stockholders Equity                                                                       |  |                  | 1,032  |   |                  |   | 1,032  |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Total Stockholders Equity                                                                 |  |                  | 2,998  |   |                  |   | 3,154  |  
|                                                                                           |  |                  |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                 |  | $                | 10,158 |   |                  | $ | 10,293 |  
|                                                                                           |  |                  |        |   |                  |   |        |  



See the notes to the
consolidated financial statements.



F-3



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF OPERATIONS

See Explanatory Note

(in millions)



|                                                                                                                      |  |                         |        |   |            |   |        |            |  |   |        |  
|--------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | ------ | - | ---------- | - | ------ | ---------- |  | - | ------ | -
|                                                                                                                      |  | Year Ended December 31, |       
|                                                                                                                      |  | 2004                    |        |   | 2003       |   |        | 2002       | 
|                                                                                                                      |  |                         |        |   | (Restated) |   |        | (Restated) | 
|Revenues                                                                                                              |  | $                       | 5,351  |   |            | $ | 4,714  |            |  | $ | 4,245  |  
|Cost of sales, exclusive of depreciation shown separately below                                                       |  |                         | (4,716 | ) |            |   | (4,371 | )          |  |   | (3,945 | )
|Depreciation and amortization expense                                                                                 |  |                         | (312   | ) |            |   | (330   | )          |  |   | (270   | )
|Goodwill impairment                                                                                                   |  |                         |       |   |            |   |       |            |  |   | (640   | )
|Impairment and other charges                                                                                          |  |                         | (29    | ) |            |   | (4     | )          |  |   | (184   | )
|Gain on sale of assets, net                                                                                           |  |                         | 69     |   |            |   | 29     |            |  |   | 4      |  
|General and administrative expenses                                                                                   |  |                         | (307   | ) |            |   | (293   | )          |  |   | (255   | )
|                                                                                                                      |  |                         |        |   |            |   |        |            |  |   |        |  
|Operating income (loss)                                                                                               |  |                         | 56     |   |            |   | (255   | )          |  |   | (1,045 | )
|Earnings (losses) from unconsolidated investments                                                                     |  |                         | 126    |   |            |   | 132    |            |  |   | (52    | )
|Interest expense                                                                                                      |  |                         | (359   | ) |            |   | (338   | )          |  |   | (187   | )
|Other income and expense, net                                                                                         |  |                         | 8      |   |            |   | 11     |            |  |   | (25    | )
|Minority interest income (expense)                                                                                    |  |                         | (25    | ) |            |   | 3      |            |  |   | (36    | )
|Accumulated distributions associated with trust preferred securities                                                  |  |                         |       |   |            |   | (8     | )          |  |   | (13    | )
|                                                                                                                      |  |                         |        |   |            |   |        |            |  |   |        |  
|Loss from continuing operations before income taxes                                                                   |  |                         | (194   | ) |            |   | (455   | )          |  |   | (1,358 | )
|Income tax benefit                                                                                                    |  |                         | 97     |   |            |   | 191    |            |  |   | 366    |  
|                                                                                                                      |  |                         |        |   |            |   |        |            |  |   |        |  
|Loss from continuing operations                                                                                       |  |                         | (97    | ) |            |   | (264   | )          |  |   | (992   | )
|Loss from discontinued operations, net of tax benefit (expense) of $(27), $5 and $13, respectively (Note 3)           |  |                         | (7     | ) |            |   | (12    | )          |  |   | (100   | )
|                                                                                                                      |  |                         |        |   |            |   |        |            |  |   |        |  
|Loss before cumulative effect of change in accounting principles                                                      |  |                         | (104   | ) |            |   | (276   | )          |  |   | (1,092 | )
|Cumulative effect of change in accounting principles, net of tax expense of zero, $25 and zero, respectively (Note 2) |  |                         |       |   |            |   | 42     |            |  |   |       |  
|                                                                                                                      |  |                         |        |   |            |   |        |            |  |   |        |  
|Net loss                                                                                                              |  | $                       | (104   | ) |            | $ | (234   | )          |  | $ | (1,092 | )
|                                                                                                                      |  |                         |        |   |            |   |        |            |  |   |        |  





See the notes to the consolidated financial statements.



F-4



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF CASH FLOWS

See Explanatory Note

(in millions)



|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|------------------------------------------------------------------------------ |  | ----------------------- | ---- | - | ---------- | - | ------ | ---------- |  | - | ------ | -
|                                                                               |  | Year Ended December 31, |     
|                                                                               |  | 2004                    |      |   | 2003       |   |        | 2002       | 
|                                                                               |  |                         |      |   | (Restated) |   |        | (Restated) | 
|CASH FLOWS FROM OPERATING ACTIVITIES:                                          |  |                         |      |   |            |   |        |            |  |   |        |  
|Net loss                                                                       |  | $                       | (104 | ) |            | $ | (234   | )          |  | $ | (1,092 | )
|Adjustments to reconcile net loss to net cash flows from operating activities: |  |                         |      |   |            |   |        |            |  |   |        |  
|Depreciation and amortization                                                  |  |                         | 344  |   |            |   | 390    |            |  |   | 427    |  
|Goodwill impairment                                                            |  |                         |     |   |            |   |       |            |  |   | 640    |  
|Impairment and other charges                                                   |  |                         | 29   |   |            |   | 4      |            |  |   | 226    |  
|(Earnings) losses from unconsolidated investments, net of cash distributions   |  |                         | 11   |   |            |   | 23     |            |  |   | 143    |  
|Risk-management activities                                                     |  |                         | (50  | ) |            |   | 377    |            |  |   | 638    |  
|Gain (loss) on sale of assets, net                                             |  |                         | (69  | ) |            |   | (26    | )          |  |   | 84     |  
|Deferred income taxes                                                          |  |                         | (77  | ) |            |   | (199   | )          |  |   | (187   | )
|Cumulative effect of change in accounting principles (Note 2)                  |  |                         |     |   |            |   | (42    | )          |  |   |       |  
|Reserve for doubtful accounts                                                  |  |                         | (7   | ) |            |   | 13     |            |  |   | 52     |  
|Liability associated with gas transportation contracts                         |  |                         | (148 | ) |            |   |       |            |  |   |       |  
|Other                                                                          |  |                         | 58   |   |            |   | (12    | )          |  |   | 105    |  
|Changes in working capital:                                                    |  |                         |      |   |            |   |        |            |  |   |        |  
|Accounts receivable                                                            |  |                         | (8   | ) |            |   | 1,590  |            |  |   | 384    |  
|Inventory                                                                      |  |                         | (31  | ) |            |   | 123    |            |  |   | 1      |  
|Prepayments and other assets                                                   |  |                         | (114 | ) |            |   | 742    |            |  |   | (717   | )
|Accounts payable and accrued liabilities                                       |  |                         | 5    |   |            |   | (1,884 | )          |  |   | (384   | )
|Changes in non-current assets                                                  |  |                         | (26  | ) |            |   | (21    | )          |  |   | 7      |  
|Changes in non-current liabilities                                             |  |                         | 27   |   |            |   | (84    | )          |  |   | (301   | )
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|Net cash provided by (used in) operating activities                            |  |                         | (160 | ) |            |   | 760    |            |  |   | 26     |  
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                          |  |                         |      |   |            |   |        |            |  |   |        |  
|Capital expenditures                                                           |  |                         | (219 | ) |            |   | (205   | )          |  |   | (735   | )
|Investments in unconsolidated affiliates                                       |  |                         |     |   |            |   | (4     | )          |  |   | (11    | )
|Business acquisitions, net of cash acquired                                    |  |                         |     |   |            |   |       |            |  |   | (20    | )
|Proceeds from asset sales, net                                                 |  |                         | 246  |   |            |   | 58     |            |  |   | 715    |  
|Affiliate transactions                                                         |  |                         | (238 | ) |            |   | (272   | )          |  |   | 770    |  
|Other investing, net                                                           |  |                         |     |   |            |   |       |            |  |   | 85     |  
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|Net cash provided by (used in) investing activities                            |  |                         | (211 | ) |            |   | (423   | )          |  |   | 804    |  
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                          |  |                         |      |   |            |   |        |            |  |   |        |  
|Net proceeds from long-term borrowings                                         |  |                         | 581  |   |            |   | 1,863  |            |  |   | 532    |  
|Net proceeds from short-term borrowings                                        |  |                         |     |   |            |   |       |            |  |   | 181    |  
|Repayments of borrowings                                                       |  |                         | (267 | ) |            |   | (2,366 | )          |  |   | (441   | )
|Net cash flow from commercial paper and revolving lines of credit              |  |                         |     |   |            |   | (128   | )          |  |   | (540   | )
|Other financing, net                                                           |  |                         | (25  | ) |            |   | (21    | )          |  |   | (14    | )
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|Net cash provided by (used in) financing activities                            |  |                         | 289  |   |            |   | (652   | )          |  |   | (282   | )
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|Effect of exchange rate changes on cash                                        |  |                         | (1   | ) |            |   | 10     |            |  |   | (59    | )
|Net increase (decrease) in cash and cash equivalents                           |  |                         | (83  | ) |            |   | (305   | )          |  |   | 489    |  
|Cash and cash equivalents, beginning of period                                 |  |                         | 328  |   |            |   | 633    |            |  |   | 144    |  
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  
|Cash and cash equivalents, end of period                                       |  | $                       | 245  |   |            | $ | 328    |            |  | $ | 633    |  
|                                                                               |  |                         |      |   |            |   |        |            |  |   |        |  



See the notes to the
consolidated financial statements.



F-5



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS EQUITY

See Explanatory Note

(in millions)



|                                       |  |                          |       |   |                                            |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  
|-------------------------------------- |  | ------------------------ | ----- | - | ------------------------------------------ | - | --- | ------------------------------------ |  | - | ------------------- | - | ----- | - | ----- |  | - | ------ | -
|                                       |  | AdditionalPaid-InCapital |       |   | AccumulatedOtherComprehensiveIncome (Loss) |   |     | RetainedEarnings(AccumulatedDeficit) |  |   | StockholdersEquity |   | Total |  
|December 31, 2001 (Restated)           |  | $                        | 2,392 |   |                                            | $ | 10  |                                      |  | $ | 996                 |   |       | $ | 1,032 |  | $ | 4,430  |  
|Net loss (Restated)                    |  |                          |      |   |                                            |   |    |                                      |  |   | (1,092              | ) |       |   |      |  |   | (1,092 | )
|Other comprehensive income, net of tax |  |                          |      |   |                                            |   | 2   |                                      |  |   |                    |   |       |   |      |  |   | 2      |  
|Options exercised                      |  |                          | 11    |   |                                            |   |    |                                      |  |   |                    |   |       |   |      |  |   | 11     |  
|401(k) plan and profit sharing stock   |  |                          | 7     |   |                                            |   |    |                                      |  |   |                    |   |       |   |      |  |   | 7      |  
|                                       |  |                          |       |   |                                            |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  
|December 31, 2002 (Restated)           |  | $                        | 2,410 |   |                                            | $ | 12  |                                      |  | $ | (96                 | ) |       | $ | 1,032 |  | $ | 3,358  |  
|Net loss (Restated)                    |  |                          |      |   |                                            |   |    |                                      |  |   | (234                | ) |       |   |      |  |   | (234   | )
|Other comprehensive income, net of tax |  |                          |      |   |                                            |   | 21  |                                      |  |   |                    |   |       |   |      |  |   | 21     |  
|Options exercised                      |  |                          | 2     |   |                                            |   |    |                                      |  |   |                    |   |       |   |      |  |   | 2      |  
|401(k) plan and profit sharing stock   |  |                          | 5     |   |                                            |   |    |                                      |  |   |                    |   |       |   |      |  |   | 5      |  
|Options granted                        |  |                          | 2     |   |                                            |   |    |                                      |  |   |                    |   |       |   |      |  |   | 2      |  
|                                       |  |                          |       |   |                                            |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  
|December 31, 2003 (Restated)           |  | $                        | 2,419 |   |                                            | $ | 33  |                                      |  | $ | (330                | ) |       | $ | 1,032 |  | $ | 3,154  |  
|Net loss                               |  |                          |      |   |                                            |   |    |                                      |  |   | (104                | ) |       |   |      |  |   | (104   | )
|Other comprehensive loss, net of tax   |  |                          |      |   |                                            |   | (46 | )                                    |  |   |                    |   |       |   |      |  |   | (46    | )
|Options exercised                      |  |                          | (6    | ) |                                            |   |    |                                      |  |   |                    |   |       |   |      |  |   | (6     | )
|                                       |  |                          |       |   |                                            |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  
|December 31, 2004                      |  | $                        | 2,413 |   |                                            | $ | (13 | )                                    |  | $ | (434                | ) |       | $ | 1,032 |  | $ | 2,998  |  
|                                       |  |                          |       |   |                                            |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  





See the notes to the consolidated financial statements.



F-6



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

See Explanatory Note

(in millions)



|                                                                                                                                                        |  |                         |      |   |            |   |      |            |  |   |        |  
|------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | ---- | - | ---------- | - | ---- | ---------- |  | - | ------ | -
|                                                                                                                                                        |  | Year Ended December 31, |     
|                                                                                                                                                        |  | 2004                    |      |   | 2003       |   |      | 2002       | 
|                                                                                                                                                        |  |                         |      |   | (Restated) |   |      | (Restated) | 
|Net loss                                                                                                                                                |  | $                       | (104 | ) |            | $ | (234 | )          |  | $ | (1,092 | )
|Cash flow hedging activities, net:                                                                                                                      |  |                         |      |   |            |   |      |            |  |   |        |  
|Unrealized mark-to-market gains (losses) arising during period, net                                                                                     |  |                         | (62  | ) |            |   | 39   |            |  |   | 73     |  
|Reclassification of mark-to-market (gains) losses to earnings, net                                                                                      |  |                         | 36   |   |            |   | (37  | )          |  |   | (73    | )
|                                                                                                                                                        |  |                         |      |   |            |   |      |            |  |   |        |  
|Changes in cash flow hedging activities, net (net of tax benefit (expense) of $16, $(1) and zero, respectively)                                         |  |                         | (26  | ) |            |   | 2    |            |  |   |       |  
|Foreign currency translation adjustments                                                                                                                |  |                         | (11  | ) |            |   | 19   |            |  |   | 3      |  
|Minimum pension liability (net of tax benefit of $5, zero and $2, respectively)                                                                         |  |                         | (9   | ) |            |   |     |            |  |   | (3     | )
|Unrealized gains on securities, netReclassification adjustments for losses realized in net loss, net of tax expense of zero, zero and
$1, respectively |  |                         |     |   |            |   |     |            |  |   | 2      |  
|                                                                                                                                                        |  |                         |      |   |            |   |      |            |  |   |        |  
|Other comprehensive income (loss), net of tax                                                                                                           |  |                         | (46  | ) |            |   | 21   |            |  |   | 2      |  
|                                                                                                                                                        |  |                         |      |   |            |   |      |            |  |   |        |  
|Comprehensive loss                                                                                                                                      |  | $                       | (150 | ) |            | $ | (213 | )          |  | $ | (1,090 | )
|                                                                                                                                                        |  |                         |      |   |            |   |      |            |  |   |        |  



See the notes to the
consolidated financial statements.



F-7



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##### Table of Contents

##### Index to Financial Statements

DYNEGY INC.



NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS



Explanatory Note



This Annual Report on Form 10-K for the fiscal year ended December 31, 2004 includes restatements of our consolidated financial statements for each of the
two years ended December 31, 2003 and restatements prior to 2002. The restatements relate to our deferred income tax accounts. Although this item was not considered material to the periods to which it related, this item is material to our 2004
results. We are required to restate prior periods in accordance with APB 20, Accounting Changes. Quarterly information in this Explanatory Note is unaudited. Specifically, the restatement is as follows:



Deferred Income Tax Accounts.In Amendment No. 1 to our third
quarter 2004 Form 10-Q, we detailed the steps implemented to improve our internal controls around our tax accounting and tax reconciliation controls and processes. Recently, during the preparation of our financial statements for inclusion in this
Form 10-K, and as a result of these additional internal controls, we determined that adjustments related to our deferred income tax accounts in periods prior to 2004 were required. These adjustments, which primarily related to errors in our
previously completed tax basis balance sheet review, resulted in a $6 million increase of our deferred tax liability at December 31, 2003. The aggregate effect of this restatement on our net loss for the twelve months ended December 31, 2003 is a
decrease in net loss of $6 million. This restatement had no impact on our net loss for the year ended December 31, 2004 or our previously reported cash provided by (used in) operating activities, investing activities or financing activities.



The table below reflects the quarterly and year-to-date impact
of the correction to our previous accounting for income taxes on net loss as originally reported in Amendment No. 1 to our Annual Report of Form 10-K for the year ended December 31, 2003.



|               |  |                          |   |                         |   |                              |  |                       |   |                              |   |                              |  |   |   |  |   |    |  
|-------------- |  | ------------------------ | - | ----------------------- | - | ---------------------------- |  | --------------------- | - | ---------------------------- | - | ---------------------------- |  | - | - |  | - | -- | -
|               |  | ThreeMonthsEndedMarch 31 |   | ThreeMonthsEndedJune 30 |   | ThreeMonthsEndedSeptember 30 |  | SixMonthsEndedJune 30 |   | Nine MonthsEndedSeptember 30 |   | TwelveMonthsEndedDecember 31 | 
|               |  | (in millions)            |  
|2001 and prior |  |                          |   |                         |   |                              |  |                       |   |                              |   |                              |  |   |   |  | $ | (4 | )
|2002           |  | $                        |  |                         | $ |                             |  | $                     |  |                              | $ |                             |  | $ |  |  |   | (8 | )
|2003           |  |                          |  |                         |   |                             |  |                       |  |                              |   |                             |  |   |  |  |   | 6  |  



F-8



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Summary.A synopsis of the aggregate financial impact of these restatements on the
amounts originally reported in Amendment No. 1 to our Annual Report of Form 10-K for the year ended December 31, 2003 is as follows:



RESTATED SELECTED BALANCE SHEET DATA



|                             |  |                  |       |  
|---------------------------- |  | ---------------- | ----- | -
|                             |  | December 31,2003 |      
|                             |  | (in millions)    |      
|Deferred income taxes        |  |                  |       |  
|As previously reported       |  | $                | 186   |  
|Deferred income tax accounts |  |                  | 6     |  
|                             |  |                  |       |  
|As restated                  |  | $                | 192   |  
|                             |  |                  |       |  
|Total Liabilities            |  |                  |       |  
|As previously reported       |  | $                | 7,196 |  
|Reclassifications (1)        |  |                  | (184  | )
|Deferred income tax accounts |  |                  | 6     |  
|                             |  |                  |       |  
|As restated                  |  | $                | 7,018 |  
|                             |  |                  |       |  
|Stockholders Equity         |  |                  |       |  
|As previously reported       |  | $                | 3,160 |  
|Deferred income tax accounts |  |                  | (6    | )
|                             |  |                  |       |  
|As restated                  |  | $                | 3,154 |  
|                             |  |                  |       |  

---

|(1) | Adjustment to our balances for total liabilities relate to reclassifications of December 31, 2003 balance sheet amounts to conform to the December 31, 2004 balance sheet
presentation.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



RESTATED SELECTED RESULTS OF
OPERATIONS DATA



|                             |  |                        |      |   |      |   |        |  
|---------------------------- |  | ---------------------- | ---- | - | ---- | - | ------ | -
|                             |  | Year EndedDecember 31, |     
|                             |  | 2003                   |      |   | 2002 |  
|                             |  | (in millions)          |     
|Income tax benefit           |  |                        |      |   |      |   |        |  
|As previously reported       |  | $                      | 185  |   |      | $ | 374    |  
|Deferred income tax accounts |  |                        | 6    |   |      |   | (8     | )
|                             |  |                        |      |   |      |   |        |  
|As restated                  |  | $                      | 191  |   |      | $ | 366    |  
|                             |  |                        |      |   |      |   |        |  
|Net loss                     |  |                        |      |   |      |   |        |  
|As previously reported       |  | $                      | (240 | ) |      | $ | (1,084 | )
|Deferred income tax accounts |  |                        | 6    |   |      |   | (8     | )
|                             |  |                        |      |   |      |   |        |  
|As restated                  |  | $                      | (234 | ) |      | $ | (1,092 | )
|                             |  |                        |      |   |      |   |        |  



Note 1Organization and
Operations of the Company



Dynegy Holdings Inc. (together
with our subsidiaries, we, us or our) is a holding company and conducts substantially all of our business through our subsidiaries. We own operating divisions engaged in power generation and natural gas liquids.
We also separately report the results of our customer risk management business. We had three reportable business segments in 2004: GEN, NGL and CRM. We reported our results in



F-9



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



these three business segments based on the diversity of their respective operations. Please see a description of abbreviations used in these footnotes
beginning on page F-71.



Note 2Accounting Policies



Our accounting policies conform to GAAP. Our most
significant accounting policies are described below. The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of
operations. 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 used in, among other things, (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 our estimates.



Principles of Consolidation.The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned
or controlled subsidiaries, variable interest entities for which we are the primary beneficiary and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities. Intercompany
accounts and transactions have been eliminated. Certain reclassifications have been made to prior-period amounts to conform with current-period financial statement classifications.



Cash and Cash Equivalents.Cash and cash equivalents consist of all demand deposits and funds invested in
highly liquid short-term investments with original maturities of three months or less.



Allowance for Doubtful Accounts.We establish provisions for losses on accounts receivable if it becomes probable we will not collect all or part of outstanding balances. We review collectibility and
establish or adjust our allowance as necessary primarily using a percent of balance methodology and methodologies involving historical levels of write-offs. The specific identification method is also used in certain circumstances.



Investment in Unconsolidated Affiliates.Investments in
affiliates over which we exercise significant influence, generally occurring in ownership interests of 20% to 50%, and also occurring in lesser ownership percentages due to voting rights or other factors, are accounted for using the equity method.
Our share of net income from these affiliates is reflected in the consolidated statements of operations as earnings (losses) from unconsolidated investments. Any excess of our investment in affiliates, as compared to our share of the underlying
equity that is not recognized as goodwill, is amortized over the estimated economic service lives of the underlying assets. Other investments over which we may not exercise significant influence and that have readily determinable fair values are
considered available-for-sale and are recorded at quoted market values or at the lower of cost or net realizable value, if there are no readily determinable fair values. For securities with readily determinable fair values, the change in the
unrealized gain or loss, net of deferred income tax, is recorded as a separate component of accumulated other comprehensive income (loss) in the consolidated statements of comprehensive loss. Realized gains and losses on investment transactions are
determined using the specific identification method. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in earnings (losses) from unconsolidated investments
in the consolidated statements of operations.



F-10



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Concentration of Credit Risk.We sell our energy products and services to customers in
the electric and gas distribution industries and to entities engaged in industrial and petrochemical businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because
the customer base may be similarly affected by changes in economic, industry, weather or other conditions.



At December 31, 2004, our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $259 million. To reduce our
credit exposure, we execute agreements that permit us to offset receivables, payables and mark-to-market exposure. We attempt to further reduce credit risk with certain counterparties by obtaining third-party guarantees or collateral as well as the
right of termination in the event of default.



Our Credit
Department, based on guidelines approved by the Board of Directors, establishes our counterparty credit limits. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. Our credit risk system
provides current credit exposure to counterparties on a daily basis.



We enter into master netting agreements both to mitigate credit exposure and to reduce collateral requirements. In general, the agreements include our risk management subsidiaries and allow the aggregation of credit exposure, margin and
set-off. As a result, we decrease a potential credit loss arising from a counterparty default.



Inventory.Our natural gas, natural gas liquids, coal, emission allowances and fuel oil inventories are carried at the lower of weighted average cost or at market. Our materials and supplies inventory is
carried at the lower of cost or market using the specific identification method.



Property, Plant and Equipment.Property, plant and equipment, which has consisted principally of gas gathering, processing, fractionation, terminalling and storage facilities, natural gas transportation
and electric transmission lines, pipelines and power generating facilities, is recorded at historical cost. Expenditures for major replacements, renewals and major maintenance are capitalized. We consider major maintenance to be expenditures
incurred on a cyclical basis to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in operating condition are expensed. Depreciation is provided using the straight-line method
over the estimated economic service lives of the assets, ranging from 3 to 40 years. Composite depreciation rates (which we refer to as composite rates) are applied to functional groups of assets having similar economic characteristics. The
estimated economic service lives of our functional asset groups are as follows:



|                                                                       |  |              
|---------------------------------------------------------------------- |  | -------------
|Asset Group                                                            |  | Range ofYears
|Power Generation Facilities                                            |  | 28 to 40     
|Natural Gas Gathering Systems and Processing Facilities                |  | 15 to 25     
|Fractionation, Terminalling and Natural Gas Liquids Storage Facilities |  | 15 to 25     
|Transportation Equipment                                               |  | 5 to 10      
|Buildings and Improvements                                             |  | 10 to 40     
|Office and Miscellaneous Equipment                                     |  | 3 to 35      



Gains and losses are
not recognized for retirements of property, plant and equipment subject to composite rates until the asset group subject to the composite rate is retired. Gains and losses on sales of individual assets are reflected in gain on sale of assets, net in
the consolidated statements of operations. We assess the carrying



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



value of our property, plant and equipment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. If an
impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the related discounted cash flows of the assets and recording a loss if the resulting estimated fair value is less than the book value. For
assets identified as held for sale, the book value is compared to comparable market prices, or the estimated fair value if comparable market prices are not readily available, to determine if an impairment loss is required. Please see Note
4Restructuring and Impairment Charges beginning on page F-23 for a discussion of impairment charges we recognized in 2004, 2003 and 2002.



Asset Retirement Obligations.We adopted SFAS No. 143, Asset Retirement Obligations, effective January 1, 2003. Under the
provisions of SFAS No. 143, we are required to record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount when the liability is incurred. Significant judgment is involved in
estimating future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flow change, the change may have a material impact on our results of operations.



As part of the transition adjustment in adopting SFAS No. 143,
existing environmental liabilities in the amount of $73 million were reversed in the first quarter 2003. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the ARO and was
recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities exceeded the fair value of the future retirement obligations, the impact of adopting SFAS No. 143 was an increase in earnings, net of tax, of $36 million in the first
quarter 2003, which is included in cumulative effect of change in accounting principles in the consolidated statements of operations. In addition to these liabilities, we also have potential retirement obligations for dismantlement of power
generation facilities, a fractionation facility and natural gas storage facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate any potential retirement
obligations associated with these assets. Liabilities will be recorded in accordance with SFAS No. 143 at the time we are able to estimate any new AROs.



Our AROs relate to activities such as ash pond and landfill capping, closure and post-closure costs, environmental testing, remediation, monitoring and
land and equipment lease obligations. Annual amortization of the assets associated with the AROs was $2 million and $6 million in 2004 and 2003, respectively. A summary of changes in our AROs by reportable segment is as follows:



|                             |  |     |    |     |   |       |  |   |   
|---------------------------- |  | --- | -- | --- | - | ----- |  | - | --
|                             |  | GEN |    | NGL |   | Total
|Balance at January 1, 2003   |  | $   | 26 |     | $ | 9     |  | $ | 35
|Accretion expense            |  |     | 4  |     |   | 1     |  |   | 5 
|                             |  |     |    |     |   |       |  |   |   
|Balance at December 31, 2003 |  |     | 30 |     |   | 10    |  |   | 40
|Accretion expense            |  |     | 4  |     |   | 1     |  |   | 5 
|Other (1)                    |  |     | 1  |     |   |      |  |   | 1 
|                             |  |     |    |     |   |       |  |   |   
|Balance at December 31, 2004 |  | $   | 35 |     | $ | 11    |  | $ | 46
|                             |  |     |    |     |   |       |  |   |   

---

|(1) | During 2004, a land lease, and the related ARO, formerly held by Illinois Power was transferred to our GEN segment. In addition, AROs totaling less than $1 million were removed
following our sales of Sherman and our interest in Indian Basin. There were no additional AROs recorded or settled, nor were there any revisions to estimated cash flows associated with existing AROs, during 2004.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



The following pro forma financial information has been prepared to give effect to the adoption of
SFAS No. 143 for the year ended December 31, 2002 as if it had been adopted January 1, 2002 (in millions, except per share amounts):



|                                                                              |  |   |        |  
|----------------------------------------------------------------------------- |  | - | ------ | -
|Loss from continuing operations, as reported                                  |  | $ | (992   | )
|Pro forma adjustments to reflect retroactive adoption of SFAS No. 143         |  |   | (5     | )
|                                                                              |  |   |        |  
|Pro forma loss from continuing operations                                     |  | $ | (997   | )
|                                                                              |  |   |        |  
|Loss before cumulative effect of change in accounting principles, as reported |  | $ | (1,092 | )
|Pro forma adjustments to reflect retroactive adoption of SFAS No. 143         |  |   | (3     | )
|                                                                              |  |   |        |  
|Pro forma loss before cumulative effect of change in accounting principles    |  | $ | (1,095 | )
|                                                                              |  |   |        |  
|Net loss, as reported                                                         |  | $ | (1,092 | )
|Pro forma adjustments to reflect retroactive adoption of SFAS No. 143         |  |   | (3     | )
|                                                                              |  |   |        |  
|Pro forma net loss                                                            |  | $ | (1,095 | )
|                                                                              |  |   |        |  



Contingencies,
Commitments, Guarantees and Indemnifications.We are involved in numerous lawsuits, claims, proceedings, joint venture audits and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, Accounting for
Contingencies, we record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we
have appropriate reserves recorded on the consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage for
litigation matters, and are adjusted as circumstances warrant. Our estimates and judgment could change based on new information, changes in laws or regulations, changes in managements plans or intentions, the outcome of legal proceedings,
settlements or other factors. If different estimates and judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts. Actual results could vary materially from these estimates and
judgments.



Liabilities for environmental contingencies are
recorded when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations,
existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability. These assumptions involve the judgments and
estimates of management and any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.



We follow the guidance of FIN No. 45 Guarantors Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others for disclosures and accounting of various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification subject to FIN No. 45 is entered into, an
estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances, however management also considers the probability of such
circumstances occurring when estimating the fair value. Actual results may materially differ from the estimated fair value of such guarantees and indemnifications.



Goodwill and Other Intangible Assets. Goodwill represents, at the time of an acquisition, the amount of
purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



No. 142, Goodwill and Other Intangible Assets, when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for
impairment on an annual basis and when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective, inherently imprecise and can change materially from
period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. We currently perform our annual impairment test in the fourth quarter after our annual budgetary process, and we may record
further impairment losses in future periods as a result of such test. Please see Note 10Goodwill beginning on page F-33 for discussion of impairment charges we recognized for 2003 and 2002.



Revenue Recognition. We utilize two comprehensive accounting
models in reporting our consolidated financial position and results of operations as required by GAAPan accrual model and a fair value model. We determine the appropriate model for our operations based on guidance provided in applicable
accounting standards and positions adopted by the FASB or the SEC. We have applied these accounting policies on a consistent basis during the three years in the period ended December 31, 2004, except as required by the adoption of EITF Issue 02-03,
Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, which rescinded EITF Issue 98-10, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities.



The accrual
model has historically been used to account for substantially all of the operations conducted in our GEN and NGL segments. These segments consist largely of the ownership and operation of physical assets that we use in various generation, processing
and delivery operations. The business of these segments includes the generation of electricity, the separation of natural gas liquids into their component parts from a stream of natural gas and the transportation or transmission of commodities
through pipelines or over transmission lines. End sales from these businesses result in physical delivery of commodities to our wholesale, commercial, industrial and retail customers. We recognize revenue from these transactions when the product or
service is delivered to a customer.



The fair value model has
historically been used to account for forward physical and financial transactions, occurring primarily in the CRM and GEN segments, which meet criteria defined by the FASB or the EITF. The criteria are complex, but generally require these contracts
to relate to future periods, to contain fixed price and volume components and to have terms that require or permit net settlement of the contract in cash or the equivalent. The FASB determined that the fair value model is the most appropriate method
for accounting for these types of contracts. In part, this conclusion is based on the cash settlement provisions in these agreements, as well as the volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, which
impact the valuation of these contracts. Since these transactions may be settled in cash or the equivalent, the value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current prices
and rates as of each balance sheet date.



We estimate the fair
value of our marketing portfolio using a liquidation value approach assuming that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is computed by multiplying all existing
positions in the portfolio by estimated prices, reduced by a time value of money adjustment and deduction of reserves for credit and price. The estimated prices in this valuation are based either on (1) prices obtained from market quotes, when there
are an adequate number of quotes to consider the period liquid, or, if market quotes are unavailable, or the market is not considered to be liquid, (2) prices from a proprietary model which incorporates forward energy prices derived from market
quotes and values from previously executed transactions. The amounts recorded as revenue change as these estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control.



Typically, derivative contracts can be accounted for in three
different ways: (1) as an accrual contract, if the criteria for the normal purchase normal sale exemption are met and documented; (2) as a cash flow or fair



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



value hedge, if the criteria are met and documented; or (3) as a mark-to-market contract with changes in fair value recognized in current period earnings.
Generally, we only mark-to-market through earnings our derivative contracts if they do not qualify for the normal purchase normal sale exemption or as a cash flow hedge. Because derivative contracts can be accounted for in three
different ways, and as the normal purchase normal sale exemption and cash flow and fair value hedge accounting are elective, the accounting treatment used by another party for a similar transaction could be different than the accounting
treatment we use.



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



In October 2002, as an additional component of EITF Issue 02-03, the EITF
rescinded EITF Issue 98-10, which previously required use of mark-to-market accounting for our energy trading contracts. While the rescission of EITF Issue 98-10 reduced the number of contracts accounted for on a mark-to-market basis, it did not
eliminate mark-to-market accounting. All derivative contracts that either do not qualify, or are not designated, as hedges or as normal purchases or sales, as defined by SFAS No. 133, Accounting for Derivative Instruments and Hedging
Activities, as amended, continue to be marked-to-market in the consolidated statements of operations in accordance with SFAS No. 133. Any earnings or losses previously recognized under EITF Issue 98-10 that would not have been recognized under
SFAS No. 133 were reversed in 2003 pursuant to adopting the provisions of EITF Issue 02-03. The cumulative effect of this change in accounting principle resulted in after-tax earnings of $21 million in 2003 and comprised the following items that are
no longer required to be recorded using mark-to-market accounting (in millions):



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

---

|(1) | All of the natural gas inventory was sold during 2003.
|--- | ------------------------------------------------------



Cash inflows and cash outflows associated with the settlement of risk management activities are recognized in net cash provided by (used in) operating
activities on the consolidated statements of cash flows.



Income Taxes. Our parent, Dynegy, files a consolidated U.S. federal income tax return and, for financial reporting purposes, accounts for income taxes using the liability method in accordance with SFAS No. 109,
Accounting for Income Taxes, which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences.



As part of the process of preparing our consolidated financial statements, we
are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current



F-15



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



tax payable and related tax expense together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax
and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.



We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more
likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether,
based on the weight of the evidence, a valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available
information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies.



Management believes future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize
assets for which no reserve has been established. While we have considered these factors in assessing the need for a valuation allowance, there is no assurance that a valuation allowance would not need to be established in the future if information
about future years change. Any change in the valuation allowance would impact our income tax expense and net income in the period in which such a determination is made.



We are included in the consolidated federal and state income tax returns filed by Dynegy. Pursuant to tax allocation
arrangements, we record a receivable from Dynegy in an amount equal to the tax benefits realized in Dynegys consolidated federal income tax return resulting from the utilization of our net operating losses and/or tax credits, or record a
payable to Dynegy in an amount equal to the federal income tax computed on our separate company taxable income less the tax benefits associated with net operating losses and/or tax credits generated by us which are utilized in Dynegys
consolidated federal income tax return.



Please see Note
13Income Taxes beginning on page F-40 for further discussion of our accounting for income taxes and any change in our valuation allowance.



Foreign Currency. For subsidiaries whose functional currency is not the U.S. Dollar, assets and liabilities are translated at year-end rates
of exchange and revenues and expenses are translated at monthly average exchange rates. Translation adjustments for the asset and liability accounts are included as a separate component of accumulated other comprehensive loss in stockholders
equity. Currency transaction gains and losses are recorded in other income and expense, net on the consolidated statements of operations and totaled gains (losses) of approximately $1 million, zero and $13 million for the years ended December 31,
2004, 2003 and 2002, respectively.



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



Under the prospective method of transition, all stock options granted by Dynegy after January 1, 2003 are accounted for on a fair value basis. Options
granted prior to January 1, 2003 continue to be accounted for using



F-16



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense is not reflected for employee stock options
unless they were granted at an exercise price lower than market value on the grant date. Dynegy has granted in-the-money options in the past and we continue to recognize compensation expense over the applicable vesting periods. No in-the-money stock
options have been granted since 1999.



Had compensation cost
for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net loss would have approximated the following pro forma amounts for the years ended December 31, 2004, 2003 and 2002, respectively.



|                                                                                                                                            |  |                                     |      |   |      |   |      |      |  |   |        |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------- | ---- | - | ---- | - | ---- | ---- |  | - | ------ | -
|                                                                                                                                            |  | Years Ended December 31,            |     
|                                                                                                                                            |  | 2004                                |      |   | 2003 |   |      | 2002 | 
|                                                                                                                                            |  | (in millions, except per sharedata) |     
|Net loss as reported                                                                                                                        |  | $                                   | (104 | ) |      | $ | (234 | )    |  | $ | (1,092 | )
|Add: Stock-based employee compensation expense included in reported net loss, net of related tax effects                                    |  |                                     | 4    |   |      |   | 2    |      |  |   | 8      |  
|Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax
effects |  |                                     | (15  | ) |      |   | (30  | )    |  |   | (70    | )
|                                                                                                                                            |  |                                     |      |   |      |   |      |      |  |   |        |  
|Pro forma net loss                                                                                                                          |  | $                                   | (115 | ) |      | $ | (262 | )    |  | $ | (1,154 | )
|                                                                                                                                            |  |                                     |      |   |      |   |      |      |  |   |        |  



Minority
Interest.Minority interest on the consolidated balance sheets includes third-party investments in entities that we consolidate, but do not wholly-own. The net pre-tax results attributed to minority interest holders in consolidated entities
are included in minority interest income (expense) in the consolidated statements of operations.



Accounting Principles Adopted



SFAS No. 150. In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity, which establishes how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Instruments that have an unconditional obligation requiring the issuer to redeem
the instrument by transferring an asset at a specified date are required to be classified as liabilities on the balance sheet. Instruments that require the issuance of a variable number of equity shares by the issuer generally do not have the risks
associated with equity instruments and as such should also be classified as liabilities on the balance sheet. SFAS No. 150 was effective for contracts in existence or created or modified for the first interim period beginning after June 15, 2003.
Upon adoption, we reclassified approximately $200 million of Subordinated Debentures, previously recorded in the mezzanine section of our balance sheet between liabilities and stockholders equity, to long-term liabilities. Accordingly, the
interest related to this instrument is recorded as interest expense beginning July 1, 2003. Prior year amounts have not been reclassified to conform to this change. Previously, the preferred return on this instrument was reported in accumulated
distributions associated with trust preferred securities in the consolidated statements of operations.



FIN No. 46R. In January 2003, the FASB issued FIN No. 46, Consolidation of Variable Interest EntitiesAn Interpretation of ARB
No. 51. In December 2003, the FASB issued the updated and final interpretation FIN No. 46R. FIN No. 46R requires that an equity investor in a variable interest entity have significant equity at risk (generally a minimum of 10%, which is an
increase from the 3% required under previous guidance) and hold a controlling interest, evidenced by voting rights, and absorb a majority of the entitys expected losses, receive a



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



majority of the entitys expected returns, or both. If the equity investor is unable to evidence these characteristics, the entity that retains these
ownership characteristics is required to consolidate the variable interest entity as the primary beneficiary. FIN No. 46R was applicable immediately to variable interest entities created or obtained after January 31, 2003. While we have not entered
into any arrangements in 2004 or 2003 that would be subject to FIN No. 46R, entities previously formed are impacted. FIN No. 46R was effective on December 31, 2003 for interests in entities that were previously considered special purpose entities
under then existing authoritative guidance. We recorded a cumulative effect of change in accounting principle of $15 million after-tax related to our adoption of this portion of FIN No. 46R, as further described below.



CoGen Lyondell, Inc. (CLI) was the lessee of the CoGen Facility, a 610 MW
gas-fueled combined-cycle co-generation plant that sells steam and electricity to the Lyondell Chemical Complex and sells electricity to the open wholesale market in ERCOT. Additionally, CoGen Lessor was a synthetic lease entity which leased the
CoGen Facility to CLI. Both entities were previously considered special purpose entities and also met the definition of a VIE because their equity holders did not have a controlling interest or significant equity investment at risk in the entity. We
were considered the primary beneficiary of both entities as we held a fixed-price purchase option on the assets of the entities during the lease term and maintained a residual value guarantee for 97% of the facility on CoGen Lessor. FIN No. 46R did
not impact our accounting for CLI, as we have always consolidated CLI. Additionally, we began accounting for our lease with CoGen Lessor as a capital lease in June 2002, and, therefore, began consolidating the generation facility and the associated
debt. If we had adopted this provision of FIN No. 46R on January 1, 2002, our income (loss) before cumulative effect of change in accounting principles would have decreased by zero and $1 million for the years ended December 31, 2003 and 2002,
respectively. Our net income (loss) would have increased (decreased) by $15 million and $(1) million for the years ended December 31, 2003 and 2002, respectively. The $15 million cumulative effect noted above is primarily a result of recording
additional accumulated depreciation on the facility from June 1997, the inception of the leasing arrangement, through June 2002. We retired the $170 million capital lease obligation with proceeds received from our October 2003 follow-on notes
offering further described in Note 11DebtSecond Priority Senior Secured Notes beginning on page F-36.



We adopted the remaining provisions of FIN No. 46R on March 31, 2004. These provisions require that we review the structure of non-SPE legal entities in
which we have an investment and other legal entities with whom we transact to determine whether such entities are VIEs, as defined by FIN No. 46R. With respect to each of the VIEs we identified, we assessed whether we are the primary
beneficiary, as defined by FIN No. 46R. We concluded that we were not the primary beneficiary of any of these entities and, therefore, the adoption did not have an impact on our consolidated financial statements.



FIN No. 46R requires additional disclosures for entities which meet the
definition of a VIE in which we hold a significant variable interest but are not the primary beneficiary. We own 50% equity interests in various generation facilities in Illinois and California, which are accounted for using the equity method and
are included in unconsolidated investments in our consolidated balance sheets. We acquired or began involvement with these equity interests in 1997 and 1999. Total net generating capacity for these generating facilities ranges from 165 MW to 902 MW.
As a result of various contractual arrangements into which these entities have entered, we have concluded that they are VIEs. As we do not absorb a majority of the expected losses or receive a majority of the expected residual returns, we are not
considered the primary beneficiary of these entities. Our equity investment balance in the facilities totaled $324 million at December 31, 2004, and one of these entities has a loan outstanding to another of these entities, which totaled $20 million
at December 31, 2004.



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 Partners, L.P., which we refer to as Independence and which owns and
operates a 1,021 MW combined



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



cycle natural gas generation facility near Scriba, New York. We had previously been unable to assess whether the entity was a VIE, but have subsequently
received the necessary financial and contractual information related to the entity. 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 are approximately $753 million, which includes the fixed capacity
payments under our power tolling contract and fixed payments related to the financial derivative instrument. On January 31, 2005, Dynegy completed the acquisition of ExRes SHC, Inc., the parent company of Sithe Energies and Independence. Please see
Note 20Subsequent Events beginning on page F-70 for further discussion regarding this acquisition.



Accounting Principles Not Yet Adopted



SFAS No. 123(R). In December 2004, the FASB issued SFAS No. 123(R), Share-Based Payment, which revises SFAS No. 123. SFAS No.
123(R) is effective July 1, 2005 for all calendar year-end companies and requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. This expense will be recognized over the period during which
an employee is required to provide services in exchange for the award.



As noted in Employee Stock Options above, we transitioned to a fair value based method of accounting for stock-based compensation in the first quarter 2003. Our share-based payments primarily consist of stock options and
restricted stock awards. For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model. 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. Prior to the issuance of SFAS No. 123(R), we adopted the modified prospective approach for
expensing the fair value of stock options and restricted stock awards granted after January 1, 2003, and as such we do not expect the guidance under SFAS 123(R) to have a material impact on our consolidated statement of operations.



Note 3Dispositions, Contract Terminations and Discontinued Operations



Dispositions and Contract Terminations



Sale of Illinois Power.On September 30, 2004, Dynegy sold all of the outstanding common and preferred shares of Illinois Power Company, owned by Illinova Corporation, its subsidiary, as well as its 20% interest in the Joppa power generation facility, to Ameren
for $2.3 billion. Concurrently with that sale, we entered into a new two-year power purchase agreement with Illinois Power. Under the terms of this new agreement, which became effective January 1, 2005, we have agreed to provide Illinois Power with
up to 2,800 MWs of capacity at $48.00 per kW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. We also agreed to sell 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to Illinois Power at a fixed price of
$16 per KW-yr with an option to purchase energy at market-based prices.



Sherman. In November 2004, we sold our Sherman natural gas processing facility located in Sherman, Texas. This sale resulted in a pre-tax gain of approximately $16 million. This gain is included in gain on sale of assets, net
on our consolidated statements of operations.



Indian
Basin. In April 2004, we sold our 16% interest in the Indian Basin Gas Processing Plant for approximately $48 million, and we recognized a pre-tax gain on the sale of approximately $36 million. This gain is included in gain on sale of
assets, net on our consolidated statements of operations.



Kendall. On November 18, 2004, DPM entered into a back to back power purchase agreement with Constellation Energy Commodities Group, Inc., or Constellation, under which Constellation will effectively



F-19



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



receive DPMs rights to purchase approximately 570 MW of capacity and energy arising under DPMs tolling contract with LSP-Kendall Energy, LLC for
a four-year term from December 2004 through November 2008. DPM will remain the primary obligor to the Kendall tolling contract, but will receive offsetting payments from Constellation during the four-year term.



In connection with this transaction, DPM paid to Constellation $117.5 million
in cash and effectively eliminated approximately $161 million in our future fixed payment obligations under the Kendall tolling contract through November 2008. We recognized a pre-tax charge of approximately $115 million ($72 million after-tax)
related to this transaction. The charge is included in cost of sales on the consolidated statements of operations.



Gas Transportation Contracts.In June 2004, we agreed to exit four long-term natural gas transportation contracts whose purpose was to
secure firm pipeline capacity through 2014 in support of our former third-party marketing and trading business. In exchange for exiting these obligations, we paid $20 million in June 2004, $16 million in December 2004 and will pay an additional
$26 million in the first quarter 2005. This future payment obligation was recorded at its fair value of $40 million and will be accreted to $42 million over the period July 1, 2004 through March 31, 2005. Additionally, we reversed an aggregate
liability of $148 million associated with the transportation contracts that was originally established in 2001 and recognized a pre-tax gain of $88 million ($55 million after-tax) related to these transactions. This gain is included in revenues on
our consolidated statements of operations and is included in the results of our CRM segment. This agreement eliminated our obligation to make approximately $295 million in aggregate fixed capacity payments from April 2005 through 2014.



Batesville Tolling Arrangement.In December 2003, we reached
an agreement with Virginia Electric and Power Company, a subsidiary of Dominion Resources, to terminate a wholesale power tolling contract totaling approximately 110 MWs. Under the terms of the agreement, we paid Virginia Power $34 million to end
the arrangement. As a result, we eliminated approximately $63 million in future capacity payments as well as collateral obligations of $12.5 million. We recognized a pre-tax loss of approximately $34 million ($22 million after-tax) in connection
with this agreement.



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



The four contracts were derivatives under
SFAS No. 133 and were carried at their fair value on the consolidated balance sheets, with changes in fair value recognized in earnings. Our net risk management asset related to these contracts was approximately $140 million at June 30, 2003.
Therefore, the $30 million difference between the settlement of $110 million and the carrying value of the net risk management asset was recorded as a pre-tax charge ($19 million after-tax). The two restructured contracts were carried at fair value
with changes in fair value recognized in earnings through August 2003, when such contracts were terminated.



Southern Power Tolling Arrangements.In the second quarter 2003, we reached an agreement with Southern Power to terminate three power
tolling arrangements among Dynegy, Southern Power and our respective affiliates covering an aggregate of 1,100 MWs. Under the terms of the agreement, we paid Southern Power $155 million to terminate these arrangements. The terminations resulted in
$89 million of net collateral being returned to us and eliminated our obligation to make $1.7 billion of capacity payments to Southern Power over the next 30 years. The transaction closed in May 2003, and we recognized a pre-tax loss of
approximately $133 million ($84 million after-tax).



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Hackberry LNG Project.During the first quarter 2003, we entered into an agreement to
sell our interest in Hackberry LNG Terminal LLC, the entity we formed in connection with our proposed LNG terminal/gasification project in Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction
closed in April 2003. At closing, we received an initial payment of $20 million and recognized a pre-tax gain of approximately $12 million ($8 million after-tax). We retained the right to receive additional contingent payments based upon project
development milestones. In October 2003, we received a $15 million payment associated with the completion of a project milestone and recognized a pre-tax gain of $15 million ($9 million after-tax). In March 2004, we sold our remaining financial
interest in this project, which interest included rights to receive future contingent payments under the 2003 agreement, for $17 million and recognized a pre-tax gain of $17 million. These gains are included in gain on sale of assets, net on our
consolidated statements of operations.



SouthStar Energy
Services.During the first quarter 2003, we completed the sale of our 20% equity investment in SouthStar Energy Services LLC. We received approximately $20 million cash and recognized a pre-tax gain of approximately $1 million ($1 million
after-tax). The gain is included in gain on sale of assets, net on our consolidated statements of operations.



Canadian Assets.In August and November 2002, we sold significant portions of our Canadian crude oil and natural gas marketing businesses to
Seminole. The pre-tax loss on these sales was approximately $7 million.



Discontinued Operations



During 2002,
we sold our ownership interests in Northern Natural, our U.K. natural gas storage business and our global liquids business. In addition, as part of our restructuring plan, we sold or liquidated additional portions of our operations during 2003,
including our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144, as further described below.



Northern Natural. In November 2001, Dynegy acquired 1,000 shares of Northern Natural Series A Preferred Stock for $1.5 billion. We
concurrently acquired an option to purchase all of the equity of Northern Naturals indirect parent company. We exercised our option in November 2001 upon termination of a merger agreement with Enron, and closing of the option exercise occurred
on January 31, 2002.



Consideration paid for the 2002
business acquisition of Northern Natural was as follows (in millions):



|                       |  |   |      
|---------------------- |  | - | -----
|Cash purchase of stock |  | $ | 65   
|Liabilities assumed    |  |   | 1,070
|                       |  |   |      
|Total consideration    |  | $ | 1,135
|                       |  |   |      



On August 16, 2002, we
and Dynegy sold all of our investments in the common stock and preferred stock, respectively, of Northern Natural to MidAmerican for $879 million in cash, net of working capital adjustments. Under the terms of this agreement, MidAmerican acquired
all of the common and preferred stock of Northern Natural and assumed all of Northern Naturals $950 million of debt. Pursuant to the sales agreement, 95% of the purchase price was allocated to the preferred stock sold by Dynegy and 5% of the
purchase price was allocated to the common stock sold by us. We incurred a pre-tax loss in 2002 of $63 million ($45 million after-tax) associated with the sale, including adjustments for changes in working capital. Northern Naturals results of
operations are included as a discontinued operation in our consolidated statements of operations, as part of our Other segment.



For federal income tax purposes, the sale resulted in a capital loss, which may be deducted solely against capital gains, if any, realized by us in our
consolidated federal tax returns. There is a three-year carryback and a



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



five-year carryforward for capital losses under existing federal statutes. For financial reporting purposes, we recorded a valuation allowance against a
portion of the potential tax benefit because of uncertainty about our ability to generate future capital gains. Please see Note 13Income Taxes beginning on page F-40 for further information about our capital loss carryforwards and related
valuation allowance.



Pursuant to the sale agreement, we are
obligated to indemnify MidAmerican against any breaches of our representations and warranties contained therein. This indemnification obligation, which is capped at approximately $209 million, includes any potential tax liabilities we might have
assumed when we acquired Northern Natural from the Enron consolidated group.



On September 30, 2002, we sold $90 million in Northern Natural 6.875% senior notes due May 2005 for approximately $96 million, including accrued interest of $2 million. We acquired the notes at par value in April 2002
pursuant to a tender offer that it agreed to effect in order to obtain a bondholder consent in connection with the acquisition of Northern Natural. The gain on sale of approximately $4 million is reflected in other income and expense, net on the
accompanying 2002 consolidated statements of operations and is net of accrued interest.



U.K. Storage. On September 30, 2002, we sold a subsidiary that owned the Hornsea facility for net cash proceeds of approximately $189 million. There was no gain or loss recognized on this sale. On
November 14, 2002, we sold the subsidiaries that owned the Rough offshore natural gas field and the Easington natural gas processing terminal for cash proceeds of approximately $500 million. We recognized a pre-tax gain on the sale of Rough of
approximately $30 million ($5 million after-tax) in 2002.



Global Liquids. With our decision to exit the international LPG trading and transportation business, we sold our global liquids business in December 2002, which was included in our NGL segment, to Trammo Gas International
Inc., a wholly owned subsidiary of Transammonia Inc. We did not receive any cash consideration at close. We have the right to receive contingent payments in the future, which are capped at $8 million. We recorded pre-tax write-downs and accruals
totaling $27 million associated with this transaction in 2002, which is reflected in discontinued operations in the NGL segment.



Approximately $12 million of the $27 million charge noted above was our investment in EIOL. We had a 37.5% ownership interest in EIOL valued at $12
million that we accounted for using the equity method. We wrote down our investment in the EIOL project to zero at December 31, 2002 due to our expectation that we would receive no value or cash flows for our current investment in the project, and
our exit from the EIOL project was completed in 2003. The remaining 2002 charges associated with this disposition included the write-off of a logistics and accounting computer system not acquired by the purchaser and other related restructuring
costs.



U.K. CRM. We substantially completed our
exit from the U.K. CRM business during the first quarter 2003. For the year ended December 31, 2003, we recognized an after-tax loss of $21 million, primarily as a result of selling and terminating all of our U.K. gas and power positions, as well as
administrative expenses, depreciation and amortization, shut-down costs and currency translation losses. Collateral postings totaling $98 million were eliminated with the selling/terminations of these positions. We do not expect the U.K. CRM
business to have a material impact on our future results.



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



The following table summarizes information related to our discontinued operations:



|                                               |  |                 |     |   |             |   |         |  |   |               |   |  |       |     |   |  |   |       |  
|---------------------------------------------- |  | --------------- | --- | - | ----------- | - | ------- |  | - | ------------- | - |  | ----- | --- | - |  | - | ----- | -
|                                               |  | NorthernNatural |     |   | U.K.Storage |   | U.K.CRM |  |   | GlobalLiquids |   |  | Total |    
|2004                                           |  |                 |     |   |             |   |         |  |   |               |   |  |       |     |   |  |   |       |  
|Income (loss) from operations before taxes (1) |  | $               |    |   |             | $ |        |  | $ | 19            |   |  | $     | 1   |   |  | $ | 20    |  
|Income (loss) from operations after taxes      |  |                 |    |   |             |   |        |  |   | (7            | ) |  |       |    |   |  |   | (7    | )
|                                               |  |                 |     |   |            
|2003                                           |  |                 |     |   |             |   |         |  |   |               |   |  |       |     |   |  |   |       |  
|Revenue                                        |  | $               |    |   |             | $ |        |  | $ | 21            |   |  | $     |    |   |  | $ | 21    |  
|Loss from operations before taxes              |  |                 |    |   |             |   |        |  |   | (13           | ) |  |       | (2  | ) |  |   | (15   | )
|Loss from operations after taxes               |  |                 |    |   |             |   |        |  |   | (9            | ) |  |       | (2  | ) |  |   | (11   | )
|Gain (loss) on sale before taxes               |  |                 | (3  | ) |             |   | 1       |  |   |              |   |  |       |    |   |  |   | (2    | )
|Gain (loss) on sale after taxes                |  |                 | (2  | ) |             |   | 1       |  |   |              |   |  |       |    |   |  |   | (1    | )
|                                               |  |                 |     |   |            
|2002                                           |  |                 |     |   |             |   |         |  |   |               |   |  |       |     |   |  |   |       |  
|Revenue                                        |  | $               | 201 |   |             | $ | 140     |  | $ | 16            |   |  | $     | 784 |   |  | $ | 1,141 |  
|Income (loss) from operations before taxes     |  |                 | 38  |   |             |   | 34      |  |   | (115          | ) |  |       | (22 | ) |  |   | (65   | )
|Income (loss) from operations after taxes      |  |                 | 23  |   |             |   | 23      |  |   | (77           | ) |  |       | (19 | ) |  |   | (50   | )
|Gain (loss) on sale before taxes               |  |                 | (63 | ) |             |   | 30      |  |   |              |   |  |       | (15 | ) |  |   | (48   | )
|Gain (loss) on sale after taxes                |  |                 | (45 | ) |             |   | 5       |  |   |              |   |  |       | (10 | ) |  |   | (50   | )

---

|(1) | In the first quarter 2004, we recognized $17 million of pre-tax income related to translation gains on foreign currency in the U.K. Please see Note 5Risk Management Activities
and Financial InstrumentsAccounting for Derivative Instruments and Hedging ActivitiesNet Investment Hedges in Foreign Operations beginning on page F-27 for further discussion. In the second quarter 2004, we recognized a tax expense of
$20 million related to charges resulting from the conclusion of prior year tax audits. Please see Note 13Income Taxes beginning on page F-40 for further discussion.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Note 4Restructuring and Impairment Charges



In 2004, we recorded a $5 million pre-tax charge related to the impairment of one of our NGL assets. Also during 2004, we
recorded $85 million in pre-tax impairments of our investment in West Coast Power. For further discussion, please see Note 9Unconsolidated InvestmentsGEN Investments beginning on page F-31.



In 2003, we recorded a $16 million pre-tax charge related to the impairment
of some of our generation investments. For further discussion, please see Note 9Unconsolidated InvestmentsGEN Investments beginning on page F-31. Also, during 2003, we recorded a $12 million pre-tax charge related to the impairment of
our investment in GCF. For further discussion, please see Note 9Unconsolidated InvestmentsNGL Investments beginning on page F-32.



In 2002, we recorded a goodwill impairment relating to our GEN and CRM segments totaling $640 million. For further discussion, please see Note
10Goodwill beginning on page F-33.



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



In 2002, we recorded pre-tax restructuring and impairment charges of $392 million relating to various
aspects of our operations. The table below provides the amounts of these charges by business area and the caption in which they are included in our consolidated statements of operations:



|                                        |  |                                    |    |                            |   |                                                |  |       |     |                        |   |             |  |   |    |  |   |    
|--------------------------------------- |  | ---------------------------------- | -- | -------------------------- | - | ---------------------------------------------- |  | ----- | --- | ---------------------- | - | ----------- |  | - | -- |  | - | ---
|                                        |  | DepreciationandAmortizationExpense |    | Impairmentand OtherCharges |   | (Earnings)Losses fromUnconsolidatedInvestments |  | Other |     | DiscontinuedOperations |   | TotalCharge
|                                        |  | (in millions)                     
|Severance and other restructuring costs |  |                                    | 17 |                            |   | 134                                            |  |       |    |                        |   | 20          |  |   | 36 |  |   | 207
|Impairment of generation investments    |  |                                    |   |                            |   |                                               |  |       | 117 |                        |   |            |  |   |   |  |   | 117
|Impairment of technology investments    |  |                                    |   |                            |   |                                               |  |       | 16  |                        |   |            |  |   | 1  |  |   | 17 
|Impairment of other obsolete assets     |  |                                    |   |                            |   | 50                                             |  |       |    |                        |   |            |  |   | 1  |  |   | 51 
|                                        |  |                                    |    |                            |   |                                                |  |       |     |                        |   |             |  |   |    |  |   |    
|                                        |  | $                                  | 17 |                            | $ | 184                                            |  | $     | 133 |                        | $ | 20          |  | $ | 38 |  | $ | 392
|                                        |  |                                    |    |                            |   |                                                |  |       |     |                        |   |             |  |   |    |  |   |    



Severance and
Other Restructuring Costs.In the second quarter 2002, we recognized a $32 million pre-tax ($21 million after-tax) charge for severance benefits from a work force reduction that affected approximately 309 employees. In addition, in October
2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business. As part of this restructuring, which included a further work force reduction of approximately 780 employees, we
recognized a pre-tax charge of $175 million ($114 million after-tax) during the fourth quarter 2002. The total charge of $207 million ($135 million after-tax) is detailed below (in millions):



|                                           |  |   |    
|------------------------------------------ |  | - | ---
|Cancellation fees and operating leases     |  | $ | 58 
|Severance                                  |  |   | 106
|Asset impairments                          |  |   | 15 
|Change in estimated useful lives of assets |  |   | 28 
|                                           |  |   |    
|                                           |  | $ | 207
|                                           |  |   |    



In accordance with
EITF Issue 94-3, we recognized $58 million in charges ($38 million after-tax) during 2002 associated with cancellation fees and accruals for the termination of operating leases. These accruals are not discounted.



In addition, we recognized charges of $106 million ($69 million after-tax)
during 2002 for severance benefits for approximately 1,089 employees of various segments and all staffing levels, including our former chief executive officer, former president and former chief financial officer.



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Following is a schedule of 2004, 2003 and 2002 activity for the liabilities recorded associated with
the cancellation fees, operating leases and severance:



|                              |  |               |     |   |                                     |   |     |       |  |   |     |  
|----------------------------- |  | ------------- | --- | - | ----------------------------------- | - | --- | ----- |  | - | --- | -
|                              |  | Severance     |     |   | CancellationFees andOperatingLeases |   |     | Total | 
|                              |  | (in millions) |    
|Balance at December 31, 2001  |  | $             |    |   |                                     | $ |    |       |  | $ |    |  
|2002 charge                   |  |               | 106 |   |                                     |   | 58  |       |  |   | 164 |  
|2002 cash payments            |  |               | (40 | ) |                                     |   |    |       |  |   | (40 | )
|                              |  |               |     |   |                                     |   |     |       |  |   |     |  
|Balance at December 31, 2002  |  | $             | 66  |   |                                     | $ | 58  |       |  | $ | 124 |  
|2003 adjustments to liability |  |               | (8  | ) |                                     |   | 3   |       |  |   | (5  | )
|2003 cash payments            |  |               | (35 | ) |                                     |   | (34 | )     |  |   | (69 | )
|                              |  |               |     |   |                                     |   |     |       |  |   |     |  
|Balance at December 31, 2003  |  | $             | 23  |   |                                     | $ | 27  |       |  | $ | 50  |  
|2004 adjustments to liability |  |               | 18  |   |                                     |   | 7   |       |  |   | 25  |  
|2004 cash payments            |  |               | (38 | ) |                                     |   | (11 | )     |  |   | (49 | )
|                              |  |               |     |   |                                     |   |     |       |  |   |     |  
|Balance at December 31, 2004  |  | $             | 3   |   |                                     | $ | 23  |       |  | $ | 26  |  
|                              |  |               |     |   |                                     |   |     |       |  |   |     |  



During 2003, the
adjustment to the accrued liability primarily reflects reductions in the severance accrual for employees who will now be retained, as well as for employees of our foreign operations. In addition, we adjusted the liability for operating leases for
revised estimates of potential income from subleasing the leased facilities.



During 2004, the adjustment to the accrued liability primarily reflects increases in the severance accrual due to changes in our estimate of the probable loss associated with the severance claims of our former chief
executive officer and our former president. Cash payments during 2004 reflect payments made to our former chief executive officer and our former president. Please see Note 14Commitments and ContingenciesSummary of Material Legal
ProceedingsSeverance Arbitrations beginning on page F-49 for further discussion regarding the status of these claims and settlement payments.



We expect the $23 million accrual as of December 31, 2004 associated with cancellation fees and operating leases to be paid by the end of 2007 when the
leases expire.



Impairment losses of $15 million ($10 million
after-tax) were also incurred in accordance with SFAS No. 144 as a result of the corporate restructuring plan for certain technology assets no longer being utilized. The remaining $28 million ($18 million after-tax) of the charge represents
accelerated depreciation due to a change in the estimated useful life for leasehold improvements and technology assets related to the abandonment of those assets. This charge was included in depreciation and amortization expense, and $11 million was
subsequently reclassified to discontinued operations.



Impairment of Generation Investments.In conjunction with our review of the carrying value of goodwill in the third quarter 2002 (see Note 10Goodwill beginning on page F-33 for further discussion), we assessed the
carrying value of our generation portfolio on an asset-by-asset basis. The generation portfolio includes wholly-owned generating facilities, which are reflected in property, plant and equipment, as well as investments in partnerships and limited
liability companies that own generating facilities, which are reflected in unconsolidated investments. Based on this review, the carrying value associated with the wholly-owned generation facilities was considered realizable. However, some
unconsolidated investments were considered impaired, resulting in a pre-tax charge of $117 million, which is reflected in earnings (losses) from unconsolidated investments on the consolidated statements of operations. The diminution in the fair
value of these investments was primarily a result of depressed energy prices.



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Impairment of Technology Investments.During the second quarter 2002, we recognized an
impairment charge associated with certain technology investments. The $10 million pre-tax ($7 million after-tax) charge was recorded in earnings (losses) from unconsolidated investments, and $1 million of the charge ($1 million after-tax) was
subsequently reclassified to discontinued operations.



These
investments were re-evaluated at September 30, 2002 based on our inability to sell certain investments for their adjusted carrying values and the continued depressed conditions in the technology sector. Based on this assessment, the remaining
carrying value of these investments was written-off, resulting in a pre-tax charge of $7 million ($4 million after-tax), which was recorded in earnings (losses) from unconsolidated investments. The cumulative pre-tax charge related to technology
investments for the year ended December 31, 2002 was $17 million ($11 million after-tax), of which $1 million was subsequently reclassified to discontinued operations.



Impairment of Other Obsolete Assets.As a result of our decision to exit the CRM business, our investment in
Dynegydirect was written off in the third quarter 2002, resulting in a pre-tax charge of $25 million ($16 million after-tax). The charge was recorded in impairment and other charges in the consolidated statements of operations.



In the fourth quarter 2002, we also recognized a $14 million
($9 million after-tax) charge associated with the impairment of a generation turbine, as its fair value calculated in accordance with SFAS No. 144 was less than its carrying value. The charge was recorded in impairment and other charges in the
consolidated statements of operations.



We recognized a pre-tax
charge of $12 million ($8 million after-tax) in the second quarter 2002 related to the retirement of partially depreciated information technology equipment and software replaced during the quarter with new system applications and arrangements as
well as miscellaneous deposits that are not expected to provide future value. The equipment and software was replaced during the second quarter 2002 with new system applications and arrangements. The charge was recorded in impairment and other
charges, and $1 million of the charge ($1 million after-tax) was subsequently reclassified to discontinued operations.



Note 5Risk Management Activities and Financial Instruments



Our operations are impacted by several factors, some of which may not be mitigated by risk management methods. These risks include, but are not limited
to, commodity price, interest rate and foreign exchange rate fluctuations, weather patterns, counterparty credit risks, changes in competition, operational risks, environmental risks and changes in regulations.



We define market risk as changes to our earnings and cash flow resulting from
changes in market conditions, including changes in commodity prices, interest rates and currency rates as well as the impact of volatility and market liquidity on such prices. We seek to manage market risk through diversification, controlling
position sizes and executing hedging strategies.



Accounting for Derivative Instruments and Hedging Activities



We follow the accounting and disclosure requirements of SFAS No. 133, as amended. Under SFAS No. 133, all derivative instruments are recognized in the balance sheet at their fair values and changes in fair value
are recognized immediately in earnings, unless such instruments qualify, and are designated, as hedges of future cash flows, fair values or net investments in foreign operations or qualify, and are designated, as normal purchases and sales. We
distinguish between these hedges, which are further described below, as follows:



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



| |  |  | Cash flow hedges. Under these derivatives, the effective portion of changes in fair value is recorded as a component of accumulated other comprehensive income (loss)
until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is reported immediately as a component of other income and expense, net in the consolidated statements of operations.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Fair value hedges.Under these derivatives, changes in the fair value of the derivative and changes in the fair value of the related asset or liability are recorded in
current period earnings.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Net investments in foreign operations. Under these derivatives, the effective portion of changes in the fair value of the derivative is recorded in the foreign
currency translation adjustment, a component of accumulated other comprehensive loss. Any ineffective portion is reported immediately as a component of other income and expense, net in the consolidated statements of operations.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Cash Flow Hedges. We enter into
financial derivative instruments that qualify as cash flow hedges. The maximum length of time for which we hedge our exposure for cash flow hedges is through 2006. Instruments related to our GEN and NGL businesses are entered into for purposes of
hedging future fuel requirements and sales commitments and locking in future margin. Interest rate swaps were previously used to convert the floating interest-rate component of some obligations to fixed rates.



During the year ended December 31, 2004, we recorded a $3 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 years ended December 31, 2003 and 2002, there was
no material ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the years ended December 31, 2004, 2003 and 2002, we
recorded charges of zero, less than $1 million and zero, respectively, related to the reclassification of earnings in connection with forecasted transactions that were no longer considered probable of occurring.



The balance in cash flow hedging activities, net at December 31, 2004 is
expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity or natural gas liquids and payments of interest, as applicable to each type of hedge. Of this amount, after-tax losses of
approximately $20 million are currently estimated to be reclassified into earnings over the 12-month period ending December 31, 2005. 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. The maximum length of time for which we hedge our exposure for fair value hedges is through 2012. We use
interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into variable-rate debt. During the years ended December 31, 2004, 2003 and 2002, there was no ineffectiveness from changes in the fair value of hedge positions and no
amounts were excluded from the assessment of hedge effectiveness. During the years ended December 31, 2004, 2003 and 2002, we recorded gains of zero, $6 million and zero, respectively, related to the recognition of firm commitments that no longer
qualified as fair value hedges.



Net Investment Hedges in
Foreign Operations. Although we have exited a substantial amount of our foreign operations, we continue to have investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. In the past, we
used derivative financial instruments, including foreign exchange forward contracts and cross-currency interest rate swaps, to hedge this exposure. As of December 31, 2004 and 2003, we had no net investment hedges in place.



F-27



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



During the year ended December 31, 2003, our efforts to exit the U.K. CRM business and the European
communications business were substantially completed. As required by SFAS No. 52, Foreign Currency Translation, a significant portion of unrealized gains and losses resulting from translation and financial instruments utilized to hedge
currency exposures previously recorded in stockholders equity were recognized in income, resulting in an after-tax loss of approximately $5 million. During the first quarter 2004, we repatriated a majority of our cash from the U.K. by
repayment of intercompany loans, resulting in the substantial liquidation of our investment in the U.K. As such, we recognized approximately $17 million of pre-tax translation gains in income that arose since April 1, 2003 and had accumulated in
stockholders equity.



Accumulated Other
Comprehensive Income (Loss).Accumulated other comprehensive income (loss), net of tax, is included in stockholders equity on the consolidated balance sheets as follows:



|                                                          |  |               |     |   |      |   |    |  
|--------------------------------------------------------- |  | ------------- | --- | - | ---- | - | -- | -
|                                                          |  | December 31,  |    
|                                                          |  | 2004          |     |   | 2003 |  
|                                                          |  | (in millions) |    
|Cash flow hedging activities, net                         |  | $             | (16 | ) |      | $ | 10 |  
|Foreign currency translation adjustment                   |  |               | 16  |   |      |   | 26 |  
|Minimum pension liability                                 |  |               | (13 | ) |      |   | (3 | )
|                                                          |  |               |     |   |      |   |    |  
|Accumulated other comprehensive income (loss), net of tax |  | $             | (13 | ) |      | $ | 33 |  
|                                                          |  |               |     |   |      |   |    |  



Notional
Contract Amounts. The absolute notional contract amounts associated with the derivative instruments designated as hedges were as follows:



|                                                                   |  |              |       |      |   |      
|------------------------------------------------------------------ |  | ------------ | ----- | ---- | - | -----
|                                                                   |  | December 31,
|                                                                   |  | 2004         |       | 2003
|Fair Value Hedge Interest Rate Swaps (in Millions of U.S. Dollars) |  | $            | 525   |      | $ | 25   
|Fixed Interest Rate Received on Swaps (Percent)                    |  |              | 4.331 |      |   | 5.706
|Cash Flow Hedge Interest Rate Swaps (in Millions of U.S. Dollars)  |  | $            |      |      | $ | 405  
|Fixed Interest Rate Paid on Swaps (Percent)                        |  |              |      |      |   | 3.448
|Natural Gas Cash Flow Hedges (Trillion Cubic Feet)                 |  |              | 0.023 |      |   | 0.073
|Electricity Cash Flow Hedges (Million Megawatt Hours)              |  |              | 7.244 |      |   | 3.651
|Fuel Oil Cash Flow Hedges (Million Barrels)                        |  |              | 1.025 |      |   | 0.825



Fair Value of
Financial Instruments.The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, Disclosures About Fair Value of Financial Instruments. We have
determined the estimated fair-value amounts using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market
assumptions or valuation methodologies could have a material effect on the estimated fair-value amounts.





F-28



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



The carrying values of current financial assets and liabilities approximate fair values due to the
short-term maturities of these instruments. The carrying amounts and fair values of debt are included in Note 11Debt beginning on page F-34. The carrying amounts and fair values of our other financial instruments were:



|                                        |  |                |     |   |           |   |     |                |  |   |           |   |  |   |     |  
|--------------------------------------- |  | -------------- | --- | - | --------- | - | --- | -------------- |  | - | --------- | - |  | - | --- | -
|                                        |  | December 31,   |    
|                                        |  | 2004           |     |   | 2003      |  
|                                        |  | CarryingAmount |     |   | FairValue |   |     | CarryingAmount |  |   | FairValue |  
|                                        |  | (in millions)  |    
|Fair Value Hedge Interest Rate Swap     |  | $              | 5   |   |           | $ | 5   |                |  | $ | 3         |   |  | $ | 3   |  
|Cash Flow Hedge Interest Rate Swap      |  |                |    |   |           |   |    |                |  |   | (3        | ) |  |   | (3  | )
|Interest Rate Risk-Management Contracts |  |                | (3  | ) |           |   | (3  | )              |  |   | (4        | ) |  |   | (4  | )
|Commodity Cash Flow Hedge Contracts     |  |                | (8  | ) |           |   | (8  | )              |  |   | 17        |   |  |   | 17  |  
|Commodity Risk-Management Contracts     |  |                | (86 | ) |           |   | (86 | )              |  |   | (86       | ) |  |   | (86 | )



The fair value of
interest rate and commodity risk-management contracts were based upon the estimated consideration that would be received to terminate those contracts in a gain position and the estimated cost that would be incurred to terminate those contracts in a
loss position.



Note 6Cash Flow Information



Following are supplemental disclosures of cash flow and non-cash investing
and financing information:



|                                                    |  |                         |     |      |   |     |      |  |   |        |  
|--------------------------------------------------- |  | ----------------------- | --- | ---- | - | --- | ---- |  | - | ------ | -
|                                                    |  | Year Ended December 31, |    
|                                                    |  | 2004                    |     | 2003 |   |     | 2002 | 
|                                                    |  | (in millions)           |    
|Interest paid (net of amount capitalized)           |  | $                       | 319 |      | $ | 180 |      |  | $ | 182    |  
|                                                    |  |                         |     |      |   |     |      |  |   |        |  
|Taxes paid (refunds), net                           |  | $                       | 4   |      | $ | (91 | )    |  | $ | 8      |  
|                                                    |  |                         |     |      |   |     |      |  |   |        |  
|Detail of business acquired (1):                    |  |                         |     |      |   |     |      |  |   |        |  
|Current assets and other                            |  | $                       |    |      | $ |    |      |  | $ | 144    |  
|Fair value of non-current assets                    |  |                         |    |      |   |    |      |  |   | 990    |  
|Liabilities assumed, including deferred taxes       |  |                         |    |      |   |    |      |  |   | (1,070 | )
|Cash balance acquired                               |  |                         |    |      |   |    |      |  |   | (44    | )
|                                                    |  |                         |     |      |   |     |      |  |   |        |  
|Cash paid, net of cash acquired                     |  | $                       |    |      | $ |    |      |  | $ | 20     |  
|                                                    |  |                         |     |      |   |     |      |  |   |        |  
|Other non-cash investing and financing activity:    |  |                         |     |      |   |     |      |  |   |        |  
|Addition of a capital lease                         |  | $                       |    |      | $ | 66  |      |  | $ | 170    |  
|Sale of West Texas LPG Pipeline Limited Partnership |  |                         |    |      |   |    |      |  |   | 45     |  

---

|(1) | The business acquired in 2002 was Northern Natural. Please read Note 3Dispositions, Contract Terminations and Discontinued OperationsDiscontinued
OperationsNorthern Natural beginning on page F-21 for more information regarding this acquisition.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





F-29



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 7Inventory



A summary of our inventories is as follows:



|                       |  |               |     |      |   |    
|---------------------- |  | ------------- | --- | ---- | - | ---
|                       |  | December 31, 
|                       |  | 2004          |     | 2003
|                       |  | (in millions)
|Natural gas in storage |  | $             |    |      | $ | 5  
|Natural gas liquids    |  |               | 60  |      |   | 40 
|Coal                   |  |               | 49  |      |   | 37 
|Fuel oil               |  |               | 14  |      |   | 16 
|Emission Allowances    |  |               | 27  |      |   | 11 
|Materials and supplies |  |               | 83  |      |   | 85 
|                       |  |               |     |      |   |    
|                       |  | $             | 233 |      | $ | 194
|                       |  |               |     |      |   |    



Note 8Property, Plant and
Equipment



A summary of our property, plant and equipment
is as follows:



|                                       |  |               |        |   |      |   |        |  
|-------------------------------------- |  | ------------- | ------ | - | ---- | - | ------ | -
|                                       |  | December 31,  |       
|                                       |  | 2004          |        |   | 2003 |  
|                                       |  | (in millions) |       
|Generation assets                      |  | $             | 5,838  |   |      | $ | 5,729  |  
|Natural gas liquids assets:            |  |               |        |   |      |   |        |  
|Natural gas processing                 |  |               | 1,058  |   |      |   | 1,067  |  
|Fractionation                          |  |               | 230    |   |      |   | 231    |  
|Liquids marketing                      |  |               | 30     |   |      |   | 22     |  
|Natural gas gathering and transmission |  |               | 115    |   |      |   | 98     |  
|Terminals and storage                  |  |               | 301    |   |      |   | 307    |  
|Barges                                 |  |               | 29     |   |      |   | 29     |  
|IT systems and other                   |  |               | 221    |   |      |   | 208    |  
|                                       |  |               |        |   |      |   |        |  
|                                       |  |               | 7,822  |   |      |   | 7,691  |  
|Accumulated depreciation               |  |               | (1,692 | ) |      |   | (1,389 | )
|                                       |  |               |        |   |      |   |        |  
|                                       |  | $             | 6,130  |   |      | $ | 6,302  |  
|                                       |  |               |        |   |      |   |        |  



Interest capitalized
related to costs of projects in process of development totaled $2 million, $11 million and $15 million for the years ended December 31, 2004, 2003 and 2002, respectively.



Note 9Unconsolidated Investments



Our unconsolidated investments consist primarily of investments in affiliates that we do not control, but where we have significant influence over
operations. Our principal equity method investments consist of entities that operate generation and natural gas liquids assets. We entered into these ventures principally to share risk and leverage existing commercial relationships. These ventures
maintain independent capital structures and have financed their operations either on a non-recourse basis to us or through their ongoing commercial activities. We hold investments in joint ventures in which ChevronTexaco or its affiliates are
investors. For additional information about these investments, please read Note 12Related Party Transactions beginning on page F-38.





F-30



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



A summary of our unconsolidated investments is as follows:



|                                 |  |               |     |      |   |    
|-------------------------------- |  | ------------- | --- | ---- | - | ---
|                                 |  | December 31, 
|                                 |  | 2004          |     | 2003
|                                 |  | (in millions)
|Equity affiliates:               |  |               |     |      |   |    
|GEN investments                  |  | $             | 336 |      | $ | 495
|NGL investments                  |  |               | 78  |      |   | 82 
|                                 |  |               |     |      |   |    
|Total unconsolidated investments |  | $             | 414 |      | $ | 577
|                                 |  |               |     |      |   |    



Cash distributions
received from our equity investments during 2004, 2003 and 2002 were $137 million, $155 million and $77 million, respectively. Our investment balances include unamortized purchase price differences of $7 million and $61 million at December 31, 2004
and 2003, respectively. The unamortized purchase price differences represent the excess of our purchase price over our share of the investees book value at the time of acquisition. Undistributed earnings from our equity investments included in
accumulated deficit at December 31, 2004 and 2003 totaled $187 million and $144 million, respectively.



GEN Investments. Generation investments at December 31, 2004, include ownership interests in four joint ventures that own fossil fuel
electric generation facilities. Our ownership is 50% in the majority of these ventures. Our aggregate net investment of $336 million at December 31, 2004 represents approximately 1,010 MWs of net generating capacity.



Our most significant investment in generating capacity is our interest in
West Coast Power, representing approximately 945 MWs of net generating capacity in California. Our net investment in West Coast Power totaled approximately $262 million and $291 million at December 31, 2004 and December 31, 2003, respectively. West
Coast Power provided equity earnings of approximately $153 million, $117 million and $17 million in the years ended December 31, 2004, 2003 and 2002, respectively. Our West Coast Power related earnings for 2004 include a $12 million charge
representing our share of an asset impairment. Earnings from unconsolidated investments for 2004 also include an impairment of $73 million on our investment in West Coast Power, primarily due to the expiration of the CDWR contract in December 2004.
Our West Coast Power related earnings for 2003 include a $20 million charge representing our share of a goodwill impairment. Our West Coast Power related earnings for 2002 include an impairment charge of $33 million to write down our investment to
fair value, as well as a $50 million charge representing our share of a bad debt allowance. A significant amount of West Coast Powers historical earnings related to the CDWR contract, which expired at the end of 2004.



Summarized financial information for West Coast Power, and our equity share
thereof, was:



|                        |  |               |     |             |   |       |  |             |     |       |   |             |  |   |     |  |   |    
|----------------------- |  | ------------- | --- | ----------- | - | ----- |  | ----------- | --- | ----- | - | ----------- |  | - | --- |  | - | ---
|                        |  | December 31, 
|                        |  | 2004          |     | 2003        |   | 2002 
|                        |  | Total         |     | EquityShare |   | Total |  | EquityShare |     | Total |   | EquityShare
|                        |  | (in millions)
|Current assets          |  | $             | 429 |             | $ | 215   |  | $           | 257 |       | $ | 129         |  | $ | 255 |  | $ | 128
|Non-current assets      |  |               | 394 |             |   | 197   |  |             | 454 |       |   | 227         |  |   | 532 |  |   | 266
|Current liabilities     |  |               | 82  |             |   | 41    |  |             | 55  |       |   | 28          |  |   | 112 |  |   | 56 
|Non-current liabilities |  |               | 5   |             |   | 3     |  |             | 8   |       |   | 4           |  |   | 34  |  |   | 17 
|Revenues                |  |               | 726 |             |   | 363   |  |             | 696 |       |   | 348         |  |   | 585 |  |   | 293
|Operating income        |  |               | 304 |             |   | 152   |  |             | 231 |       |   | 116         |  |   | 48  |  |   | 24 
|Net income              |  |               | 306 |             |   | 153   |  |             | 233 |       |   | 117         |  |   | 34  |  |   | 17 



Based on their
significance, West Coast Powers audited consolidated financial statements are included herein beginning on page F-75.



F-31



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



In the fourth quarter 2004, we sold our unconsolidated investment in the Commonwealth generating
facility. We did not recognize a material gain or loss on this sale.



In the third quarter 2004, we sold our unconsolidated investments in the Oyster Creek, Michigan Power and Hartwell generating facilities for aggregate net cash proceeds of approximately $132 million. We recognized gains of $15 million and
$2 million related to our sales of Oyster Creek and Hartwell, but did not recognize any gain or loss on the sale of Michigan Power. However, during the year ended December 31, 2004, we recorded an impairment on our investment in Michigan Power
totaling $8 million, to adjust our book value to the sale price.



In the fourth quarter 2003, we evaluated our domestic interests in several power generation entities. We conducted this evaluation, which was required by GAAP, because of a surplus of both international and domestic investments being
actively marketed for sale and a continued, sustained downturn in the independent power producer market. Through our evaluation, we determined that several of these equity investments experienced circumstances and events that indicated that the book
value of our investment was no longer recoverable and that such decline in value was other than temporary. For some of our investments, we have entered into active discussions with either the owner of the entity or a third party, who, in some cases,
has conducted extensive due diligence on the investment to determine an appropriate bid price. We believe that a bid price, or an external valuation, is the best determinant of fair value for these investments, if available. For other investments,
we prepared internal valuation models to determine the fair value. After comparing the fair values of each of our investments to their book value, we recorded a pre-tax impairment charge of $16 million ($10 million after-tax) and included this
charge in earnings (losses) from unconsolidated investments. The ultimate sale of these investments may result in additional charges.



For the year ended December 31, 2003, we derived 11% of our consolidated revenues from transactions with West Coast Power. No other customer accounted for
more than 10% of our consolidated revenues or consolidated cost of sales during 2004, 2003 or 2002.



In addition to the charges related to our investment in West Coast Power described above, equity earnings during 2002 were negatively impacted by a
pre-tax impairment of $84 million (net of the $33 million West Coast Power impairment) in multiple equity investments based on a fair value assessment, as further discussed in Note 4Restructuring and Impairment Charges beginning on page
F-23.



NGL Investments. At December 31, 2004,
natural gas liquids investments included a 22.9% ownership interest in Venice Energy Services Company, L.L.C. (VESCO), a venture that operates a natural gas liquids processing, extraction, fractionation and storage facility in the Gulf Coast region
as well as a 38.75% ownership interest in GCF, a venture that fractionates natural gas liquids on the Gulf Coast. In August 2002, we sold our investment in WTLPS to ChevronTexaco. Please read Note 12Related Party Transactions beginning on page
F-38 for further discussion of this transaction.



During the
fourth quarter 2003, we determined that the fair value of our minority interest in GCF, based on bid prices received for a possible sale of the investment, was lower than the book value. As such, we recorded a pre-tax impairment charge in the fourth
quarter of 2003 of $12 million ($8 million after-tax) and included this charge in earnings (losses) from unconsolidated investments.





F-32



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Summarized Information. Summarized aggregate financial information for unconsolidated
equity investments, exclusive of the West Coast Power information included above, and our equity share thereof was:



|                        |  |               |     |             |   |       |  |             |       |       |   |             |  |   |       |  |   |    
|----------------------- |  | ------------- | --- | ----------- | - | ----- |  | ----------- | ----- | ----- | - | ----------- |  | - | ----- |  | - | ---
|                        |  | December 31, 
|                        |  | 2004          |     | 2003        |   | 2002 
|                        |  | Total         |     | EquityShare |   | Total |  | EquityShare |       | Total |   | EquityShare
|                        |  | (in millions)
|Current assets          |  | $             | 146 |             | $ | 51    |  | $           | 218   |       | $ | 92          |  | $ | 429   |  | $ | 154
|Non-current assets      |  |               | 134 |             |   | 67    |  |             | 1,210 |       |   | 543         |  |   | 1,195 |  |   | 532
|Current liabilities     |  |               | 86  |             |   | 25    |  |             | 153   |       |   | 64          |  |   | 314   |  |   | 127
|Non-current liabilities |  |               | 56  |             |   | 26    |  |             | 528   |       |   | 263         |  |   | 568   |  |   | 284
|Revenues                |  |               | 500 |             |   | 194   |  |             | 1,190 |       |   | 463         |  |   | 2,247 |  |   | 886
|Operating income        |  |               | 113 |             |   | 48    |  |             | 176   |       |   | 75          |  |   | 203   |  |   | 82 
|Net income              |  |               | 90  |             |   | 37    |  |             | 120   |       |   | 45          |  |   | 153   |  |   | 56 



Earnings from
unconsolidated investments of $126 million for the year ended December 31, 2004 include the $37 million above, $153 million from West Coast Power and gains on the sales of our equity investment in Oyster Creek and our equity investment in Hartwell
of $15 million and $2 million, respectively. These gains were partially offset by a $73 million impairment of our investment in West Coast Power and an $8 million impairment of our Michigan Power equity investment.



Earnings from unconsolidated investments of $132 million for the year ended
December 31, 2003 includes the $45 million above and $117 million from West Coast Power, offset by $30 million in impairments of investments.



Losses from unconsolidated investments of $54 million for the year ended December 31, 2002 consist primarily of the $56 million above and $17 million from
West Coast Power, offset by impairments of generation and technology investments of $117 million and $17 million, respectively (see Note 4Restructuring and Impairment ChargesImpairment of Generation Investments beginning on page F-25 and
Note 4 Restructuring and Impairment ChargesImpairment of Technology Investments beginning on page F-26).



Other Investments. We previously owned securities that had a readily determinable fair market value and were considered available-for-sale.
During 2002, we wrote down the remaining values of our available-for-sale securities. For further discussion, please see Note 4Restructuring and Impairment Charges beginning on page F-23. The market value of these investments at December 31,
2004 and 2003 was estimated to be zero.



Note 10Goodwill



There were no changes in the carrying amount of goodwill,
which is entirely comprised of $15 million in our NGL segment, during 2004 or 2003. Significant components of changes in goodwill during 2002 included the following.



We adopted SFAS No. 142 effective January 1, 2002, and, accordingly, tested for impairment all amounts recorded as goodwill.
We determined that no goodwill was impaired. The fair value of our reporting units was estimated using the expected discounted future cash flows.



During 2002, the value of goodwill associated with our former WEN segment was determined to be impaired, resulting in our recognizing a charge of $640
million. The fair values of the respective components of this segment were estimated utilizing the expected discounted future cash flows. The primary factors leading to this impairment were: (1) the reduction in near-term power prices; (2) an
increase in the rate of return required



F-33



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



for investors to enter the energy merchant sector; and (3) our decision to exit third-party risk management aspects of the marketing and trading business.
The impairment charge is reflected in the consolidated statements of operations as a goodwill impairment.



Also in 2002, $887 million of goodwill associated with the acquisition of Northern Natural was recorded in the Other segment and subsequently removed when
Northern Natural was sold. See Note 3Dispositions, Contract Terminations and Discontinued OperationsDiscontinued OperationsNorthern Natural beginning on page F-21 for additional discussion of the sale of Northern Natural.



Of the $640 million goodwill impairment recognized in 2002,
$405 million related to goodwill for which there was no tax basis, and thus that portion of the impairment was the same on a pre-tax or an after-tax basis. The remaining impairment of the $235 million was $146 million on an after-tax basis.



Note 11Debt



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



|                                                                                        |  |                |       |           |   |                |  |           |       |  |   |      
|--------------------------------------------------------------------------------------- |  | -------------- | ----- | --------- | - | -------------- |  | --------- | ----- |  | - | -----
|                                                                                        |  | December 31,  
|                                                                                        |  | 2004           |       | 2003     
|                                                                                        |  | CarryingAmount |       | FairValue |   | CarryingAmount |  | FairValue
|                                                                                        |  | (in millions) 
|Dynegy Holdings Inc.                                                                    |  |                |       |           |   |                |  |           |       |  |   |      
|Term Loan, floating rate due through 2010                                               |  | $              | 597   |           | $ | 604            |  | $         |      |  | $ |     
|Senior Notes, 8.125% due 2005                                                           |  |                | 18    |           |   | 18             |  |           | 18    |  |   | 18   
|Senior Notes, 7.45% due 2006                                                            |  |                | 22    |           |   | 23             |  |           | 22    |  |   | 24   
|Senior Notes, 6.875% due 2011                                                           |  |                | 512   |           |   | 480            |  |           | 519   |  |   | 455  
|Senior Notes, 8.75% due 2012                                                            |  |                | 501   |           |   | 522            |  |           | 500   |  |   | 501  
|Senior Debentures, 7.125% due 2018                                                      |  |                | 176   |           |   | 154            |  |           | 179   |  |   | 147  
|Senior Debentures, 7.625% due 2026                                                      |  |                | 177   |           |   | 150            |  |           | 181   |  |   | 147  
|Second Priority Senior Secured Notes, floating rate due 2008                            |  |                | 225   |           |   | 247            |  |           | 225   |  |   | 225  
|Second Priority Senior Secured Notes, 9.875% due 2010                                   |  |                | 625   |           |   | 698            |  |           | 625   |  |   | 705  
|Second Priority Senior Secured Notes, 10.125% due 2013                                  |  |                | 900   |           |   | 1,028          |  |           | 900   |  |   | 1,035
|Subordinated Debentures payable to affiliates, 8.316%, due 2027                         |  |                | 200   |           |   | 165            |  |           | 200   |  |   | 164  
|ABG Gas Supply Credit Agreement, due through 2006                                       |  |                |      |           |   |               |  |           | 185   |  |   | 185  
|Tilton capital lease payable to affiliates                                              |  |                |      |           |   |               |  |           | 71    |  |   | 71   
|Generation Facility Debt, due 2007                                                      |  |                | 183   |           |   | 183            |  |           | 184   |  |   | 184  
|                                                                                        |  |                |       |           |   |                |  |           |       |  |   |      
|                                                                                        |  |                | 4,136 |           |   |                |  |           | 3,809 |  |   |      
|Unamortized premium on debt, net                                                        |  |                | 5     |           |   |                |  |           | 5     |  |   |      
|                                                                                        |  |                |       |           |   |                |  |           |       |  |   |      
|                                                                                        |  |                | 4,141 |           |   |                |  |           | 3,814 |  |   |      
|Less: Amounts due within one year, including non-cash amortization of basis adjustments |  |                | 34    |           |   |                |  |           | 150   |  |   |      
|                                                                                        |  |                |       |           |   |                |  |           |       |  |   |      
|Total Long-Term Debt                                                                    |  | $              | 4,107 |           |   |                |  | $         | 3,664 |  |   |      
|                                                                                        |  |                |       |           |   |                |  |           |       |  |   |      



Aggregate maturities
of the principal amounts of all long-term indebtedness for the next five years and beyond are as follows: 2005$34 million; 2006$28 million; 2007$188 million (Excludes $700 million secured revolving credit facility, which matures on
May 28, 2007 and under which, as of December 31, 2004, there were no borrowings and $94 million letters of credit outstanding.); 2008$231 million; 2009$6 million; and thereafter$3,654 million.



Term Loan and Credit Facility. Effective May 28, 2004, we
entered into a $1.3 billion credit facility consisting of:



| |  |  | a $700 million secured revolving credit facility that matures on May 28, 2007; and
| | - |  | ----------------------------------------------------------------------------------



| |  |  | a $600 million secured amortizing term loan that matures on May 28, 2010.
| | - |  | -------------------------------------------------------------------------



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



The credit facility replaced our $1.1 billion revolving credit facility, which was scheduled to
mature in February 2005.



The revolving credit facility
provides funding for general corporate purposes and is also available for the issuance of letters of credit. Borrowings under the revolving credit facility bear interest, at our option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus
4.00% per annum. A letter of credit fee is payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.00% of such undrawn amount. We also incur additional fees for issuing letters of credit. An unused
commitment fee of 0.50% is payable on the unused portion of the revolving credit facility.



During the year ended December 31, 2004, we reduced letters of credit under our revolving credit facilities by an aggregate amount of approximately $94
million, resulting in a total of $94 million outstanding at December 31, 2004. As of December 31, 2004, there were no borrowings outstanding under our $700 million revolving credit facility. During the period from December 31,2004 through
March 11, 2005, we reduced our outstanding letters of credit under this facility by $5 million.



Of the $600 million in proceeds from the term loan drawn at closing, a portion was used to post cash collateral in lieu of letters of credit, while
approximately $19 million was used to pay fees and expenses incurred in connection with the new facility. These fees have been capitalized and are being amortized over the terms of the credit facility. In August 2004, $154 million of the proceeds
from the $600 million term loan were used to pre-pay all outstanding indebtedness and other amounts owed in connection with the ABG Gas Supply financing. The remaining proceeds, subject to specified restrictions in the credit facility, are available
for general corporate purposes. Borrowings under the term loan bear interest, at our option, at (i) a base rate plus 3.00% per annum or (ii) LIBOR plus 4.00% per annum.



The credit facility contains mandatory prepayment events associated with specified asset sales and recovery events (i.e.,
certain payments in respect of insurance claims or condemnation proceedings). We must offer to repay the term loan or permanently reduce the revolving credit facility with 100% of the net cash proceeds of all asset sales or any proceeds from
recovery events, excluding (i) proceeds from sales of designated assets; (ii) up to $100 million of net cash proceeds from other asset sales as designated by us; and (iii) up to $900 million of proceeds from asset sales and recovery events that are
reinvested in the business, subject to specified restrictions. Sales of assets over a specified threshold require written confirmation from both Standard & Poors Ratings Service and Moodys Investors Service that the credit ratings of
the credit facility will not be lowered as a result. Further, any sale of our Baldwin facility or all or substantially all of our NGL assets would require the written consent of a majority of the lenders under the credit facility.



The credit facility provides for no amortization of principal prior to the
maturity dates except (i) upon the occurrence of a mandatory prepayment event and (ii) term loan amortization of 1% per annum.



The credit facility is secured by substantially the same collateral as the $1.1 billion facility it replaced, including a first priority interest in
substantially all our assets and the assets of our subsidiaries and on substantially all of the equity of our subsidiaries in each case to the extent permitted by other applicable agreements. Dynegy and substantially all of its subsidiaries also
guarantee this facility.



The credit facility contains
affirmative and negative covenants, including negative covenants relating to the following which restrict us and our subsidiaries but do not restrict Dynegy: liens; investments; indebtedness; dispositions; restricted payments; burdensome agreements;
amendments to organizational documents; prepayments of indebtedness; and swap contracts. The credit facility also contains the financial and capital expenditure-related covenants described below.



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



The credit facility generally prohibits us and our subsidiaries, subject to specified exceptions,
from incurring additional debt. Notwithstanding this restriction, we may issue, to the extent permitted by the more restrictive covenants in the indenture governing our second priority senior secured notes, (i) up to $700 million of additional
second lien or junior secured debt or unsecured debt, provided such additional debt matures at least six months after the term loan, and (ii) permitted refinancing indebtedness.



The credit facility generally prohibits us and our subsidiaries from pre-paying, redeeming or repurchasing our outstanding
debt or preferred stock. Notwithstanding this restriction, we may pre-pay, repurchase or redeem our remaining 2005 and 2006 senior notes and the Generation facility debt. We also may pre-pay, repurchase or redeem its other senior unsecured notes and
its second priority senior secured notes, subject to specified conditions.



Dynegy and its subsidiaries are also prohibited from (i) permitting the Secured Debt/EBITDA Ratio (as defined in the credit facility) on and after September 30, 2004 to exceed specified ratios; (ii) permitting
liquidity to be less than $200 million for a period of more than ten consecutive business days; or (iii) making capital expenditures during each four fiscal quarter period in excess of a designated amount, subject to specified exceptions.



The terms and conditions of the credit facility are described
in more detail in the definitive agreements governing the credit facility, which are incorporated by reference as exhibits to our second quarter 2004 Form 10-Q.



Senior Notes.The notes are unsecured and are not subject to a sinking fund.



Second Priority Senior Secured Notes. In August 2003, we issued
$1.45 billion in second priority senior secured notes, comprised of: (i) $225 million in floating rate notes due 2008 which accrue interest at a rate of LIBOR plus 650 basis points (reset on a quarterly basis); (ii) $525 million in 9.875% notes due
2010 with a yield to maturity of 10.0%; and (iii) $700 million in 10.125% notes due 2013 with a yield to maturity of 10.25%.



In October 2003, we consummated a follow-on offering of $300 million aggregate principal amount of additional second priority senior secured notes,
comprised of: (i) $100 million of 9.875% second priority senior secured notes due 2010 issued at a premium to par of 104.25% with a yield to maturity of approximately 9.0%; and (ii) $200 million of 10.125% second priority senior secured notes due
2013 issued at a premium to par of 105.25% with a yield to maturity of approximately 9.3%. Each of these series of additional notes are treated as a single class with the corresponding series of our second priority senior secured notes that were
originally issued in August 2003.



Each of our existing and
future wholly owned domestic subsidiaries that guarantee our obligations under our credit facility also guarantee the obligations under the notes on a senior secured basis. In addition, Dynegy and its other subsidiaries that guarantee our existing
credit facility also guarantee the obligations under the notes on a senior secured basis. The notes and guarantees are senior obligations secured by a second-priority lien on, subject to certain exceptions and permitted liens, all of our and our
guarantors existing and future property and assets that secure our obligations under its credit facility.



The indenture governing the notes contains restrictive covenants that limit our ability and the ability of our subsidiaries that guarantee the notes to,
among other things: (1) redeem, repurchase or pay dividends or distributions on capital stock; (2) make investments or restricted payments; (3) incur or guarantee additional indebtedness; (4) create certain liens; (5) engage in sale and leaseback
transactions; (6) consolidate, merge or transfer all or substantially all of its assets; or (7) engage in certain transactions with affiliates.



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Subordinated Debentures. In May 1997, NGC Corporation Capital Trust I
(Trust) issued, in a private transaction, $200 million aggregate liquidation amount of 8.316% Subordinated Capital Income Securities (Trust Securities) representing preferred undivided beneficial interests in the assets of
the Trust. The Trust invested the proceeds from the issuance of the Trust Securities in an equivalent amount of our 8.316% Subordinated Debentures (Subordinated Debentures). The sole assets of the Trust are the Subordinated Debentures.
The Trust Securities are subject to mandatory redemption in whole, but not in part, on June 1, 2027, upon payment of the Subordinated Debentures at maturity, or in whole, but not in part, at any time, contemporaneously with the optional prepayment
of the Subordinated Debentures, as allowed by the associated indenture. The Subordinated Debentures are redeemable, at our option, at specified redemption prices. The Subordinated Debentures represent our unsecured obligations and rank subordinate
and junior in right of payment to all of our senior indebtedness to the extent and in the manner set forth in the associated indenture. We have irrevocably and unconditionally guaranteed, on a subordinated basis, payment for the benefit of the
holders of the Trust Securities the obligations of the Trust to the extent the Trust has funds legally available for distribution to the holders of the Trust Securities. Since the Trust is considered a SPE, FIN No. 46R was applied effective December
31, 2003. The holders of the Trust Securities absorb a majority of the Trusts expected losses. Accordingly, our obligation is represented by the Subordinated Debentures payable to the deconsolidated Trust rather than the Trust Securities that
were payable to the holders of the Trust Securities. This deconsolidation did not impact our consolidated balance sheets or consolidated statements of operations.



We may defer payment of interest on the Subordinated Debentures as described in the indenture, although we have not yet done
so and have continued to pay interest as and when due. As of December 31, 2004 and 2003, the redemption amount associated with these securities totaled $200 million. In accordance with SFAS No. 150, on July 1, 2003, we reclassified these securities
to long-term debt on the consolidated balance sheets. Prior year amounts have not been reclassified to conform to this change.



ABG Gas Supply Credit Agreement.In August 2004, we used $154 million in proceeds from our $600 million term loan to pre-pay all remaining
indebtedness and other obligations under our ABG Gas Supply financing as required by the terms of our credit facility.



Generation Facility Debt.We previously entered into a lease arrangement for the purpose of constructing a generation facility located in
Kentucky. As originally constituted, this arrangement required variable-rate interest only payments that include an option to purchase the related assets at maturity of the facility for a balloon payment equal to the principal balance on the
financing. We have capitalized upfront fees with our generation facility lease arrangement and amortize these fees over the term of the arrangement. The generation lease arrangement expires in 2007 and bears interest at LIBOR plus 1.5% to 2.5%,
depending on the tranche (3.976% and 2.713% at December 31, 2004 and 2003).



Tilton Capital Lease.In September 1999, Illinois Power entered into an operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. This facility
consists of peaking units totaling 176 MWs of capacity. Illinois Power sublet the turbines to DMG in October 1999. In September 2003, we delivered notice of our intent to exercise our option in order for DMG to purchase the turbines upon the
expiration of the operating lease in September 2004. As a result of this action, we began accounting for the lease obligation as a capital lease. Accordingly, we recorded a $66 million increase to property, plant and equipment and a corresponding
increase to short-term debt. The recorded amount of $66 million represents the fair market value of the leased assets at the inception of the capital lease. The difference between the recorded amount and the $81 million purchase price was accreted
over the remaining term of the capital lease through a charge to interest expense with a corresponding increase to short-term debt.



In July 2004, Illinois Power terminated its lease arrangement, and DMG purchased the turbines for $81 million. This action resulted in a reduction of debt
of $78 million. The difference between the purchase price and



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



the debt balance was recorded as an increase to property, plant and equipment of $3 million in our consolidated balance sheets and represents the remaining
accretion to the end of the term of the original lease agreement.



Note
12Related Party Transactions



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



In
August 2002, we executed an agreement with ChevronTexaco pursuant to which the parties amended the existing gas purchase agreement, security agreement, netting agreement and certain related agreements. Under this new agreement, we accelerated our
payment terms effective upon the closing of the sale of Northern Natural described in Note 3Dispositions, Contract Terminations and Discontinued OperationsDiscontinued OperationsNorthern Natural beginning on page F-21 above.



Also in August 2002, in partial satisfaction of certain of our
obligations to ChevronTexaco under these agreements, we transferred our 39.2% ownership interest in WTLPS, valued at $45 million, to ChevronTexaco, the largest interest owner of WTLPS and operator of the pipeline. This non-cash transaction reduced
accounts payable to affiliates and unconsolidated investments by $45 million.



Other transactions with ChevronTexaco result from purchases and sales of natural gas and natural gas liquids between our affiliates and ChevronTexaco. We believe that these transactions are executed on terms that are
fair and reasonable. During the years ended December 31, 2004, 2003 and 2002, our marketing business recognized net purchases from ChevronTexaco of $23 million, $0.3 billion and $1.5 billion, respectively. In accordance with the net presentation
provisions of EITF Issue 02-03, all of these transactions, whether physically or financially settled, have been presented net on the consolidated statements of operations. In addition, during the years ended December 31, 2004, 2003 and 2002, our
other businesses recognized aggregate sales to ChevronTexaco of $1.1 billion, $0.9 billion and $0.8 billion, respectively, and aggregate purchases of $1.1 billion, $0.8 billion and $0.5 billion, respectively, which are reflected gross on the
consolidated statements of operations.



Equity
Investments.We hold investments in joint ventures in which ChevronTexaco or its affiliates are also investors. These investments include a 22.9% ownership interest in VESCO, which holds a pipeline gathering system, a processing plant, a
fractionator and an underground natural gas liquids storage facility in Louisiana; and a 50% ownership interest in Nevada Cogeneration Associates #2, which holds our Black Mountain power generation facility. During the years ended December 31, 2004,
2003 and 2002, our portion of the net income from joint ventures with ChevronTexaco was approximately $13 million, $10 million and $17 million, respectively.



We also purchase and sell natural gas, natural gas liquids, crude oil, emissions and power and, in some instances, earn management fees from certain
entities in which we have equity investments. During the years



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



ended December 31, 2004, 2003 and 2002, our marketing business recognized net sales to affiliates related to these transactions of $0.3 billion, $0.7 billion
and $1.0 billion, respectively. In accordance with the net presentation provisions of EITF 02-03, all of these transactions, whether physically or financially settled, have been presented net on the consolidated statements of operations. In
addition, during the years ended December 31, 2004, 2003 and 2002, our other businesses recognized aggregate sales to these affiliates of $12 million, $25 million and $15 million, respectively, and aggregate purchases of $170 million, $177 million
and $152 million, respectively, which are reflected gross on the consolidated statements of operations. Revenues were related to the supply of fuel for use at generation facilities, primarily West Coast Power, and the supply of natural gas sold by
retail affiliates. Expenses primarily represent the purchase of natural gas liquids that are subsequently sold in our marketing operations.



Other.We routinely conduct business with subsidiaries of Dynegy that are not a part of this consolidated group. As a result of such
transactions, we had approximately zero and $2.8 million in an accounts payable, affiliates balance at December 31, 2004 and 2003, respectively.



Additionally, certain of our subsidiaries received revenues of approximately $352 million, $569 million and $486 million from Illinois Power during the
years ended December 31, 2004, 2003 and 2002, respectively. These revenues primarily related to a power purchase agreement that we had with Illinois Power that provided Illinois Power the right to purchase power from us for a primary term that
expired December 31, 2004. For further information, please see Note 3Dispositions, Contract Terminations and Discontinued OperationsDispositions and Contract TerminationsSale of Illinois Power beginning on page F-19 above



These subsidiaries also purchased approximately $5 million, $9
million and $10 million of natural gas from Illinois Power during the years ended December 31, 2004, 2003 and 2002, respectively.



F-39



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 13Income Taxes



Prior period amounts in this footnote have been restated. For further information, please see the Explanatory Note beginning
on page F-8.



Income Tax Benefit.We are subject
to U.S. federal, foreign and state income taxes on our operations. Components of loss from continuing operations before income taxes were as follows:



|                                                              |  |                         |      |   |      |   |      |      |  |   |        |  
|------------------------------------------------------------- |  | ----------------------- | ---- | - | ---- | - | ---- | ---- |  | - | ------ | -
|                                                              |  | Year Ended December 31, |     
|                                                              |  | 2004                    |      |   | 2003 |   |      | 2002 | 
|                                                              |  | (in millions)           |     
|Income (loss) from continuing operations before income taxes: |  |                         |      |   |      |   |      |      |  |   |        |  
|Domestic                                                      |  | $                       | (193 | ) |      | $ | (457 | )    |  | $ | (1,349 | )
|Foreign                                                       |  |                         | (1   | ) |      |   | 2    |      |  |   | (9     | )
|                                                              |  |                         |      |   |      |   |      |      |  |   |        |  
|                                                              |  | $                       | (194 | ) |      | $ | (455 | )    |  | $ | (1,358 | )
|                                                              |  |                         |      |   |      |   |      |      |  |   |        |  



Components of income
tax benefit related to loss from continuing operations were as follows:



|                                |  |                         |     |   |      |   |     |      |  |   |    
|------------------------------- |  | ----------------------- | --- | - | ---- | - | --- | ---- |  | - | ---
|                                |  | Year Ended December 31,
|                                |  | 2004                    |     |   | 2003 |   |     | 2002
|                                |  | (in millions)          
|Current tax benefit (expense):  |  |                         |     |   |      |   |     |      |  |   |    
|Domestic                        |  | $                       | (7  | ) |      | $ | (9  | )    |  | $ | 222
|Deferred tax benefit (expense): |  |                         |     |   |      |   |     |      |  |   |    
|Domestic                        |  |                         | 104 |   |      |   | 201 |      |  |   | 134
|Foreign                         |  |                         |    |   |      |   | (1  | )    |  |   | 10 
|                                |  |                         |     |   |      |   |     |      |  |   |    
|Income tax benefit              |  | $                       | 97  |   |      | $ | 191 |      |  | $ | 366
|                                |  |                         |     |   |      |   |     |      |  |   |    



Income tax benefits
related to loss from continuing operations for the years ended December 31, 2004, 2003 and 2002, were equivalent to effective rates of 50%, 42% and 27%, respectively. Differences between taxes computed at the U.S. federal statutory rate and our
reported income tax benefit were as follows:



|                                                  |  |                         |    |      |   |     |      |  |   |      |  
|------------------------------------------------- |  | ----------------------- | -- | ---- | - | --- | ---- |  | - | ---- | -
|                                                  |  | Year Ended December 31, |   
|                                                  |  | 2004                    |    | 2003 |   |     | 2002 | 
|                                                  |  | (in millions)           |   
|Expected tax benefit at U.S. statutory rate (35%) |  | $                       | 68 |      | $ | 159 |      |  | $ | 475  |  
|State taxes                                       |  |                         | 13 |      |   | 20  |      |  |   | 49   |  
|Foreign taxes                                     |  |                         |   |      |   | (2  | )    |  |   | 1    |  
|Valuation allowance                               |  |                         | 15 |      |   |    |      |  |   | (5   | )
|Goodwill permanent differences and impairments    |  |                         |   |      |   |    |      |  |   | (142 | )
|Basis differentials and other                     |  |                         | 1  |      |   | 14  |      |  |   | (12  | )
|                                                  |  |                         |    |      |   |     |      |  |   |      |  
|Income tax benefit                                |  | $                       | 97 |      | $ | 191 |      |  | $ | 366  |  
|                                                  |  |                         |    |      |   |     |      |  |   |      |  



F-40



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Deferred Tax Liabilities and Assets. Significant components of deferred tax liabilities
and assets were as follows:



|                                               |  |               |     |   |      |   |     |  
|---------------------------------------------- |  | ------------- | --- | - | ---- | - | --- | -
|                                               |  | December 31,  |    
|                                               |  | 2004          |     |   | 2003 |  
|                                               |  | (in millions) |    
|Deferred tax assets                            |  |               |     |   |      |   |     |  
|Current:                                       |  |               |     |   |      |   |     |  
|NOL carryforwards                              |  | $             |    |   |      | $ | 109 |  
|Reserves                                       |  |               | 51  |   |      |   | 25  |  
|Miscellaneous book/tax recognition differences |  |               | 22  |   |      |   |    |  
|                                               |  |               |     |   |      |   |     |  
|Subtotal                                       |  |               | 73  |   |      |   | 134 |  
|Less: valuation allowance                      |  |               |    |   |      |   | (10 | )
|                                               |  |               |     |   |      |   |     |  
|Total current deferred tax assets              |  |               | 73  |   |      |   | 124 |  
|                                               |  |               |     |   |      |   |     |  
|Non-current:                                   |  |               |     |   |      |   |     |  
|NOL carryforwards                              |  |               | 248 |   |      |   | 324 |  
|Capital loss carryforwards                     |  |               | 34  |   |      |   | 56  |  
|Foreign tax credits                            |  |               | 34  |   |      |   | 5   |  
|Other                                          |  |               | 29  |   |      |   | 10  |  
|                                               |  |               |     |   |      |   |     |  
|Subtotal                                       |  |               | 345 |   |      |   | 395 |  
|Less: valuation allowance                      |  |               | (69 | ) |      |   | (41 | )
|                                               |  |               |     |   |      |   |     |  
|Total non-current deferred tax assets          |  |               | 276 |   |      |   | 354 |  
|                                               |  |               |     |   |      |   |     |  
|Deferred tax liabilities                       |  |               |     |   |      |   |     |  
|Depreciation and other property differences    |  |               | 681 |   |      |   | 653 |  
|Miscellaneous book/tax recognition differences |  |               | 45  |   |      |   | 17  |  
|                                               |  |               |     |   |      |   |     |  
|Total deferred tax liabilities                 |  |               | 726 |   |      |   | 670 |  
|                                               |  |               |     |   |      |   |     |  
|Net deferred tax liability                     |  | $             | 377 |   |      | $ | 192 |  
|                                               |  |               |     |   |      |   |     |  



F-41



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



NOL Carryforwards. At December 31, 2004, we had approximately $581 million of regular
federal tax NOL carryforwards after considering the effect of carryback to prior years. If certain substantial changes in the Companys ownership should occur, there would be an annual limitation on the amount of the carryforwards which can be
utilized. There was no valuation allowance established at December 31, 2004 for our federal NOL carryforwards, as management believes our NOL carryforward is more likely than not to be fully realized in the future based, among other things, on
managements estimates of future taxable net income, future reversals of existing taxable temporary differences and tax planning.



At December 31, 2004, state NOL carryforwards were as follows:



|                                                        |  |               |       |                  |            
|------------------------------------------------------- |  | ------------- | ----- | ---------------- | -----------
|                                                        |  | Amount        |       | Expiration Dates
|                                                        |  | (in millions) |       |                 
|States where we file unitary state income tax returns:  |  |               |       |                  |            
|Illinois                                                |  | $             | 225   |                  | 2015  2022
|California                                              |  |               | 44    |                  | 2022  2023
|New Mexico                                              |  |               | 25    |                  | 2007  2008
|States where we file separate state income tax returns: |  |               |       |                  |            
|Louisiana                                               |  |               | 171   |                  | 2020  2024
|New York                                                |  |               | 167   |                  | 2022  2024
|Kentucky                                                |  |               | 156   |                  | 2022  2024
|Texas                                                   |  |               | 61    |                  | 2007  2009
|North Carolina                                          |  |               | 56    |                  | 2015  2019
|Georgia                                                 |  |               | 42    |                  | 2022  2024
|Ohio                                                    |  |               | 41    |                  | 2023  2024
|Michigan                                                |  |               | 40    |                  | 2011  2024
|Pennsylvania                                            |  |               | 37    |                  | 2022  2024
|Other                                                   |  |               | 20    |                  | 2005  2024
|                                                        |  |               |       |                  |            
|                                                        |  | $             | 1,085 |                  |            
|                                                        |  |               |       |                  |            



During 2004, we
established a valuation allowance for certain state NOL carryforwards which management believes are not likely to be fully realized in the future based on our ability to generate gains in the respective state. See Change in Valuation
Allowance below.



Capital Loss
Carryforwards. At December 31, 2004, we had approximately $91 million of capital loss carryforwards. The capital loss carryforwards expire during 2007 and 2008. At December 31, 2004, we had a full valuation allowance for our capital loss
carryforwards, which management believes are not likely to be fully realized in the future based on our ability to generate capital gains.



Foreign Tax Credits. At December 31, 2004, we had approximately $34 million of foreign tax credits. The foreign tax credits will expire in
2005 and 2006. At December 31, 2004, we had a full valuation allowance for our foreign tax credits, as we have disposed of or discontinued the majority of our foreign operations and management believes the foreign tax credits are not likely to be
fully realized in the future based on our ability to generate foreign source income. Unless we generate foreign source income in 2005 and 2006, which we do not anticipate, we will write-off the $34 million of foreign tax credits and the related $34
million valuation allowance.



Residual U.S. Income Tax on
Foreign Earnings. We do not have any material undistributed earnings from our foreign operations. In addition, we have sufficient intercompany loans from our affiliates in both the U.K.



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and Canada, which will allow us the ability to repatriate any funds from those countries without incurring any income tax. Therefore, we have not provided
any U. S. deferred taxes or foreign withholding taxes, if any, that might be payable on the actual or deemed remittance of any such earnings.



Change in Valuation Allowance. Realization of our deferred tax assets is dependent upon, among other things, our ability to generate taxable
income of the appropriate character in the future. During 2004, we released valuation allowance related to completed sales that resulted in the realization of capital gains. We also established valuation allowance on certain foreign tax credits and
a state net operating loss carryforward. At December 31, 2004 and 2003, valuation allowances related to capital loss carryforwards, foreign tax credit carryforwards and state NOL carryforwards have been established. The changes in the valuation
allowance by attribute for the years ended December 31, 2004 and 2003 were as follows:



|                                                       |  |                           |     |   |                    |   |     |                        |  |   |       |   |  |   |     |  
|------------------------------------------------------ |  | ------------------------- | --- | - | ------------------ | - | --- | ---------------------- |  | - | ----- | - |  | - | --- | -
|                                                       |  | Capital LossCarryforwards |     |   | Foreign TaxCredits |   |     | State NOLCarryforwards |  |   | Total |  
|                                                       |  | (in millions)             |    
|Balance as of December 31, 2002 and 2003               |  | $                         | (46 | ) |                    | $ | (5  | )                      |  | $ |      |   |  | $ | (51 | )
|Changes in valuation allowancecontinuing operations   |  |                           | 16  |   |                    |   | (29 | )                      |  |   | (1    | ) |  |   | (14 | )
|Changes in valuation allowancediscontinued operations |  |                           | (4  | ) |                    |   |    |                        |  |   |      |   |  |   | (4  | )
|                                                       |  |                           |     |   |                    |   |     |                        |  |   |       |   |  |   |     |  
|Balance as of December 31, 2004                        |  | $                         | (34 | ) |                    | $ | (34 | )                      |  | $ | (1    | ) |  | $ | (69 | )
|                                                       |  |                           |     |   |                    |   |     |                        |  |   |       |   |  |   |     |  



American Jobs
Creation Act of 2004. On October 22, 2004, the American Jobs Creation Act of 2004 was signed into law. This legislation contains a number of changes to the Internal Revenue Code. We have analyzed the law in order to determine its effects.
The two most notable provisions are those dealing with the reduced tax rate on the repatriation of money from foreign operations and the deduction for domestic-based manufacturing activity. We do not believe either of these provisions will impact us
as we do not have significant funds overseas to take advantage of the reduced tax rate on repatriations, and we are projecting that we will continue to generate net operating losses for at least the next twelve months and, therefore, cannot take
advantage of the domestic-based manufacturing deduction.



Various IRS and State Settlements and Settlement of Contingent Liability Transactions.On February 23, 2005, we settled our dispute with the IRS relating to our participation in three contingent liability transactions in 1996,
1997 and 1999. The settlement did not have a material impact on our financial results. We expect to pay the penalty and interest of approximately $2 million in settlement of this matter in the first quarter 2005. Our federal income tax returns are
routinely audited by the IRS, and provisions are routinely made in the financial statements in anticipation of the results of these audits. The IRS completed its audit of our 1998-2000 tax returns during 2004, including the settlement of the
contingent liability transactions noted above.



Note 14Commitments and
Contingencies



Summary of Material Legal Proceedings



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



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Contingencies. During 2004, we recorded pre-tax legal and settlement charges of $117 million, including cash payments made in the period in excess of
our then-existing accruals. The charges recorded relate to contingencies for which, during 2004, either the amount of loss became probable and reasonably estimable or our previous loss estimates were adjusted.



For environmental matters, we record liabilities when remedial efforts are
probable and the costs can be reasonably estimated. Please read Note 2Accounting Policies beginning on page F-10 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 each of these matters based on current
information and made a judgment concerning its potential outcome, considering 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.



Shareholder Litigation. We and Dynegy are defending a class action lawsuit filed on behalf of purchasers of
Dynegys publicly traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit as filed principally alleged that we and Dynegy and certain of our current and former officers and
directors violated the federal securities laws in connection with our disclosures, including accounting disclosures, regarding Project Alpha (a structured natural gas transaction entered into by us in April 2001), round-trip trading, the submission
of false trade reports to publications that calculate natural gas index prices, the alleged manipulation of the California power market and the restatement of our financial statements for 1999-2001. The Regents of the University of California are
lead plaintiff and Lerach Coughlin Stoia & Robbins, LLP is class counsel. The plaintiff filed an amended complaint in January 2004 and, in March 2004, we filed motions to dismiss. Briefing on our motions was completed in June 2004. The judge
entered an order on our motion in October 2004 dismissing all claims brought by the plaintiff under the Securities Act of 1933, except those relating to Dynegys March 2001 note offering and December 2001 common stock offering, and the
Securities Exchange Act of 1934, except those dealing with Project Alpha and two alleged round-trip trades. Further, the judge scheduled the trial to commence in May 2005. Also in October 2004, the plaintiff voluntarily dismissed its claim under the
Securities Act of 1933 relating to Dynegys March 2001 note offering. The parties filed motions on the class certification issue throughout the fourth quarter 2004. In December 2004, the court issued an order identifying the class period for
the Exchange Act claims as June 21, 2001 through July 22, 2002, and the class period for the Securities Act claims to begin December 20, 2001. The court is taking discovery on the issue of the closing date for the Securities Act class period. We and
Dynegy have been, and intend to continue, actively mediating this matter to reach a reasonable settlement if possible. However, we and Dynegy will be fully prepared for the trial scheduled for May 2005 in the event a settlement cannot be reached
with the plaintiff. An adverse result in this litigation could have a material adverse effect on our financial condition, results of operations and cash flows. Reserves have been provided in connection with this litigation.



In addition, Dynegy is a nominal defendant in several derivative lawsuits
brought by shareholders on Dynegys behalf against certain of its former officers and current and former directors whose claims are similar to those described above. These lawsuits have been consolidated into two groupsone pending in
federal court



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and the other pending in state court. A hearing on Dynegys motion to dismiss the federal derivative claim was held in February 2005, at which time the
judge indicated his intent to stay or dismiss this matter pending the resolution of the shareholder litigation described above. Subsequently, in February 2005, the plaintiffs voluntarily dismissed this lawsuit. Discovery in the state derivative
matter is ongoing. We do not expect to incur any material liability with respect to these claims.



ERISA/Dynegy 401(k) Litigation. Dynegy is defending a purported class action complaint filed in federal district court on behalf of
participants holding Dynegy common stock in the Dynegy 401(k) Savings Plan during the period from April 1999 to January 2003. This complaint alleges violations of ERISA in connection with Dynegys 401(k) Savings Plan, including claims that
Dynegys Board and certain of Dynegys former and current officers, past and present members of Dynegys Benefit Plans Committee, former employees who served on a predecessor committee to its Benefit Plans Committee, and Vanguard
Fiduciary Trust Company and CG Trust Company (trustees of the trust that held Plan assets for portions of the class period) breached their fiduciary duties to the Plans participants and beneficiaries in connection with the Plans
investment in Dynegy common stockin particular with respect to 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 July 2003, Dynegy filed a motion to dismiss this action. The judge entered an order on Dynegys motion in March 2004, dismissing several of the plaintiffs claims and all of the defendants except
Dynegy and the members of its Benefit Plans Committee from January 2002 to January 2003, the substantially reduced class period established by the order. In May 2004, in response to the plaintiffs request, the judge ordered the parties to
engage in mediation. The parties mediated for two months, and ultimately reached a settlement under which the defendants agreed to pay $30.75 million to the plaintiff for a full and final release of all claims. In December 2004, the Court granted
final approval of the agreement and the settlement was fully funded by insurance proceeds. Plaintiffs counsel is currently in the process of distributing the settlement funds to the class members.



ERISA/Illinois Power 401(k) Litigation. In January 2005, three
Illinois Power employees and participants in the Illinois Power Company Incentive Savings Plan For Employees Covered Under a Collective Bargaining Agreement, which we refer to as the Illinois Power 401(k) Plan, purporting to represent all Illinois
Power employees who held Dynegy common stock through the Illinois Power 401(k) Plan during the period from February 2000 through September 2004, 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 Illinois Power 401(k) Plan, including claims that certain of Dynegys former and current officers (who are past and present members of its
Benefit Plans Committee) breached their fiduciary duties to the plans participants and beneficiaries in connection with the plans investment in Dynegy common stock in a manner similar to that alleged in the complaint filed with respect
to the ERISA litigation Dynegy settled in December 2004 described above. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorneys fees and other costs. We do not believe that any liability which might be incurred
by Dynegy as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Baldwin Station Litigation.Since November 1999, DMG has been the subject of an NOV from the EPA and a complaint filed by the EPA and the
DOJ in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations related to certain maintenance, repair and replacement activities at our Baldwin generating station. We have reached agreement with
the EPA, the DOJ, the State of Illinois and the environmental group intervenors on terms to settle the litigation. A consent decree was signed by all parties and lodged with the U.S. District Court for the Southern District of Illinois on March 7,
2005. As required by the Clean Air Act, the consent decree will be posted in the Federal Register and the public will be given an opportunity to comment on the terms of the settlement. We expect that the consent decree will be approved and entered
by the Court after the public comments have been considered and addressed by EPA and the DOJ. The



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consent decree provides for our payment of a civil penalty of $9 million and for our funding of several environmental projects in the additional aggregate
amount of $15 million. It also requires us to install additional emission controls at our Baldwin, Vermilion and Havana plants. Under the terms of the settlement, we will invest $321 million in emission control projects through 2010, including the
previously planned conversion of our Vermilion facility to low-sulfur PRB coal, with an additional $224 million in emission control projects in the 2011-2012 timeframe. The decree settles all claims in the litigation, as well as similar claims that
might have been brought related to maintenance, repair and replacement activities at other DMG plants including Vermilion, Wood River, Hennepin and Havana.



Reserves have been provided in an aggregate amount adequate to cover the civil penalties and the environmental projects provided for under the consent
decree.



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



California Market Litigation. We and/or Dynegy and numerous other power generators and marketers are the subject of numerous lawsuits
arising from our participation in the western power markets during the California energy crisis. Eight of these lawsuits, which primarily allege manipulation of the California wholesale power markets and seek unspecified treble damages, were
consolidated before a single federal judge. That judge dismissed two of the cases in the first quarter 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. An appeal from the Ninth Circuits affirmation of the September 2004 dismissal has been taken to the United States Supreme Court, and we filed our response brief in January 2005. Regarding the remaining six
consolidated cases, the Ninth Circuit denied our appeal of a prior decision to remand those cases to state court and affirmed the remand in December 2004. We intend to file a motion to dismiss these cases in the state court in the first quarter
2005.



In addition to the eight consolidated lawsuits discussed
above, nine other 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/or Dynegy and numerous other power generators and marketers
between April and October 2002. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek an injunction, restitution and unspecified damages. While some of the allegations in
these lawsuits are similar to the allegations in the eight lawsuits described above, these lawsuits include additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. The court
dismissed eight of these nine actions, although the plaintiffs appealed, and the briefing on that appeal was completed in October 2004. In February 2005, the Ninth Circuit issued its decision affirming the denial of remand and dismissal of these
cases. The ninth case was remanded to state court, where a newly added defendant filed a motion in February 2004 to remove the case back to federal court. In January 2005, following a hearing on the issue, the court denied the removal and returned
the case to state court. We intend to file expeditiously a motion to dismiss this case.



In December 2002, two additional actions were filed with similar allegations on behalf of residents of Washington and Oregon. In May 2003, the plaintiffs voluntarily dismissed these actions and refiled them in
California Superior Court as a class action complaint. The complaint, which was brought on behalf of consumers and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California
market, alleges violations of the Cartwright Act and unfair business practices. This



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action has been removed from state court and consolidated with existing actions pending before the United States District Court for the Northern District of
California. The hearing on plaintiffs appeal to remand to state court occurred in February 2004. The judge stayed his ruling on the appeal pending the Ninth Circuits ruling on the six consolidated cases referenced above.



In May 2004, Wah Chang, a division of TDY Industries, Inc.,
filed suit in Oregon federal court against several energy companies, including Dynegy Power Marketing, Inc., seeking more than $30 million in compensatory damages resulting from alleged manipulation of the California wholesale power markets. In
February 2005, at a hearing on our December 2004 motion to dismiss, the court granted our motion and dismissed this lawsuit.



In June 2004, the City of Tacoma public utility filed a lawsuit in Washington federal court against a number of energy companies, including us, alleging
it paid inflated prices for electricity due to the defendants manipulation of the California wholesale power markets. In response to the defendants December 2004 motion, the court dismissed this lawsuit in February 2005.



In October 2004, Preferred Energy Services, an independent electric services
provider in California, filed suit against us and several other defendants alleging that the defendants, in violation of the California anti-trust and unfair business practices statutes, engaged in unfair, unlawful and deceptive practices in the
California wholesale energy market from May 2000 through December 2001. Plaintiff, which formerly sold electricity generated from renewable sources in the California market, claims to have been forced out of business by the defendants conduct
and is seeking $5 million in compensatory damages, as well as treble damages. We have not yet been served with this lawsuit.



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



FERC and Related Regulatory InvestigationsRequests for Refunds. In October 2004, the FERC approved in all respects the agreement announced by Dynegy and West Coast Power in April 2004 which
provides for the settlement of FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001, including:



| |  |  | the FERCs June 2003 order to show cause why the activities of certain participants in the California power markets from January 2000 to June 2001, including Dynegy, did not
constitute gaming and/or anomalous market behavior as defined in the Cal ISO and Cal PX tariffs, which matter was resolved by the January 2004 settlement providing that West Coast Power will pay approximately $3 million into a fund for the benefit
of California and Western electricity consumers. This January 2004 settlement was incorporated into the broader settlement described below; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the FERCs July 2001 hearings and October 2003 orders relating to the establishment of (i) refunds to electricity customers, or offsets against amounts owed to electricity
suppliers, during the period of October 2000 through June 2001 and (ii) a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The parties to this settlement other than Dynegy and West Coast Power include the FERC Office of Market Oversight and
Investigations, NRG Energy, Inc., Pacific Gas and Electric Company, Southern California Edison, San Diego Gas & Electric Company, the CDWR, the California Electricity Oversight Board and the California



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Attorney General. Other market participants are permitted to opt into this settlement and share in the distribution of the settlement proceeds. Most of these
other market participants have agreed to participate in the settlement. The entitlement to refund and/or the liability of each of the non-settling market participants will be determined by the Cal ISO. Under the terms of the settlement, we will have
no further liability to these non-settling parties.



As part of
the settlement agreement, West Coast Power agreed to (i) forego its right to collect approximately $259 million in past-due receivables, plus interest, from the Cal ISO and the Cal PX related to the settlement period, (ii) forego natural gas cost
recovery claims against the California settling parties related to the settlement period, and (iii) place into escrow accounts a total of $22.5 million, which includes the above-referenced $3 million settlement with the FERC staff, for subsequent
distribution to various California energy purchasers. In exchange, the settling parties agreed to forego (i) all claims relating to refunds or other monetary damages for sales of electricity during the settlement period, and (ii) claims alleging
receipt of unjust or unreasonable rates for the sale of electricity during the settlement period.



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 related filings and cannot predict their outcome.



West Coast Power. Prior to the approval of the above-described settlement by the FERC in October 2004, our portion of the receivables owed
to West Coast Power by the Cal ISO and Cal PX as of September 30, 2004 approximated $214 million. As part of the settlement, West Coast Power agreed to forego its right to collect these past due receivables. This change had no impact on our results,
as our portion of these receivables was fully reserved.



Enron Trade Credit Litigation. Shortly before their bankruptcy filing in the fourth quarter 2001, we determined that Enron Corp. and its affiliates had net exposure to us, including certain liquidated damages and other amounts
relating to the termination of commercial transactions among the parties, of approximately $84 million. This exposure was calculated by setting off approximately $230 million owed from Dynegy entities to Enron entities against approximately $314
million owed from Enron entities to Dynegy entities. The master netting agreement between Enron and us and the valuation of the commercial transactions covered by the agreement, which valuation is based principally on the parties assessment of
market prices for such period, remain subject to some dispute. We have engaged in an ongoing process with Enron to reconcile the differences between our respective valuations of the transactions and accounts receivable. As a result of ongoing
refinement of the values of past transactions, we reduced the $84 million amount that we originally believed we were owed by Enron to approximately $57 million, including the liabilities under the gas transportation agreement related to the Sithe
Independence power tolling arrangement.This change in value had no impact on our results, as the net receivable was fully reserved in the fourth quarter 2001. In the event that Enron is victorious in its position that the master netting
agreement is unenforceable, our exposure to Enron would be approximately $216 million, with as much as $220 million in unsecured Dynegy claims remaining to enforce against the bankruptcy estate. As required by the master netting agreement, we
instituted arbitration proceedings against those Enron parties not in bankruptcy in 2002 and filed a motion with the Bankruptcy Court requesting that we be allowed to proceed to arbitration against those Enron parties that are in bankruptcy. The
Enron parties opposed our request and filed an adversary proceeding against us, alleging that the master netting agreement should not be enforced and that the



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Enron companies should recover approximately $230 million from us. We have disputed such allegations and are vigorously defending our position regarding the
setoff rights contained in the master netting agreement, although the Bankruptcy Court has yet to rule on the enforceability of the master netting agreement.



In November 2003, we gave notice of our intent to pursue arbitration against Enron Canada Corp. as a non-bankrupt party to the master netting agreement.
In response, Enron Canada Corp. filed a lawsuit in Canadian District Court to recover the amounts that it claims to be owed by our Canadian subsidiary under the master netting agreement, contingent upon a Bankruptcy Court ruling on the
enforceability of the master netting agreement. In December 2003, Enron filed an application with the Bankruptcy Court for an injunction to prohibit this arbitration; the Bankruptcy Court ruled that the automatic stay of the bankruptcy applied to
our request to pursue arbitration against Enron Canada Corp. under the master netting agreement. Consequently, we are currently prohibited from enforcing the master netting agreement by arbitration. In March 2004, we appealed the enforcement of the
automatic stay and requested permission from the appellate court to proceed with arbitration against Enron Canada Corp. We also filed a motion with the Bankruptcy Court requesting a trial to determine the enforceability of the master netting
agreement under the U.S. Bankruptcy Code. The appellate court denied our appeal as interlocutory in November 2004. We are currently awaiting a ruling by the Bankruptcy Court on our request for a trial date. The parties engaged in a second
court-ordered mediation in November 2004, but did not reach a settlement.



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 claim. Reserves have been provided in an aggregate amount we consider reasonable with respect to
Enrons claims. Given the size of the claims at issue, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.



Severance Arbitrations. Dynegys former CEO, Chuck Watson, former President, Steve Bergstrom, and former
CFO, Rob Doty, each filed for arbitration pursuant to the terms of their employment/severance agreements. These former officers made arbitration claims seeking payments of up to approximately $28.7 million, $10.4 million and $3.4 million,
respectively. In May 2004, pursuant to the decision of the arbitration panel, Dynegy paid Mr. Bergstrom $10.4 million plus attorneys fees, costs and interest in accordance with the arbitration panels decisions. Shortly after the
panels decisions in the Bergstrom matter, Dynegy elected to enter into mediation with Mr. Watson. Through mediation, Dynegy agreed to pay Mr. Watson $22 million to settle his severance claims. Dynegy recorded an expense in the second quarter
2004 in the amount of the difference between this settlement amount and its severance accrual for this matter. Please read Note 4Restructuring and Impairment ChargesSeverance and Other Restructuring Costs beginning on page F-24 for
further discussion regarding the accrual relating to these former executive officers.



The arbitration with respect to Mr. Doty is scheduled to commence in May 2005. Mr. Dotys agreement is subject to interpretation, and we maintain that the amount owed is substantially lower than the amount
sought. Dynegy recorded a severance accrual it considers reasonable relating to this proceeding.



Farnsworth Litigation. In August 2002, Bradley Farnsworth filed a lawsuit against Dynegy in state court claiming breach of contract and that
he was demoted and ultimately fired from the position of Controller for refusing to participate in illegal activities. Specifically, Mr. Farnsworth alleged, in the words of his amended complaint, that certain of Dynegys former executive
officers requested that he shave or reduce for accounting purposes the forward price curves associated with the natural gas business in the United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a
reduction in Dynegys mark-to-market losses. In March 2004, the judge dismissed Mr. Farnsworths claim that he was asked to shave forward price curves.



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Under his remaining breach of contract and fraudulent inducement claims, Mr. Farnsworth alleged he was entitled to a termination payment under his employment
agreement, which he estimated at $11 million, equal to 2.99 times the greater of his average base salary and incentive compensation for the highest three calendar years preceding termination or his base salary and target bonus amount for the year of
termination. Trial on the breach of contract and fraud claims occurred in December 2004. Although the jury found that Dynegy did not breach the employment agreement, it found that Mr. Farnsworth was fraudulently induced to enter into the agreement.
Consequently, the jury awarded the plaintiff $2.2 million in actual damages and $1.4 million in punitive damages. Dynegy subsequently settled this litigation and paid Mr. Farnsworth $1.4 million in exchange for a complete release. Dynegys
reserve for this litigation was adequate with respect to the settlement amount.



Apache Litigation. In May 2002, Apache Corporation filed suit in state court against Versado, as purchaser and processor of Apaches gas, and DMS, as operator of the Versado assets in New Mexico,
seeking more than $9 million in damages. The plaintiffs petition, as amended, alleges (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that Versado engaged in sham transactions with affiliates,
resulting in Versado not receiving fair market value when it sells gas and liquids, and (iii) that the formula for calculating the amount Versado receives from its buyers of gas and liquids is flawed since it is based on gas price indexes that these
same affiliates are alleged to have manipulated by providing false price information to the index publisher. At trial, the plaintiffs claim with respect to the alleged sham transactions and index manipulation, among others, were
severed by the court and abated for a future trial, and the jury found in favor of the plaintiff on the remaining lost gas claim, awarding approximately $1.6 million in damages. In May 2004, our motion to set aside this judgment was granted by the
court and the jurys award to the plaintiff was vacated. The plaintiff filed its notice of appeal with the court in October 2004 and its appellate brief in December 2004. We intend to file our response in the first quarter 2005. The parties
attended mediation in February 2005, but did not reach a settlement. We do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash
flows.



Gas Index Pricing Litigation. We and/or
Dynegy are defending the following suits claiming damages resulting from the alleged manipulation of gas index publications and prices by us and others: ABAG v. Sempra Energy et al. (filed in state court in November 2004); AblemanArt Glass v. Encana Corporation et al.(class action filed in federal court in December 2004); Benschiedt(class action filed in state court in February 2004); Bustamante v. The McGraw Hill Companies et al. (class action filed in
state court in November 2002); City and County of San Franciscov. Dynegy Inc. et al.(filed in state court in July 2004); County of San Diego v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state
court in July 2004); County of San Mateov. Sempra Energy et al.(filed in state court in December 2004); County of Santa Clarav. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al.(filed in state court in
July 2004); 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); People of the State of Montana et al. v. Williams Energy Marketing et al.(filed in federal court in July 2003); Sacramento Municipal Utility District (SMUD) v. Reliant Energy Services, et al.(filed in state court in November 2004);School Project for Utility Rate Reduction v. Sempra Energy et al.(filed in state court in November 2004);Sierra Pacific Resources and Nevada Power Company v. El Paso Corp. et al. (filed in
federal court in April 2003); Tamco v. Dynegy Inc. et al.(filed in state court in December 2004);Texas-Ohio Energy, Inc. v. CenterPoint Energy Inc., et al.(class action filed in federal court in November 2003); and Utility
Savings& Refund v. Reliant Energy Services, et al.(class action filed in federal court in November 2004). In each of these suits, the plaintiffs allege that we and other energy companies engaged in an illegal scheme to



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



inflate natural gas prices by providing false information to gas index publications, thereby manipulating the price. All of the complaints rely heavily on
the FERC and CFTC investigations into and report concerning index-reporting manipulation in the energy industry. The plaintiffs generally seek unspecified actual and punitive damages relating to costs they claim to have incurred as a result of the
alleged conduct. We have not been served in the Montana or Leggett cases.



Pursuant to various motions filed by the parties to the litigation described above, the gas index pricing lawsuits pending in state court (except for Nelson Brothers) have been consolidated before a single
judge in state court in San Diego. These cases are now entitled the Judicial Counsel Coordinated Proceeding (JCCP) 4221, 4224, 4226, and 4228, the Natural Gas Anti-Trust Cases, I, II, III, & IV, which we refer to as the
Coordinated Gas Index Cases. A case management conference is expected in the next 60 days. The Nelson Brothers lawsuit, in which we have been brought in as a third party by the defendant, Cherokee Nitrogen, involves an alleged
breach of a gas purchase contract and continues in state court in Alabama. The parties are presently engaged in discovery.



As to the gas index pricing lawsuits that have been filed in federal court, the Sierra Pacific case was dismissed in December 2004 on
defendants motion. In Texas-Ohio, the defendants filed a motion to dismiss in May 2004, on which the court held a hearing in January 2005. We are awaiting the courts ruling. The parties are actively engaged in discovery in the
In re Natural Gas Commodity Litigation matter, following denial of the appeal of the previous denial of defendants motion to dismiss. The Multiut case involves a counterclaim filed by the defendant, Multiut, against whom we have
a pending breach of gas purchase contract claim. That case is proceeding in federal court in Illinois. The remaining federal court cases are pending transfer, or have already been transferred, to the federal judge in Nevada who is also currently
presiding over the Sierra Pacific and Texas-Ohio matters.



We are analyzing all of these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability in connection with these lawsuits. We do not believe that any liability that we might
incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



Stand Energy Litigation (formerly Atlantigas Corp. Litigation). In November 2003, Atlantigas Corporation filed suit in Maryland against us
and several other defendants alleging certain conspiracies between natural gas shippers and storage facilities. The complaint alleged that the interstate pipelines provided preferential storage and transportation services to their own unregulated
marketing affiliate in return for percentages of the profits reaped by the marketing affiliate and that such conduct violated applicable FERC regulations and the federal antitrust laws and constituted common law tortious interference with
contractual and business relations. In addition, the complaint claimed we conspired with the other defendants to receive preferential natural gas storage and transportation services at off-tariff prices. The complaint sought unspecified compensatory
and punitive damages. In January 2004, the defendants filed motions to dismiss the plaintiffs claims. In July 2004, prior to the Courts ruling on the defendants motions, the plaintiff voluntarily dismissed the Maryland federal
court action against all defendants. Shortly thereafter, plaintiff filed a class action lawsuit in a West Virginia state court against several defendants, excluding us, on similar grounds to the previous Maryland federal action. In October 2004, the
plaintiff filed an amended class action complaint naming us as a defendant in the litigation. In response, Columbia, the primary defendant, filed a motion to strike the amended pleading as untimely and our participation in the suit will be delayed
pending the resolution of this motion. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability in connection with these lawsuits. We do not believe that any
liability that we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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



U.S. Attorney Investigations. The U.S. Attorneys office in Houston is continuing its investigation of our actions relating to Project Alpha and our gas trade reporting practices. We have produced documents and witnesses
for interviews in connection with this investigation. Seven of our natural gas traders were terminated in the fourth quarter 2002 for violating our Code of Business Conduct after an ongoing internal investigation conducted by Dynegys Audit and
Compliance Committee in collaboration with independent counsel discovered that inaccurate information regarding natural gas trades had been reported to various energy industry publications. In January 2003, one of our former natural gas traders was
indicted in Houston on three counts of knowingly causing the transmission of false trade reports used to calculate the index price of natural gas and four counts of wire fraud. In August 2003, however, several of these counts were dismissed as
unconstitutional. Upon request by the U.S. Attorneys office for reconsideration of this ruling, the judge reinstated the dismissed counts. The case was originally set for trial in January 2004; however, both the U.S. Attorneys office and
the defense have appealed the courts rulings regarding the dismissed and reinstated charges. The Fifth Circuit Court of Appeals heard argument on these matters in October 2004, and reinstated all of the charges against the defendant in
December 2004. A trial date has not yet been set on this indictment. In addition, in December 2004, a second indictment was filed against this same former employee and other individuals alleging conspiracy to falsely report gas prices to various
index publications. That indictment is scheduled for trial in October 2005.



In June 2003, three former Dynegy employees were indicted on charges of conspiracy, securities fraud and mail and wire fraud related to the Project Alpha transaction. Subsequently, two of these former employees pled
guilty to conspiracy to commit securities fraud. These former employees have not been sentenced pending the completion of the governments investigation. Trial on the indictment against the third employee was held in November 2003. The
defendant was convicted on all charges and, in March 2004, sentenced to a term of approximately 24 years in federal prison.



We are cooperating fully with the U.S. Attorneys office in its continuing investigation of these matters and cannot predict the ultimate outcome of
these investigations.



Additionally, the United States
Attorneys office in the Northern District of California issued a Grand Jury subpoena requesting information related to our activities in the California energy markets in November 2002. We have been, and intend to continue, cooperating fully
with the U.S. Attorneys office in its investigation of these



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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 recordkeeping, 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 recent settlement in the ERISA litigation, it intended to take no further
action with respect to its investigation of the Dynegy Inc. 401(k) Plan. However, its investigation is ongoing as it relates to the Illinois Power 401(k) Plans, and the recent litigation relating to those plans described above.



Other Commitments and Contingencies



In conducting our operations, we have routinely entered into long-term
commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital
projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, plant sites, power generation assets and LPG vessel charters. The following describes the more significant commitments
outstanding at December 31, 2004.



Purchase Obligations.We have routinely entered into contracts for the purchase and sale of electricity, some of which contain fixed capacity payments. Such obligations are generally payable on a ratable basis, the terms of which extend through September 2017. In
return for such fixed capacity payments, we receive the right to generate electricity, which we then may re-market. These types of arrangements are referred to as tolling arrangements. Fixed payments associated with these arrangements totaled
approximately $2.1 billion at December 31, 2004. This amount includes the capacity payments on our remaining tolls as well as a cash obligation under a derivative contract related to the Independence tolling agreement.



We have other firm capacity payments related to storage and transportation of
natural gas and transmission of electricity. Such arrangements are routinely used in the physical movement and storage of energy consistent with our business strategy. The total of such obligations was $170 million as of December 31, 2004.



In addition, we have conditional purchase obligations in the
amount of $124 million related to our co-sourcing agreement with Accenture Ltd., which runs through 2013. This 10-year agreement may be cancelled after two years upon the payment of a termination fee, which ranges from $6 million for the first
quarter 2005, declining to $2 million through 2013. This termination fee is in addition to amounts due for services incurred through the termination date.



Advance Agreement.In 1997, we received cash from a gas purchaser as an advance payment under our agreement to make future natural gas
deliveries over a ten-year period. As a condition of the agreement, we entered into a natural gas swap with a third party under which we became a fixed-price payer on identical volumes to those to be delivered under the agreement at prices based on
current market rates. The cash receipt is included as deferred revenue in other long-term liabilities on the consolidated balance sheets and is ratably reduced as gas is delivered to the purchaser under the terms of the agreement. The balance at
December 31, 2004 was approximately $42 million. The agreement contains specified non-performance penalties that impact both parties and, as a condition precedent, we purchased a surety bond in support of our obligations under the agreement.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Other Minimum Commitments.In the first quarter 2001, we acquired the DNE power
generation facilities. These facilities consist of a combination of baseload, intermediate and peaking facilities aggregating approximately 1,700 MWs. The facilities are approximately 50 miles north of New York City and were acquired for
approximately $903 million cash, plus inventory and certain working capital adjustments. In May 2001, two of our subsidiaries completed a sale-leaseback transaction to provide term financing for the DNE facilities. Under the terms of the
sale-leaseback transaction, our subsidiaries sold plants and equipment and agreed to lease them back for terms expiring within 34 years, exclusive of renewal options.



Minimum commitments in connection with office space, equipment, plant sites and other leased assets, including the DNE
sale-leaseback transaction discussed above, at December 31, 2004, were as follows: 2005-$92 million; 2006-$93 million; 2007-$140 million; 2008-$158 million; 2009-$161 million and beyond-$975 million.



Rental payments made under the terms of these arrangements totaled $82
million in 2004, $78 million in 2003 and $90 million in 2002.



We are party to two charter party agreements relating to VLGCs previously utilized in our global liquids business. The aggregate minimum base commitments of the charter party agreements are approximately $13 million each year for the years
2005 through 2007, and approximately $79 million through lease expiration. The charter party rates payable under the two charter party agreements float in accordance with market based rates for similar shipping services. The $13 million and $79
million numbers set forth above are based on the minimum obligations set forth in the two charter party agreements. The primary term of one charter is through August 2013 while the primary term of the second charter is through August 2014. On
January 1, 2003, in connection with the sale of our global liquids business, we sub-chartered both VLGCs to a wholly owned subsidiary of Transammonia Inc. The terms of the sub-charters are identical to the terms of the original charter agreements.
We are currently in negotiations with the owners of the VLGCs and their lenders to obtain a novation and release of our operating subsidiary from the two charter party agreements and a partial release of our parent guarantees. Until such time as the
novations and partial releases are granted, we continue to rely on the sub-charters with a subsidiary of Transammonia to satisfy the obligations of our two charter party agreements. To date, the subsidiary of Transammonia has complied with the terms
of the sub-charter agreements.



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.



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



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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



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



Through one of our subsidiaries, we hold a 50% ownership interest in Nevada Cogeneration Associates #2. Nevada Cogeneration, in which our partner is a
ChevronTexaco subsidiary, 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 Nevada Cogeneration
receives payments which decrease in amount over time, we agreed to guarantee 50% of certain payments that may be due to the purchaser under a mechanism designed to protect it from early termination of the agreement. At December 31, 2004, 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 purchaser $45 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.



Note 15Regulatory Issues



We are subject to regulation by various federal, state, local and foreign
agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with
these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations.
In addition, the U.S. Congress 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.



Danskammer
Water Permit. Our wastewater discharges are permitted under the Clean Water Act and analogous state laws. These permits are subject to review every five years. The state-issued water discharge permits associated with the DNE facilities
expired in 1992. However, under New York State law, the authorization arising under these permits remains in effect and allows for continued operation under the terms of the original permit, provided that a timely and sufficient application
requesting renewal has been filed as required. In May 1992, the then owner of the Danskammer facility filed a renewal application which we believe was timely and sufficient. In November 2002, several environmental groups filed suit in the Supreme
Court of the State of New York seeking, among other things, a declaratory judgment that the Danskammer water intake and discharge permit expired because of alleged deficiencies in the renewal application process. In September 2004, the Court ruled
that the water intake and discharge permit for our Danskammer facility is void, but stayed the enforcement of the decision pending further review by the Court or by the Appellate Division.



In October 2004, we filed our appeal of the Courts decision with the
Appellate Division, and we intend to pursue vigorously our challenge to the Courts ruling voiding our permit. We will also continue to seek approval



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



of our application to renew the water intake and discharge permit in proceedings before the New York State Department of Environmental Conservation. If our
appeal is ultimately unsuccessful, we may be required to suspend operations at our Danskammer facility pending receipt of final approval of the renewal of our water intake and discharge permit. We cannot predict with any certainty the outcome of
these proceedings; however, an adverse outcome, particularly a requirement that we suspend operations at our Danskammer facility for any period of time, could have a material adverse effect on our financial condition, results of operations and cash
flows.



FERC Market-Based Rate Authority. The
FERCs market-based rate authority allows the sale of power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic re-review. In April 2004, the FERC issued an order concerning the ability
of companies to sell electricity at market-based rates. In this order, the FERC adopted two new tests for assessing generation market power. If an applicant for market-based rate authority is found to possess generation market power under these
tests and is unsuccessful in challenging that finding, the applicant may either propose mitigation measures or adopt cost-based rates. If the FERC finds that the proposed mitigation measures fail to eliminate the ability to exercise market power,
the applicants market-based rate authority will be revoked and the applicant will be subject to cost-based default rates, or other cost-based rates proposed by the applicant and approved by the FERC. The FERC issued a follow up order in May
2004, which it upheld in July 2004, (i) addressing the implementation process for pending and new market-based rate applications and (ii) establishing a timeline for entities with FERC market-based rate authority to provide the FERC with their
market power assessment. These orders required entities that were previously granted market- based rate authority by the FERC, including entities with pending applications for re-review, to resubmit their applications in accordance with the new
directive. Consequently, our entities with applications pending since February 2002 timely resubmitted their applications to the FERC.



In December 2004, the FERC ruled that once the Midwest Independent System Operator, Inc., or MISO, becomes a single market and performs functions such as
single central commitment and dispatch with FERC-approved market monitoring and mitigation (currently scheduled for April 2005), MISO would be considered to have a single geographic market for purposes of assessing generation market power. This
ruling will enlarge the geographic area in which our DMG facilities would be evaluated for generation market power for the relevant period. Although we cannot predict with any certainty whether our applications to renew our market based rate
authority will be approved or the loss of revenues that would result from the imposition of cost-based rates, an adverse outcome with respect to these applications, and the resulting requirement that we charge cost-based rates, could have a material
adverse effect on our financial condition, results of operations and cash flows.



Note 16Capital Stock



All of our
outstanding equity securities are held by our parent, Dynegy Inc. There is no established trading market for such securities, and they are not traded on any exchange.



Restricted Stock.During the first and second quarter 2004, we awarded an aggregate 911,729 shares of
restricted stock. The closing stock price of our Class A common stock was $4.48 and $3.85, respectively on the dates of grants. These restricted shares vest on the third anniversary from the date of grant. In years prior to 2002, we awarded 47,088
shares of restricted stock, of which 21,392 were outstanding, but not vested, at December 31, 2004. The shares awards were awarded pursuant to the terms of the Dynegy 2000 and 2001 Non-Executive Plans, which are described in Stock
Options below.



Stock Options.Dynegy has
seven stock option plans in which our employees participate, all of which contain authorized shares of Dynegys Class A common stock. Each option granted is exercisable at an option



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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



| |  |  | 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 ten-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. Options awarded to our executive officers and others who participate in Dynegys Executive Severance Pay Plan vest immediately upon the
occurrence of a change in control in accordance with the terms of the Second Supplemental Amendment to the Executive Severance Pay Plan.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Compensation expense related to options granted and restricted stock awarded totaled $6 million, $3
million and $11 million for the years ended December 31, 2004, 2003 and 2002, respectively. We recognize compensation expense ratably over the vesting period of the respective awards. Of the total compensation expense recognized for the year ended
December 31, 2002, $1 million related to the extension of the exercise period and acceleration of vesting for various stock options associated with divestitures of certain operations and provisions of certain executive employment agreements. No
accelerated compensation expense recognition occurred during the years ended December 31, 2004 and 2003. Total options outstanding and exercisable for 2004, 2003 and 2002 were as follows:



|                                                                           |  |                         |   |      |                                 |       |         |         |   |                                |   |         |  |        |                                |  |   |      
|-------------------------------------------------------------------------- |  | ----------------------- | - | ---- | ------------------------------- | ----- | ------- | ------- | - | ------------------------------ | - | ------- |  | ------ | ------------------------------ |  | - | -----
|                                                                           |  | Year Ended December 31,
|                                                                           |  | 2004                    |   | 2003 |                                 | 2002 
|                                                                           |  | Options                 |   |      | Weighted Average Exercise Price |       | Options |         |   | Weighted Average ExercisePrice |   | Options |  |        | Weighted Average ExercisePrice
|                                                                           |  | (options in thousands) 
|Outstanding at beginning of period                                         |  | 15,501                  |   |      | $                               | 18.50 |         | 26,850  |   |                                | $ | 20.10   |  | 32,155 |                                |  | $ | 20.72
|Granted                                                                    |  | 1,436                   |   |      | $                               | 4.47  |         | 1,583   |   |                                | $ | 1.78    |  | 2,274  |                                |  | $ | 2.78 
|Exercised                                                                  |  | (1,982                  | ) |      | $                               | 4.65  |         | (1,958  | ) |                                | $ | 2.88    |  | (2,985 | )                              |  | $ | 2.80 
|Cancelled or expired                                                       |  | (4,270                  | ) |      | $                               | 24.72 |         | (10,974 | ) |                                | $ | 24.03   |  | (4,594 | )                              |  | $ | 26.95
|                                                                           |  |                         |   |      |                                 |       |         |         |   |                                |   |         |  |        |                                |  |   |      
|Outstanding at end of period                                               |  | 10,685                  |   |      | $                               | 17.44 |         | 15,501  |   |                                | $ | 18.50   |  | 26,850 |                                |  | $ | 20.10
|                                                                           |  |                         |   |      |                                 |       |         |         |   |                                |   |         |  |        |                                |  |   |      
|Exercisable at end of period                                               |  | 7,856                   |   |      | $                               | 22.27 |         | 11,416  |   |                                | $ | 21.12   |  | 14,163 |                                |  | $ | 18.08
|                                                                           |  |                         |   |      |                                 |       |         |         |   |                                |   |         |  |        |                                |  |   |      
|Weighted average fair value of options granted during the period at market |  |                         |   |      | $                               | 4.47  |         |         |   |                                | $ | 1.55    |  |        |                                |  | $ | 0.61 
|                                                                           |  |                         |   |      |                                 |       |         |         |   |                                |   |         |  |        |                                |  |   |      



During the three-year
period ended December 31, 2004, we granted no options at an exercise price less than the market price on the date of grant.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Options outstanding as of December 31, 2004 are summarized below:



|                         |  |                                                 |  |                                                     |  |                                 |       |                                                 |       |                                 |   |      
|------------------------ |  | ----------------------------------------------- |  | --------------------------------------------------- |  | ------------------------------- | ----- | ----------------------------------------------- | ----- | ------------------------------- | - | -----
|                         |  | Options Outstanding                             |  | Options Exercisable                                
|Range of Exercise Prices |  | Number ofOptionsOutstanding at December 31,2004 |  | Weighted Average Remaining Contractual Life (Years) |  | Weighted Average Exercise Price |       | Number ofOptionsExercisable at December 31,2004 |       | Weighted Average Exercise Price
|                         |  | (options in thousands)                         
|$0.88-$2.15              |  | 2,539                                           |  | 7.8                                                 |  | $                               | 1.30  |                                                 | 1,058 |                                 | $ | 1.20 
|$2.16-$5.15              |  | 1,909                                           |  | 7.4                                                 |  | $                               | 4.37  |                                                 | 582   |                                 | $ | 4.14 
|$5.16-$11.59             |  | 749                                             |  | 4.0                                                 |  | $                               | 9.75  |                                                 | 736   |                                 | $ | 9.79 
|$11.60-$23.18            |  | 1,218                                           |  | 4.4                                                 |  | $                               | 15.87 |                                                 | 1,215 |                                 | $ | 15.88
|$23.19-$23.98            |  | 1,996                                           |  | 6.8                                                 |  | $                               | 23.79 |                                                 | 1,996 |                                 | $ | 23.79
|$23.99-$34.77            |  | 670                                             |  | 6.7                                                 |  | $                               | 33.92 |                                                 | 665   |                                 | $ | 33.97
|$34.78-$40.57            |  | 149                                             |  | 6.2                                                 |  | $                               | 37.52 |                                                 | 149   |                                 | $ | 37.52
|$40.58-$46.36            |  | 78                                              |  | 6.1                                                 |  | $                               | 43.80 |                                                 | 78    |                                 | $ | 43.80
|$46.37-$52.16            |  | 1,308                                           |  | 6.1                                                 |  | $                               | 47.26 |                                                 | 1,308 |                                 | $ | 47.26
|$52.17-$57.95            |  | 69                                              |  | 6.2                                                 |  | $                               | 55.95 |                                                 | 69    |                                 | $ | 55.95
|                         |  |                                                 |  |                                                     |  |                                 |       |                                                 |       |                                 |   |      
|                         |  | 10,685                                          |  |                                                     |  |                                 |       |                                                 | 7,856 |                                 |   |      
|                         |  |                                                 |  |                                                     |  |                                 |       |                                                 |       |                                 |   |      



The fair value of each
option grant was estimated on the date of grant using the Black-Scholes option-pricing model, with the following weighted-average assumptions used for grants in 2004, 2003 and 2002: dividends per year of zero for 2004 and 2003 and $0.15 for 2002;
expected volatility of 87.5%, 89.6%, and 74.3%, respectively; a risk-free interest rate of 4.1%, 3.9%, and 4.2%, respectively; and an expected option life of 10 years for all periods.



Note 17Employee Compensation, Savings and Pension Plans



Short-Term Incentive Plan. We maintain a discretionary incentive compensation plan to provide employees with
rewards for the achievement of corporate goals and individual, professional accomplishments. Specific awards are at the discretion of the Compensation and Human Resources Committee of the Board of Directors.



In addition, in 2003, Dynegy adopted the Mid-Term Incentive Plan. This
special compensation program is limited to select employees who are eligible to receive cash compensation of up to 200% of their annual base salary, payable in two installments over a two-year period, based on the performance of Dynegys Class
A common stock during the last 30 trading days in 2004 and over the entire year in 2005. The first performance period ended December 31, 2004. The first installment in the aggregate amount of approximately $0.6 million was approved by Dynegys
Compensation and Human Resources Committee of the Board of Directors and will be paid during the first quarter 2005. We account for this cash plan using variable plan accounting and recognized an aggregate amount of approximately $1 million in
compensation expense during 2004 and 2003 associated with the plan.



401(k) Savings Plan. During the 12-months ended December 31, 2004, our employees participated in four 401(k) savings plans, all of which meet the requirements of Section 401(k) of the Internal Revenue Code and are defined
contribution plans subject to the provisions of ERISA. The following summarizes the plans:



| |  |  | Dynegy Inc. 401(k) Savings Planthis plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the
United States. All employees of designated Dynegy subsidiaries are eligible to participate in the plan. Employee pre-tax contributions to the plan
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



| | are matched 100%, up to a maximum of 5% of base pay, subject to IRS limitations. Vesting in our contributions is based on years of service at 25% per full
year of service. Dynegy may also make annual discretionary contributions to employee accounts, subject to its performance. Matching and discretionary contributions, if any, are allocated in the form of units in the Dynegy common stock fund. During
the years ended December 31, 2004, 2003 and 2002, we issued approximately 1 million, 1.8 million and 2.7 million shares, respectively, of Dynegy common stock in the form of matching contributions to fund the plan. No discretionary contributions were
made for any of the years in the three-year period ended December 31, 2004;
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Dynegy Midwest Generation, Inc. 401(K) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan) and Dynegy Midwest Generation, Inc. 401(K) Savings Plan for
Employees Covered Under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered Under A Collective Bargaining Agreement)we match 50% of employee contributions to the plans, up to a
maximum of 6% of compensation, subject to IRS limitations. Employees are immediately 100% vested in our contributions. Matching contributions to the plans are allocated in the form of units in the Dynegy common stock fund. During the years ended
December 31, 2004, 2003 and 2002, we issued 0.6 million, 1.2 million and 1.1 million shares, respectively, of Dynegys common stock in the form of matching contributions to the plans; and
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Dynegy Northeast Generation, Inc. Savings Incentive Planunder this plan, which is for union and non-union employees, we match 24% of employee contributions up to 6% of base
salary for union employees and 50% of employee contributions up to 8% of base salary for non-union employees, in each case subject to IRS limitations. Employees are immediately 100% vested in our contributions. Matching contributions to this plan
are made in cash and invested according to the employee investment discretion.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



During the years ended December 31, 2004, 2003 and 2002, we recognized aggregate costs related to these employee compensation plans of $5 million, $5 million and $10 million, respectively.



Pension and Other Post-Retirement Benefits.



We have various defined benefit pension plans and post-retirement benefit
plans. All domestic employees participate in the pension plans, but only some of our domestic employees participate in the other post-retirement medical and life insurance benefit plans. Our pension plans are in the form of a cash balance plan and
more traditional career average or final average pays formula plans. We use a December 31 measurement date for all of our plans.



Prior to September 30, 2004, our employees and other Dynegy employees were participants in various defined benefit pension plans and post-retirement
benefit plans. We accounted for these plans as multiemployer plans, and as such, the applicable portions of the plans accrued benefit liabilities and fair value of the plan assets were not recorded on our balance sheets. However, as a result
of Dynegys sale of Illinois Power to Ameren, the number of participants in Dynegys various defined benefit pension plans and post-retirement benefit plans was reduced substantially. As of October 1, 2004, all participants in the plans
are our employees. As a result, we transferred the remaining balance of the plans accrued benefit liabilities and fair value of the plan assets to our balance sheets as of September 30, 2004. Considering the transfer, during the years ended
December 31, 2004, 2003 and 2002, we recognized pension expense for these plans totaling approximately $15 million, $12 million and $9 million, respectively.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Obligations and Funded Status. The following tables contain information about the
obligations and funded status of these plans on a combined basis:



|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|--------------------------------------------------- |  | ---------------- | --- | - | -------------- | - | --- | ---- |  | - | ---- | - |  | - | --- | -
|                                                    |  | Pension Benefits |     |   | Other Benefits |  
|                                                    |  | 2004             |     |   | 2003           |   |     | 2004 |  |   | 2003 |  
|                                                    |  | (in millions)    |    
|Projected benefit obligation, beginning of the year |  | $                | 42  |   |                | $ | 35  |      |  | $ | 12   |   |  | $ | 10  |  
|Service cost                                        |  |                  | 4   |   |                |   | 2   |      |  |   | 1    |   |  |   |    |  
|Interest cost                                       |  |                  | 4   |   |                |   | 2   |      |  |   | 1    |   |  |   | 1   |  
|Actuarial (gain) loss                               |  |                  | 4   |   |                |   | 4   |      |  |   |     |   |  |   | 1   |  
|Transfer due to sale of Illinois Power              |  |                  | 100 |   |                |   |    |      |  |   | 32   |   |  |   |    |  
|Benefits paid                                       |  |                  | (1  | ) |                |   | (1  | )    |  |   |     |   |  |   |    |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Projected benefit obligation, end of the year       |  | $                | 153 |   |                | $ | 42  |      |  | $ | 46   |   |  | $ | 12  |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Fair value of plan assets, beginning of the year    |  | $                | 29  |   |                | $ | 25  |      |  | $ |     |   |  | $ |    |  
|Actual return on plan assets                        |  |                  | 7   |   |                |   | 5   |      |  |   |     |   |  |   |    |  
|Transfer due to sale of Illinois Power              |  |                  | 52  |   |                |   |    |      |  |   |     |   |  |   |    |  
|Benefits paid                                       |  |                  | (1  | ) |                |   | (1  | )    |  |   |     |   |  |   |    |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Fair value of plan assets, end of the year          |  | $                | 87  |   |                | $ | 29  |      |  | $ |     |   |  | $ |    |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Funded status                                       |  | $                | (66 | ) |                | $ | (13 | )    |  | $ | (46  | ) |  | $ | (12 | )
|Unrecognized prior service costs                    |  |                  | 6   |   |                |   |    |      |  |   |     |   |  |   |    |  
|Unrecognized actuarial (gain) loss                  |  |                  | 46  |   |                |   | 10  |      |  |   | 21   |   |  |   | 4   |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Net amount recognized $                             |  | $                | (14 | ) |                | $ | (3  | )    |  | $ | (25  | ) |  | $ | (8  | )
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  



Amounts recognized in
the consolidated balance sheets consist of:



|                                       |  |                 |     |   |                |   |    |      |  |   |      |   |  |   |    |  
|-------------------------------------- |  | --------------- | --- | - | -------------- | - | -- | ---- |  | - | ---- | - |  | - | -- | -
|                                       |  | PensionBenefits |     |   | Other Benefits |  
|                                       |  | December 31,    |     |   | December 31,   |  
|                                       |  | 2004            |     |   | 2003           |   |    | 2004 |  |   | 2003 |  
|                                       |  | (in millions)   |    
|Accrued benefit liability              |  | $               | (40 | ) |                | $ | (7 | )    |  | $ | (25  | ) |  | $ | (8 | )
|Intangible asset                       |  |                 | 6   |   |                |   |   |      |  |   |     |   |  |   |   |  
|Accumulated other comprehensive income |  |                 | 20  |   |                |   | 4  |      |  |   |     |   |  |   |   |  
|                                       |  |                 |     |   |                |   |    |      |  |   |      |   |  |   |    |  
|Net amount recognized                  |  | $               | (14 | ) |                | $ | (3 | )    |  | $ | (25  | ) |  | $ | (8 | )
|                                       |  |                 |     |   |                |   |    |      |  |   |      |   |  |   |    |  



The accumulated
benefit obligation for all defined benefit pension plans was $125 million and $34 million at December 31, 2004 and 2003, respectively.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



On December 31, 2004 and December 31, 2003, our annual measurement date, the accumulated benefit
obligation related to certain of our pension plans exceeded the fair value of the pension plan assets. As a result, in accordance with SFAS No. 87, Employers Accounting for Pensions, we have recorded a minimum pension liability,
with an offset to accumulated other comprehensive loss. The following summarizes information for pension plans with an accumulated benefit obligation in excess of plan assets:



|                               |  |               |     |      |   |   
|------------------------------ |  | ------------- | --- | ---- | - | --
|                               |  | December 31, 
|                               |  | 2004          |     | 2003
|                               |  | (in millions)
|Projected benefit obligation   |  | $             | 153 |      | $ | 42
|Accumulated benefit obligation |  |               | 125 |      |   | 34
|Fair value of plan assets      |  |               | 88  |      |   | 29



The following
summarizes the change to accumulated other comprehensive income (loss) associated with the minimum pension liability:



|                                                                                                                                                            |  |               |     |   |      |   |      |  |   |    |  
|----------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------- | --- | - | ---- | - | ---- |  | - | -- | -
|                                                                                                                                                            |  | 2004          |     |   | 2003 |   | 2002 | 
|                                                                                                                                                            |  | (in millions) |    
|Change in minimum liability included in other comprehensive income / (loss) (net of tax benefit (expense) of $5 million, zero and $2 million,
respectively) |  | $             | (10 | ) |      | $ |     |  | $ | (3 | )



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



|                                              |  |                  |    |   |                |   |    |      |  |   |      |   |      |   |      |  |   |   |  |   |  
|--------------------------------------------- |  | ---------------- | -- | - | -------------- | - | -- | ---- |  | - | ---- | - | ---- | - | ---- |  | - | - |  | - | -
|                                              |  | Pension Benefits |    |   | Other Benefits
|                                              |  | 2004             |    |   | 2003           |   |    | 2002 |  |   | 2004 |   | 2003 |   | 2002
|                                              |  | (in millions)   
|Service cost benefits earned during period    |  | $                | 4  |   |                | $ | 1  |      |  | $ | 1    |   |      | $ | 1    |  | $ | 1 |  | $ | 
|Interest cost on projected benefit obligation |  |                  | 4  |   |                |   | 2  |      |  |   | 2    |   |      |   | 1    |  |   | 1 |  |   | 1
|Expected return on plan assets                |  |                  | (4 | ) |                |   | (2 | )    |  |   | (3   | ) |      |   |     |  |   |  |  |   | 
|Recognized net actuarial loss                 |  |                  | 1  |   |                |   | 1  |      |  |   |     |   |      |   | 1    |  |   |  |  |   | 
|                                              |  |                  |    |   |                |   |    |      |  |   |      |   |      |   |      |  |   |   |  |   |  
|Total net periodic benefit cost               |  | $                | 5  |   |                | $ | 2  |      |  | $ |     |   |      | $ | 3    |  | $ | 2 |  | $ | 1
|                                              |  |                  |    |   |                |   |    |      |  |   |      |   |      |   |      |  |   |   |  |   |  



Assumptions.The following weighted average assumptions were used to determine benefit obligations:



|                              |  |                  |   |  |                |   |  |      |   |  |      |  
|----------------------------- |  | ---------------- | - |  | -------------- | - |  | ---- | - |  | ---- | -
|                              |  | Pension Benefits |   |  | Other Benefits |  
|                              |  | December 31,     |   |  | December 31,   |  
|                              |  | 2004             |   |  | 2003           |   |  | 2004 |   |  | 2003 |  
|Discount rate                 |  | 5.75             | % |  | 6.00           | % |  | 5.75 | % |  | 6.00 | %
|Rate of compensation increase |  | 4.50             | % |  | 4.50           | % |  | 4.50 | % |  | 4.50 | %



The following weighted
average assumptions were used to determine net periodic benefit cost:



|                               |  |                         |   |  |                         |   |  |      |   |  |      |   |  |      |   |  |      |  
|------------------------------ |  | ----------------------- | - |  | ----------------------- | - |  | ---- | - |  | ---- | - |  | ---- | - |  | ---- | -
|                               |  | Pension Benefits        |   |  | Other Benefits          |  
|                               |  | Year Ended December 31, |   |  | Year Ended December 31, |  
|                               |  | 2004                    |   |  | 2003                    |   |  | 2002 |   |  | 2004 |   |  | 2003 |   |  | 2002 |  
|Discount rate                  |  | 5.98                    | % |  | 6.50                    | % |  | 7.50 | % |  | 5.99 | % |  | 6.50 | % |  | 7.50 | %
|Expected return on plan assets |  | 8.75                    | % |  | 9.00                    | % |  | 9.50 | % |  | 8.75 | % |  | 9.00 | % |  | 9.50 | %
|Rate of compensation increase  |  | 4.50                    | % |  | 4.50                    | % |  | 4.50 | % |  | 4.50 | % |  | 4.50 | % |  | 4.50 | %



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Our expected long-term rate of return on plan assets for the year ended December 31, 2005 will be
8.25%. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between
equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long-term. Current market factors such as inflation and interest rates are
also incorporated in the assumptions. The figure also incorporates an upward adjustment reflecting the plans use of active management and favorable past experience.



The following summarizes our assumed health care cost trend rates:



|                                                   |  |              |   |  |      |  
|-------------------------------------------------- |  | ------------ | - |  | ---- | -
|                                                   |  | December 31, |  
|                                                   |  | 2004         |   |  | 2003 |  
|Health care cost trend rate assumed for next year  |  | 10.1         | % |  | 11.0 | %
|Ultimate trend rate                                |  | 5.36         | % |  | 5.00 | %
|Year that the rate reaches the ultimate trend rate |  | 2011         |   |  | 2016 |  



Assumed health care
cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows:



|                                                         |  |               |     |          |   |      |  
|-------------------------------------------------------- |  | ------------- | --- | -------- | - | ---- | -
|                                                         |  | Increase      |     | Decrease |  
|                                                         |  | (in millions) |    
|Aggregate impact on service cost and interest cost       |  | $             | 0.9 |          | $ | (0.8 | )
|Impact on accumulated post-retirement benefit obligation |  | $             | 7.5 |          | $ | (6.3 | )



Plan Assets.We employ a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan
expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status, and corporate financial condition. The investment portfolio contains a diversified
blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalization. Other assets such as real estate and private equity may be
used judiciously to enhance long-term returns while improving portfolio diversification.



Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk
is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies, and annual liability measurement.



Our pension plans weighted-average asset allocations by asset category were as follows:



|                  |  |              |   |  |      |  
|----------------- |  | ------------ | - |  | ---- | -
|                  |  | December 31, |  
|                  |  | 2004         |   |  | 2003 |  
|Equity securities |  | 72           | % |  | 64   | %
|Debt securities   |  | 28           | % |  | 28   | %
|Real estate       |  |             |   |  | 5    | %
|Other             |  |             |   |  | 3    | %
|Total             |  | 100          | % |  | 100  | %



Equity securities did
not include any of Dynegys common stock at December 31, 2004 or 2003.



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##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Our other postretirement benefit plans weighted-average asset allocations by asset category were as
follows:



|                  |  |              |  |      |  
|----------------- |  | ------------ |  | ---- | -
|                  |  | December 31, | 
|                  |  | 2004         |  | 2003 |  
|Equity securities |  |             |  | 75   | %
|Debt securities   |  |             |  | 25   | %
|                  |  |              |  |      |  
|Total             |  |             |  | 100  | %
|                  |  |              |  |      |  



As of December 31,
2004, our other postretirement benefit plan assets were zero. Equity securities did not include any of Dynegys common stock at December 31, 2003.



Contributions. Under the terms of Dynegys agreement to sell Illinois Power to Ameren, we accelerated approximately $7 million of
future cash funding requirements in September 2004. In 2005, we expect to contribute $28 million to our pension plans and $0.3 million to our other postretirement benefit plans.



Our expected benefit payments for future services for our pension and other postretirement benefits are as follows:



|            |  |                  |      |                |   |     
|----------- |  | ---------------- | ---- | -------------- | - | ----
|            |  | Pension Benefits |      | Other Benefits
|            |  | (in millions)   
|2005        |  | $                | 2.8  |                | $ | 0.3 
|2006        |  |                  | 2.8  |                |   | 0.5 
|2007        |  |                  | 3.8  |                |   | 0.7 
|2008        |  |                  | 4.9  |                |   | 1.0 
|2009        |  |                  | 6.1  |                |   | 1.4 
|2010  2014 |  |                  | 52.5 |                |   | 13.6



Medicare
Prescription Drug, Improvement and Modernization Act of 2003.On December 8, 2003, President Bush signed into law a bill that expands Medicare, primarily adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. We
anticipate that the benefits that we will pay after 2005 will be lower as a result of the new Medicare provisions. The December 31, 2004 accumulated post-retirement benefit obligation reflects the new Medicare program as required by FASB Staff
Position 106-2. The accumulated postretirement benefit obligation was reduced by approximately $1 million by reflecting the new Medicare prescription drug program.



Note 18Segment Information



Prior period amounts in this footnote have been restated. For further information, please see the Explanatory Note beginning on page F-8.



In 2002, we reported results for the following three business segments: WEN,
DMS and T&D. Beginning January 1, 2003, we are reporting our operations in the following segments: GEN, NGL and CRM. All corporate overhead included in other reported results was allocated to our three former reporting segments prior to January
1, 2003. Beginning January 1, 2003, all direct general and administrative expenses and other income (expense) items incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred. In addition, all interest expense
was allocated to our four former reporting segments prior to January 1, 2003.



Prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business, referred to as the WEN segment. Most, but not all, of the



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



WEN third-party purchase and sale contracts were held by a subsidiary that became part of the CRM segment. Under this previous business model, the net fair
value of most of GENs generation capacity, forward sales and related trading positions were sold to the CRM segment monthly at an internally determined transfer price. The internal transfer price was primarily comprised of the option value of
generation capacity and executed forward sales contracts based on then-current forward prices of power and fuel. GEN intersegment revenues for the year ended December 31, 2002 reflect this internal transfer price and do not represent amounts
actually received for power sold to third parties. As such, the GEN intersegment revenues for the year ended December 31, 2002 do not include the effect of intra-month market price volatility. The CRM segment recorded net unaffiliated revenue from
these third-party contracts, together with all of its other third-party marketing and trading positions unrelated to the GEN segment.



In connection with our exit from the third-party marketing and trading business, individual contracts within the former WEN segment were identified on
January 1, 2003 as either GEN contracts, as they were determined to be part of our continuing operations, or CRM contracts. Under this new business segment model, CRM continued to transact with third parties on behalf of GEN. When transacting on
behalf of GEN and our other segments, CRM would record third party revenue related to GEN and our other segments, together with its other third-party marketing and trading positions unrelated to the our other segments. Transfer pricing between CRM
and our other segments was set at the actual amount received or paid for the purchases and sales to the third parties. Therefore, our other segments intersegment revenues included the effects of intra-month market price volatility, and represented
amounts actually received from or paid to third parties.



Effective July 1, 2004, GEN began transacting directly with third parties on its own behalf. Therefore, certain generation capacity, forward sales, and related market positions previously sold by GEN to CRM are now sold by GEN directly to
third parties. The GEN segment now records revenues for such third party sales as unaffiliated revenues.



Prior to January 1, 2003, consolidated revenue associated with the retail power business represented energy trading activity that was recorded on a net
basis. The GEN segment purchased from the CRM segment a portion of the physical power that was used to fill these retail power sales contracts. The revenues from retail power sales were presented gross in GEN unaffiliated revenues, with the
corresponding power purchases from the CRM segment presented in GEN intersegment revenues. Beginning January 1, 2003, pursuant to the rescission of EITF Issue 98-10, retail power sales are presented gross in consolidated revenue. Any purchases of
physical power by the GEN segment from the CRM segment are classified as cost of sales in the GEN segment and are presented in CRM intersegment revenues. These differences affect the comparability of the results for the years ended December 31,
2004, 2003 and 2002.



Revenues from third-party sales in which
a GEN entity is the legal party to the third-party sales contracts are presented gross in GEN unaffiliated revenues for the years ended December 31, 2004, 2003 and 2002.



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



Prior to January 1, 2003, our natural gas liquids operations
comprised our DMS segment. Beginning January 1, 2003, these operations comprise the NGL segment. Additionally, for the first three quarters of 2003 prior to its



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



sale, we reported the operations of Northern Natural in our T&D segment. Such operations have been reclassified to discontinued operations. Reportable
segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2004, 2003 and 2002 is presented below.



Dynegy Holdings Segment Data for the Year Ended December 31, 2004

(in millions)



|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|----------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | ----- | - |  | - | ------ | -
|                                                |  | GEN |       |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |      
|Unaffiliated revenues:                          |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Domestic                                        |  | $   | 702   |   |     | $ | 3,450 |     |  | $ | 931                   |   |  | $     |      |   |  | $ | 5,083  |  
|Other                                           |  |     |      |   |     |   | 3     |     |  |   | (87                   | ) |  |       |      |   |  |   | (84    | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|                                                |  |     | 702   |   |     |   | 3,453 |     |  |   | 844                   |   |  |       |      |   |  |   | 4,999  |  
|Affiliate revenues                              |  |     | 352   |   |     |   |      |     |  |   |                      |   |  |       |      |   |  |   | 352    |  
|Intersegment revenues                           |  |     | 528   |   |     |   | 300   |     |  |   | (672                  | ) |  |       | (156  | ) |  |   |       |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Total revenues                                  |  | $   | 1,582 |   |     | $ | 3,753 |     |  | $ | 172                   |   |  | $     | (156  | ) |  | $ | 5,351  |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Depreciation and amortization                   |  | $   | (190  | ) |     | $ | (88   | )   |  | $ | (1                    | ) |  | $     | (33   | ) |  | $ | (312   | )
|Impairment and other charges                    |  |     |      |   |     |   | (5    | )   |  |   |                      |   |  |       | (24   | ) |  |   | (29    | )
|Operating income (loss)                         |  | $   | 162   |   |     | $ | 287   |     |  | $ | (118                  | ) |  | $     | (275  | ) |  | $ | 56     |  
|Earnings from unconsolidated investments        |  |     | 116   |   |     |   | 10    |     |  |   |                      |   |  |       |      |   |  |   | 126    |  
|Other items, net                                |  |     |      |   |     |   | (22   | )   |  |   | (3                    | ) |  |       | 8     |   |  |   | (17    | )
|Interest expense                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   | (359   | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Loss from continuing operations before taxes    |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   | (194   | )
|Income tax benefit                              |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   | 97     |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Loss from continuing operations                 |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   | (97    | )
|Loss from discontinued operations, net of taxes |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   | (7     | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Net loss                                        |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  | $ | (104   | )
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Identifiable assets:                            |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Domestic                                        |  | $   | 5,484 |   |     | $ | 2,018 |     |  | $ | 312                   |   |  | $     | 1,578 |   |  | $ | 9,392  |  
|Other                                           |  |     |      |   |     |   | 5     |     |  |   | 749                   |   |  |       | 12    |   |  |   | 766    |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Total                                           |  | $   | 5,484 |   |     | $ | 2,023 |     |  | $ | 1,061                 |   |  | $     | 1,590 |   |  | $ | 10,158 |  
|                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |       |   |  |   |        |  
|Unconsolidated investments                      |  | $   | 336   |   |     | $ | 78    |     |  | $ |                      |   |  | $     |      |   |  | $ | 414    |  
|Capital expenditures                            |  | $   | (145  | ) |     | $ | (61   | )   |  | $ |                      |   |  | $     | (13   | ) |  | $ | (219   | )



F-66



---

##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Dynegy Holdings Segment Data for the Year Ended December 31, 2003

(in millions)



|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|------------------------------------------------------------------ |  | --- | ----- | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ------ | -
|                                                                   |  | GEN |       |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |     
|Unaffiliated revenues:                                             |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                           |  | $   | 352   |   |     | $ | 2,999 |     |  | $ | 840                   |   |  | $     |     |   |  | $ | 4,191  |  
|Other                                                              |  |     |      |   |     |   | 3     |     |  |   | (49                   | ) |  |       |     |   |  |   | (46    | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|                                                                   |  |     | 352   |   |     |   | 3,002 |     |  |   | 791                   |   |  |       |     |   |  |   | 4,145  |  
|Affiliate revenues                                                 |  |     | 472   |   |     |   |      |     |  |   | 97                    |   |  |       |     |   |  |   | 569    |  
|Intersegment revenues                                              |  |     | 783   |   |     |   | 250   |     |  |   | (1,015                | ) |  |       | (18  | ) |  |   |       |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total revenues                                                     |  | $   | 1,607 |   |     | $ | 3,252 |     |  | $ | (127                  | ) |  | $     | (18  | ) |  | $ | 4,714  |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Depreciation and amortization                                      |  | $   | (185  | ) |     | $ | (81   | )   |  | $ |                      |   |  | $     | (64  | ) |  | $ | (330   | )
|Operating income (loss)                                            |  | $   | 198   |   |     | $ | 170   |     |  | $ | (385                  | ) |  | $     | (238 | ) |  | $ | (255   | )
|Earnings (losses) from unconsolidated investments                  |  |     | 136   |   |     |   | (2    | )   |  |   | (2                    | ) |  |       |     |   |  |   | 132    |  
|Other items, net                                                   |  |     | 1     |   |     |   | (17   | )   |  |   | 31                    |   |  |       | (9   | ) |  |   | 6      |  
|Interest expense                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (338   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Loss from continuing operations before taxes                       |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (455   | )
|Income tax benefit                                                 |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 191    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Loss from continuing operations                                    |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (264   | )
|Loss from discontinued operations, net of taxes                    |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (12    | )
|Cumulative effect of change in accounting principles, net of taxes |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 42     |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Net loss                                                           |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  | $ | (234   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Identifiable assets:                                               |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                           |  | $   | 4,933 |   |     | $ | 1,784 |     |  | $ | 1,863                 |   |  | $     | 887  |   |  | $ | 9,467  |  
|Other                                                              |  |     |      |   |     |   | (25   | )   |  |   | 807                   |   |  |       | 44   |   |  |   | 826    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total                                                              |  | $   | 4,933 |   |     | $ | 1,759 |     |  | $ | 2,670                 |   |  | $     | 931  |   |  | $ | 10,293 |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Unconsolidated investments                                         |  | $   | 495   |   |     | $ | 82    |     |  | $ |                      |   |  | $     |     |   |  | $ | 577    |  
|Capital expenditures and investments in unconsolidated affiliates  |  | $   | (151  | ) |     | $ | (51   | )   |  | $ | (2                    | ) |  | $     | (5   | ) |  | $ | (209   | )



F-67



---

##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Dynegy Holdings Segment Data for the Year Ended December 31, 2002

(in millions)



|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|----------------------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | ---------------------- | - |  | ----- | ---- | - |  | - | ------ | -
|                                                                  |  | GEN |       |   | NGL |   |       | CRM |  |   | Other and Eliminations |   |  | Total |     
|Unaffiliated revenues:                                            |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Domestic                                                          |  | $   | 379   |   |     | $ | 2,530 |     |  | $ | 308                    |   |  | $     |     |   |  | $ | 3,217  |  
|Other                                                             |  |     |      |   |     |   | 723   |     |  |   | (181                   | ) |  |       |     |   |  |   | 542    |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|                                                                  |  |     | 379   |   |     |   | 3,253 |     |  |   | 127                    |   |  |       |     |   |  |   | 3,759  |  
|Goodwill impairment                                               |  |     | 486   |   |     |   |      |     |  |   |                       |   |  |       |     |   |  |   | 486    |  
|Intersegment revenues                                             |  |     | 434   |   |     |   | 165   |     |  |   | (258                   | ) |  |       | (341 | ) |  |   |       |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Total revenues                                                    |  | $   | 1,299 |   |     | $ | 3,418 |     |  | $ | (131                   | ) |  | $     | (341 | ) |  | $ | 4,245  |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Depreciation and amortization                                     |  | $   | (154  | ) |     | $ | (88   | )   |  | $ | (28                    | ) |  | $     |     |   |  | $ | (270   | )
|Goodwill impairment                                               |  |     | (315  | ) |     |   |      |     |  |   | (325                   | ) |  |       |     |   |  |   | (640   | )
|Impairment and other charges                                      |  |     | (71   | ) |     |   | (18   | )   |  |   | (95                    | ) |  |       |     |   |  |   | (184   | )
|Operating income (loss)                                           |  | $   | (171  | ) |     | $ | 77    |     |  | $ | (951                   | ) |  | $     |     |   |  | $ | (1,045 | )
|Earnings (losses) from unconsolidated investments                 |  |     | (45   | ) |     |   | 14    |     |  |   | (21                    | ) |  |       |     |   |  |   | (52    | )
|Other items, net                                                  |  |     | 9     |   |     |   | (34   | )   |  |   | (49                    | ) |  |       |     |   |  |   | (74    | )
|Interest expense                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   | (187   | )
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Loss from continuing operations before taxes                      |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   | (1,358 | )
|Income tax benefit                                                |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   | 366    |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Loss from continuing operations                                   |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   | (992   | )
|Loss from discontinued operations, net of taxes                   |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   | (100   | )
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Net loss                                                          |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  | $ | (1,092 | )
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Identifiable assets:                                              |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Domestic                                                          |  | $   | 6,151 |   |     | $ | 2,038 |     |  | $ | 6,034                  |   |  | $     |     |   |  | $ | 14,223 |  
|Other                                                             |  |     | 281   |   |     |   | 5     |     |  |   | 2,012                  |   |  |       |     |   |  |   | 2,298  |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Total                                                             |  | $   | 6,432 |   |     | $ | 2,043 |     |  | $ | 8,046                  |   |  | $     |     |   |  | $ | 16,521 |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                        |   |  |       |      |   |  |   |        |  
|Unconsolidated investments                                        |  | $   | 498   |   |     | $ | 102   |     |  | $ |                       |   |  | $     |     |   |  | $ | 600    |  
|Capital expenditures and investments in unconsolidated affiliates |  | $   | (616  | ) |     | $ | (105  | )   |  | $ | (14                    | ) |  | $     | (11  | ) |  | $ | (746   | )



F-68



---

##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 19Quarterly Financial Information (Unaudited)



Prior period amounts in this footnote have been restated. For further
information, please see the Explanatory Note beginning on page F-8.



The following is a summary of our unaudited quarterly financial information for the years ended December 31, 2004 and 2003:



|                                                                              |  |                                      |       |           |   |       |               |  |   |              |   |  |   |       |  
|----------------------------------------------------------------------------- |  | ------------------------------------ | ----- | --------- | - | ----- | ------------- |  | - | ------------ | - |  | - | ----- | -
|                                                                              |  | Quarter Ended                        |      
|                                                                              |  | March 2004                           |       | June 2004 |   |       | September2004 |  |   | December2004 |  
|                                                                              |  | (in millions, except per share data) |      
|Revenues                                                                      |  | $                                    | 1,327 |           | $ | 1,231 |               |  | $ | 1,387        |   |  | $ | 1,406 |  
|Operating income (loss)                                                       |  |                                      | 53    |           |   | 113   |               |  |   | 57           |   |  |   | (167  | )
|Net income (loss) before cumulative effect of change in accounting principles |  |                                      | 21    |           |   | 17    |               |  |   | (8           | ) |  |   | (134  | )
|Net income (loss)                                                             |  |                                      | 21    |           |   | 17    |               |  |   | (8           | ) |  |   | (134  | )
|                                                                              | 
|                                                                              |  | Quarter Ended                        |      
|                                                                              |  | March 2003                           |       | June 2003 |   |       | September2003 |  |   | December2003 |  
|                                                                              |  | (in millions, except per share data) |      
|Revenues                                                                      |  | $                                    | 1,541 |           | $ | 859   |               |  | $ | 1,115        |   |  | $ | 1,199 |  
|Operating income (loss)                                                       |  |                                      | 129   |           |   | (405  | )             |  |   | 37           |   |  |   | (16   | )
|Net income (loss) before cumulative effect of change in accounting principles |  |                                      | 76    |           |   | (280  | )             |  |   | (14          | ) |  |   | (58   | )
|Net income (loss)                                                             |  |                                      | 133   |           |   | (280  | )             |  |   | (14          | ) |  |   | (73   | )



A synopsis of the
aggregate financial impact of the restatements on the amounts originally reported in Amendment No. 1 to our Annual Report of Form 10-K for the year ended December 31, 2003 is as follows:



RESTATED RESULTS OF OPERATIONS BY QUARTER



|                                                                              |  |               |     |               |   |      |                   |  |   |                  |   |  |   |     |  
|----------------------------------------------------------------------------- |  | ------------- | --- | ------------- | - | ---- | ----------------- |  | - | ---------------- | - |  | - | --- | -
|                                                                              |  | Quarter Ended |    
|                                                                              |  | March 31,2003 |     | June 30, 2003 |   |      | September 30,2003 |  |   | December 31,2003 |  
|                                                                              |  | (in millions) |    
|Net income (loss) before cumulative effect of change in accounting principles |  |               |     |               |   |      |                   |  |   |                  |   |  |   |     |  
|As previously reported                                                        |  | $             | 76  |               | $ | (280 | )                 |  | $ | (14              | ) |  | $ | (64 | )
|Restatement effect                                                            |  |               |    |               |   |     |                   |  |   |                 |   |  |   | 6   |  
|                                                                              |  |               |     |               |   |      |                   |  |   |                  |   |  |   |     |  
|As restated                                                                   |  | $             | 76  |               | $ | (280 | )                 |  | $ | (14              | ) |  | $ | (58 | )
|                                                                              |  |               |     |               |   |      |                   |  |   |                  |   |  |   |     |  
|Net income (loss)                                                             |  |               |     |               |   |      |                   |  |   |                  |   |  |   |     |  
|As previously reported                                                        |  | $             | 133 |               | $ | (280 | )                 |  | $ | (14              | ) |  | $ | (79 | )
|Restatement effect                                                            |  |               |    |               |   |     |                   |  |   |                 |   |  |   | 6   |  
|                                                                              |  |               |     |               |   |      |                   |  |   |                  |   |  |   |     |  
|As restated                                                                   |  | $             | 133 |               | $ | (280 | )                 |  | $ | (14              | ) |  | $ | (73 | )
|                                                                              |  |               |     |               |   |      |                   |  |   |                  |   |  |   |     |  



F-69



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##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



RESTATED SELECTED BALANCE SHEET DATA BY QUARTER



|                       |  |                |        |               |   |                    |  |                   |       |  |   |       |  
|---------------------- |  | -------------- | ------ | ------------- | - | ------------------ |  | ----------------- | ----- |  | - | ----- | -
|                       |  | March 31, 2003 |        | June 30, 2003 |   | September 30, 2003 |  | December 31, 2003 |      
|                       |  | (in millions)  |       
|Total Liabilities      |  |                |        |               |   |                    |  |                   |       |  |   |       |  
|As previously reported |  | $              | 10,224 |               | $ | 8,487              |  | $                 | 7,363 |  | $ | 7,196 |  
|Reclassifications (1)  |  |                |       |               |   |                   |  |                   |      |  |   | (184  | )
|Restatement effect     |  |                |       |               |   |                   |  |                   |      |  |   | 6     |  
|                       |  |                |        |               |   |                    |  |                   |       |  |   |       |  
|As restated            |  | $              | 10,224 |               | $ | 8,487              |  | $                 | 7,363 |  | $ | 7,018 |  
|                       |  |                |        |               |   |                    |  |                   |       |  |   |       |  
|Stockholders Equity   |  |                |        |               |   |                    |  |                   |       |  |   |       |  
|As previously reported |  | $              | 3,508  |               | $ | 3,262              |  | $                 | 3,246 |  | $ | 3,160 |  
|Restatement effect     |  |                |       |               |   |                   |  |                   |      |  |   | (6    | )
|                       |  |                |        |               |   |                    |  |                   |       |  |   |       |  
|As restated            |  | $              | 3,508  |               | $ | 3,262              |  | $                 | 3,246 |  | $ | 3,154 |  
|                       |  |                |        |               |   |                    |  |                   |       |  |   |       |  

---

|(1) | Adjustment to our balances for total liabilities relate to reclassifications of December 31, 2003 balance sheet amounts to conform to the December 31, 2004 balance sheet
presentation.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Note 20Subsequent Events



On January 31, 2005, Dynegy completed the acquisition of ExRes SHC, Inc.,
the parent company of Sithe Energies and Independence. In exchange for $135 million in cash, subject to certain specified purchase price adjustments, 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 and a
gas supply agreement with one of our subsidiaries. Upon completion of this acquisition, our transactions with Independence became related party transactions.



On March 7, 2005, we reached agreement with the EPA regarding our Baldwin Station litigation. Please read Note 14Commitments and
ContingenciesSummary of Material Legal ProceedingsBaldwin Station Litigation beginning on page F-45 for further discussion.



F-70



---

##### Table of Contents

##### Index to Financial Statements

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



DEFINITIONS



As used in this Form 10-K, the abbreviations listed below have the following meanings:



|        |  |                                                                                             
|------- |  | --------------------------------------------------------------------------------------------
|AMP     |  | Automated mitigation procedure                                                              
|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                                                    
|CERCLA  |  | The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
|CFTC    |  | Commodity Futures Trading Commission                                                        
|COSO    |  | Committee of Sponsoring Organizations of the Treadway Commission                            
|CRM     |  | Our customer risk management business segment                                               
|DMG     |  | Dynegy Midwest Generation, Inc                                                              
|DMS     |  | Dynegy Midstream Services                                                                   
|DMT     |  | Dynegy Marketing and Trade                                                                  
|DNE     |  | Dynegy Northeast Generation                                                                 
|DOJ     |  | The Department of Justice                                                                   
|DOT     |  | Department of Transportation                                                                
|DPM     |  | Dynegy Power Marketing Inc                                                                  
|EIOL    |  | Energy Infrastructure Overseas Limited                                                      
|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                             
|EWG     |  | Exempt Wholesale Generators                                                                 
|FASB    |  | Financial Accounting Standards Board                                                        
|FERC    |  | Federal Energy Regulatory Commission                                                        
|FIN     |  | FASB Interpretation                                                                         
|FPA     |  | Federal Power Act of 1935, as amended                                                       
|FTC     |  | U.S. Federal Trade Commission                                                               
|FUCOs   |  | Foreign Utility Companies                                                                   
|GAAP    |  | Generally Accepted Accounting Principles of the United States of America                    
|GEN     |  | Our power generation business segment                                                       
|GCF     |  | Gulf Coast Fractionators                                                                    
|HLPSA   |  | Hazardous Liquid Pipeline Safety Act of 1979, as amended                                    
|ICC     |  | Illinois Commerce Commission                                                                
|ISO     |  | Independent System Operator                                                                 
|KW      |  | Keep-whole                                                                                  
|KWH     |  | Kilowatt hour                                                                               
|LNG     |  | Liquefied natural gas                                                                       
|LPG     |  | Liquefied petroleum gas                                                                     
|MBbls/d |  | Thousands of barrels per day                                                                
|Mcf     |  | Thousand cubic feet                                                                         
|MISO    |  | Midwest ISO Regional Transmission Organization                                              
|MMBtu   |  | Millions of British thermal units                                                           
|MMCFD   |  | Million cubic feet per day                                                                  



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



|      |  |                                                                                  
|----- |  | ---------------------------------------------------------------------------------
|MW    |  | Megawatts                                                                        
|MWh   |  | Megawatt hour                                                                    
|NERC  |  | North American Electric Reliability Council                                      
|NGA   |  | Natural Gas Act of 1938, as amended                                              
|NGL   |  | Our natural gas liquids business segment                                         
|NGPA  |  | Natural Gas Policy Act of 1978, as amended                                       
|NGPSA |  | Natural Gas Pipeline Safety Act of 1968, as amended                              
|NOL   |  | Net operating loss                                                               
|NOV   |  | Notice of Violation issued by the EPA                                            
|NYISO |  | New York Independent System Operator                                             
|NYDEC |  | New York Department of Environmental Conservation                                
|PCAOB |  | Public Company Accounting Oversight Board (United States)                        
|PJM   |  | Pennsylvania-New Jersey-Maryland Interconnection, LLC                            
|POL   |  | Percentage of liquids                                                            
|POP   |  | Percentage of proceeds                                                           
|PRB   |  | Powder River Basin coal                                                          
|PUCT  |  | Public Utility Commission of Texas                                               
|PUHCA |  | The Public Utility Holding Company Act of 1935, as amended                       
|QFs   |  | Qualifying Facilities                                                            
|RCRA  |  | The Resource Conservation and Recovery Act of 1976, as amended                   
|RMR   |  | Reliability Must Run                                                             
|RTO   |  | Regional Transmission Organization                                               
|SEC   |  | U.S. Securities and Exchange Commission                                          
|SFAS  |  | Statement of Financial Accounting Standards                                      
|SPE   |  | Special Purpose Entity                                                           
|T&D   |  | Our former transmission and distribution energy delivery business segment        
|VaR   |  | Value at Risk                                                                    
|VIE   |  | Variable Interest Entity                                                         
|VLGC  |  | Very large gas carrier                                                           
|WECC  |  | Western Electricity Coordinating Council                                         
|WEN   |  | Our former wholesale energy network business segment                             
|WTLPS |  | West Texas LPG Pipeline Limited Partnership, the owner of West Texas LPG Pipeline



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Schedule II



DYNEGY HOLDINGS INC.



VALUATION AND QUALIFYING ACCOUNTS



Years Ended December 31, 2004, 2003 and 2002



|                                             |  |                                |     |                               |   |    |                           |  |   |            |   |  |                          |      |   |  |   |    
|-------------------------------------------- |  | ------------------------------ | --- | ----------------------------- | - | -- | ------------------------- |  | - | ---------- | - |  | ------------------------ | ---- | - |  | - | ---
|                                             |  | Balance at Beginning of Period |     | Charged to Costs and Expenses |   |    | Charged to Other Accounts |  |   | Deductions |   |  | Balance at End of Period
|                                             |  | (in millions)                 
|2004                                         |  |                                |     |                               |   |    |                           |  |   |            |   |  |                          |      |   |  |   |    
|Allowance for doubtful accounts              |  | $                              | 174 |                               | $ | (7 | )                         |  | $ | 4          |   |  | $                        | (2   | ) |  | $ | 169
|Allowance for risk management assets (1)     |  |                                | 11  |                               |   |   |                           |  |   |           |   |  |                          | (5   | ) |  |   | 6  
|Deferred tax asset valuation allowance       |  |                                | 51  |                               |   | 18 |                           |  |   |           |   |  |                          |     |   |  |   | 69 
|2003                                         |  |                                |     |                               |   |    |                           |  |   |            |   |  |                          |      |   |  |   |    
|Allowance for doubtful accounts              |  |                                | 140 |                               |   | 25 |                           |  |   | 31         |   |  |                          | (22  | ) |  |   | 174
|Allowance for risk management assets (1) (2) |  |                                | 244 |                               |   |   |                           |  |   |           |   |  |                          | (233 | ) |  |   | 11 
|Deferred tax asset valuation allowance       |  |                                | 51  |                               |   |   |                           |  |   |           |   |  |                          |     |   |  |   | 51 
|2002                                         |  |                                |     |                               |   |    |                           |  |   |            |   |  |                          |      |   |  |   |    
|Allowance for doubtful accounts              |  |                                | 108 |                               |   | 40 |                           |  |   | (2         | ) |  |                          | (6   | ) |  |   | 140
|Allowance for risk management assets (1)     |  |                                | 248 |                               |   | (4 | )                         |  |   |           |   |  |                          |     |   |  |   | 244
|Deferred tax asset valuation allowance       |  |                                |    |                               |   | 51 |                           |  |   |           |   |  |                          |     |   |  |   | 51 

---

|(1) | Changes in price and credit reserves related to risk management assets are offset in the net mark-to-market income accounts reported in revenues.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Deduction of $233 million primarily relates to the rescission of EITF Issue 98-10, which resulted in changing the accounting for certain tolling arrangements from the mark-to-market
method to the accrual method. As such, the related reserves associated with the mark-to-market value were removed from the allowance for risk management assets.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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WEST COAST POWER LLC



INDEX TO
CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                 |  |     
|------------------------------------------------------------------------------------------------ |  | ----
|                                                                                                 |  | Page
|Consolidated Financial Statements                                                                |  |     
|Report of Independent Registered Public Accounting Firm                                          |  | F-75
|Consolidated Balance Sheets as of December 31, 2004 and 2003                                     |  | F-76
|Consolidated Statements of Operations for the years ended December 31, 2004, 2003 and 2002       |  | F-77
|Consolidated Statements of Changes in Equity for the years ended December 31, 2004, 2003and 2002 |  | F-78
|Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002       |  | F-79
|Notes to Consolidated Financial Statements                                                       |  | F-80



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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM



To the Members of West Coast Power LLC:



In our
opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, members equity and comprehensive income and cash flows present fairly, in all material respects, the financial position of West Coast
Power LLC (the Company) at December 31, 2004 and 2003, and the results of its operations and its cash flows for the three years ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of
America. These financial statements are the responsibility of the Companys management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance
with the Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis for our opinion.



As discussed in Note 9, the Company is the subject of substantial litigation. The Companys ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount
of the resolution of such litigation. The consolidated financial statements do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, Accounting for Contingencies, that
might result from the ultimate resolution of such matters.



As
discussed in Note 2, effective January 1, 2002, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets. As discussed in Note 2, effective January 1, 2003, the
Company adopted the provisions of Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.



/s/    PricewaterhouseCoopers LLP

Houston, Texas

March 11, 2005



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WEST COAST POWER LLC



CONSOLIDATED BALANCE SHEETS

(in thousands)



|                                                                                                 |  |                  |          |   |                  |   |          |  
|------------------------------------------------------------------------------------------------ |  | ---------------- | -------- | - | ---------------- | - | -------- | -
|                                                                                                 |  | December 31,2004 |          |   | December 31,2003 |  
|ASSETS                                                                                           |  |                  |          |   |                  |   |          |  
|Current Assets                                                                                   |  |                  |          |   |                  |   |          |  
|Cash and cash equivalents                                                                        |  | $                | 208,730  |   |                  | $ | 124,245  |  
|Accounts receivable, net of allowance for doubtful accounts of $1,032 and $391,819, respectively |  |                  | 113,794  |   |                  |   | 57,844   |  
|Inventory                                                                                        |  |                  | 21,318   |   |                  |   | 25,626   |  
|Prepaid expenses                                                                                 |  |                  | 52,121   |   |                  |   | 41,000   |  
|Assets from risk-management activities                                                           |  |                  | 33,231   |   |                  |   | 8,740    |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Total Current Assets                                                                             |  |                  | 429,194  |   |                  |   | 257,455  |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Property, Plant and Equipment                                                                    |  |                  | 596,776  |   |                  |   | 610,534  |  
|Accumulated depreciation                                                                         |  |                  | (203,060 | ) |                  |   | (157,017 | )
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Property, Plant and Equipment, Net                                                               |  |                  | 393,716  |   |                  |   | 453,517  |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Total Assets                                                                                     |  | $                | 822,910  |   |                  | $ | 710,972  |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|LIABILITIES AND MEMBERS EQUITY                                                                  |  |                  |          |   |                  |   |          |  
|Current Liabilities                                                                              |  |                  |          |   |                  |   |          |  
|Accounts payable                                                                                 |  | $                | 1,694    |   |                  | $ | 1,032    |  
|Accounts payable, affiliates                                                                     |  |                  | 33,529   |   |                  |   | 19,242   |  
|Accrued liabilities and other current liabilities                                                |  |                  | 10,132   |   |                  |   | 26,241   |  
|Liabilities from risk-management activities                                                      |  |                  | 36,790   |   |                  |   | 8,740    |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Total Current Liabilities                                                                        |  |                  | 82,145   |   |                  |   | 55,255   |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Asset retirement obligation                                                                      |  |                  | 5,223    |   |                  |   | 7,632    |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Total Liabilities                                                                                |  |                  | 87,368   |   |                  |   | 62,887   |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Total Members Equity                                                                            |  |                  | 735,542  |   |                  |   | 648,085  |  
|                                                                                                 |  |                  |          |   |                  |   |          |  
|Total Liabilities and Members Equity                                                            |  | $                | 822,910  |   |                  | $ | 710,972  |  
|                                                                                                 |  |                  |          |   |                  |   |          |  



See the notes to the
consolidated financial statements.



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WEST COAST POWER LLC



CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)



|                                                                                |  |                         |          |   |      |   |          |      |  |   |          |  
|------------------------------------------------------------------------------- |  | ----------------------- | -------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                                                |  | Year Ended December 31, |         
|                                                                                |  | 2004                    |          |   | 2003 |   |          | 2002 | 
|Revenues                                                                        |  | $                       | 725,626  |   |      | $ | 695,964  |      |  | $ | 585,307  |  
|Affiliate operating costs, exclusive of depreciation shown separately below     |  |                         | (316,632 | ) |      |   | (302,954 | )    |  |   | (456,526 | )
|Non-affiliate operating costs, exclusive of depreciation shown separately below |  |                         | (42,191  | ) |      |   | (62,372  | )    |  |   | (29,039  | )
|Depreciation and amortization expense                                           |  |                         | (39,456  | ) |      |   | (31,693  | )    |  |   | (27,227  | )
|Goodwill impairment                                                             |  |                         |         |   |      |   | (38,998  | )    |  |   |         |  
|Impairment charges                                                              |  |                         | (24,348  | ) |      |   |         |      |  |   | (13,451  | )
|Gain on sale of assets                                                          |  |                         | 689      |   |      |   |         |      |  |   |         |  
|General and administrative expenses                                             |  |                         | (198     | ) |      |   | (28,858  | )    |  |   | (10,638  | )
|                                                                                |  |                         |          |   |      |   |          |      |  |   |          |  
|Operating income                                                                |  |                         | 303,490  |   |      |   | 231,089  |      |  |   | 48,426   |  
|Interest expense                                                                |  |                         | (82      | ) |      |   | (176     | )    |  |   | (15,410  | )
|Interest income                                                                 |  |                         | 2,539    |   |      |   | 1,327    |      |  |   | 1,129    |  
|                                                                                |  |                         |          |   |      |   |          |      |  |   |          |  
|Income before cumulative effect of change in accounting principle               |  |                         | 305,947  |   |      |   | 232,240  |      |  |   | 34,145   |  
|Cumulative effect of change in accounting principle                             |  |                         |         |   |      |   | 1,030    |      |  |   |         |  
|                                                                                |  |                         |          |   |      |   |          |      |  |   |          |  
|Net income                                                                      |  | $                       | 305,947  |   |      | $ | 233,270  |      |  | $ | 34,145   |  
|                                                                                |  |                         |          |   |      |   |          |      |  |   |          |  



See the notes to the
consolidated financial statements.



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WEST COAST POWER LLC



CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands)

|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|-------------------------------- |  | ------------------------------------------ | ------ | - | -------------- | - | -------- | ------------------- |  | - | -------
|                                 |  | AccumulatedOtherComprehensiveIncome (Loss) |        |   | MembersEquity |   |          | ComprehensiveIncome
|Balance at December 31, 2001     |  | $                                          | (4,527 | ) |                | $ | 653,152  |                     |  |   |        
|Net income                       |  |                                            |       |   |                |   | 34,145   |                     |  | $ | 34,145 
|Amounts reclassified into income |  |                                            | 4,527  |   |                |   |          |                     |  |   |        
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Other comprehensive income       |  |                                            | 4,527  |   |                |   | 4,527    |                     |  |   | 4,527  
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Comprehensive income             |  |                                            |        |   |                |   |          |                     |  | $ | 38,672 
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Contributions                    |  |                                            |       |   |                |   | 13,516   |                     |  |   |        
|Distributions                    |  |                                            |       |   |                |   | (64,525  | )                   |  |   |        
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Balance at December 31, 2002     |  | $                                          |       |   |                | $ | 640,815  |                     |  |   |        
|Net income                       |  |                                            |       |   |                |   | 233,270  |                     |  | $ | 233,270
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Comprehensive income             |  |                                            |        |   |                |   |          |                     |  | $ | 233,270
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Distributions                    |  |                                            |       |   |                |   | (226,000 | )                   |  |   |        
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Balance at December 31, 2003     |  | $                                          |       |   |                | $ | 648,085  |                     |  |   |        
|Net income                       |  |                                            |       |   |                |   | 305,947  |                     |  | $ | 305,947
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Comprehensive income             |  |                                            |        |   |                |   |          |                     |  | $ | 305,947
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Contributions                    |  |                                            |       |   |                |   | 5,000    |                     |  |   |        
|Distributions                    |  |                                            |       |   |                |   | (217,245 | )                   |  |   |        
|Other distributions              |  |                                            |       |   |                |   | (6,245   | )                   |  |   |        
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        
|Balance at December 31, 2004     |  | $                                          |       |   |                | $ | 735,542  |                     |  |   |        
|                                 |  |                                            |        |   |                |   |          |                     |  |   |        



See the notes to the
consolidated financial statements.



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WEST COAST POWER LLC



CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)



|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|-------------------------------------------------------------------------------- |  | ----------------------- | -------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                                                 |  | Year Ended December 31, |         
|                                                                                 |  | 2004                    |          |   | 2003 |   |          | 2002 | 
|CASH FLOWS FROM OPERATING ACTIVITIES:                                            |  |                         |          |   |      |   |          |      |  |   |          |  
|Net income                                                                       |  | $                       | 305,947  |   |      | $ | 233,270  |      |  | $ | 34,145   |  
|Adjustments to reconcile net income to net cash flows from operating activities: |  |                         |          |   |      |   |          |      |  |   |          |  
|Depreciation and amortization                                                    |  |                         | 39,456   |   |      |   | 31,693   |      |  |   | 27,227   |  
|Goodwill impairment                                                              |  |                         |         |   |      |   | 38,998   |      |  |   |         |  
|Impairment charges                                                               |  |                         | 24,348   |   |      |   |         |      |  |   | 13,451   |  
|Risk-management activities                                                       |  |                         | 3,559    |   |      |   |         |      |  |   |         |  
|Gain on sale of assets                                                           |  |                         | (689     | ) |      |   |         |      |  |   |         |  
|Cumulative effect of change in accounting principle                              |  |                         |         |   |      |   | (1,030   | )    |  |   |         |  
|Other, non-cash and adjustments                                                  |  |                         | (1,313   | ) |      |   |         |      |  |   |         |  
|Changes in working capital:                                                      |  |                         |          |   |      |   |          |      |  |   |          |  
|Accounts receivable, net                                                         |  |                         | (55,950  | ) |      |   | 3,127    |      |  |   | 164,278  |  
|Inventory                                                                        |  |                         | 1,281    |   |      |   | 1,164    |      |  |   | 11,617   |  
|Prepaid expenses                                                                 |  |                         | (11,584  | ) |      |   | (30,338  | )    |  |   | 2,226    |  
|Accounts payable                                                                 |  |                         | 14,949   |   |      |   | (20,690  | )    |  |   | (17,269  | )
|Accrued liabilities and other current liabilities                                |  |                         | (18,654  | ) |      |   | 20,571   |      |  |   | 5,729    |  
|Other                                                                            |  |                         | (1,512   | ) |      |   | 3,744    |      |  |   | 2,489    |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by operating activities                                        |  |                         | 299,838  |   |      |   | 280,509  |      |  |   | 243,893  |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|                                                                                 |  |                         |         
|CASH FLOWS FROM INVESTING ACTIVITIES:                                            |  |                         |          |   |      |   |          |      |  |   |          |  
|Capital expenditures                                                             |  |                         | (1,386   | ) |      |   | (25,709  | )    |  |   | (21,652  | )
|Decrease (increase) in restricted cash                                           |  |                         |         |   |      |   | 69,362   |      |  |   | (69,362  | )
|Proceeds from asset sales, net                                                   |  |                         | 3,278    |   |      |   |         |      |  |   |         |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash provided by (used in) investing activities                              |  |                         | 1,892    |   |      |   | 43,653   |      |  |   | (91,014  | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|                                                                                 |  |                         |         
|CASH FLOWS FROM FINANCING ACTIVITIES:                                            |  |                         |          |   |      |   |          |      |  |   |          |  
|Repayments of borrowings                                                         |  |                         |         |   |      |   | (10,000  | )    |  |   | (140,057 | )
|Contributions                                                                    |  |                         |         |   |      |   |         |      |  |   | 13,516   |  
|Distributions                                                                    |  |                         | (217,245 | ) |      |   | (226,000 | )    |  |   | (64,525  | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net cash used in financing activities                                            |  |                         | (217,245 | ) |      |   | (236,000 | )    |  |   | (191,066 | )
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Net increase (decrease) in cash and cash equivalents                             |  |                         | 84,485   |   |      |   | 88,162   |      |  |   | (38,187  | )
|Cash and cash equivalents, beginning of period                                   |  |                         | 124,245  |   |      |   | 36,083   |      |  |   | 74,270   |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Cash and cash equivalents, end of period                                         |  | $                       | 208,730  |   |      | $ | 124,245  |      |  | $ | 36,083   |  
|                                                                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|                                                                                 |  |                         |         
|Supplemental Disclosure of Cash Flow Information:                                |  |                         |          |   |      |   |          |      |  |   |          |  
|Interest paid                                                                    |  |                         | 82       |   |      |   | 178      |      |  |   | 4,336    |  
|                                                                                 |  |                         |         
|Other non-cash investing and financing activity:                                 |  |                         |          |   |      |   |          |      |  |   |          |  
|Contribution of El Segundo Power II LLC by NRG                                   |  |                         | 5,000    |   |      |   |         |      |  |   |         |  



See the notes to the
consolidated financial statements.



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS



Note 1Organization and Operations of the Company



Effective June 30, 1999, Dynegy Power Corp. (DPC), an indirect
wholly owned subsidiary of Dynegy Holdings Inc. (Dynegy), and NRG Energy, Inc. (NRG), a subsidiary of Xcel Energy, Inc (collectively, the Sponsors) formed WCP (Generation) Holdings LLC (Holdings) and
West Coast Power LLC (WCP, we, us or our), both of which are Delaware limited liability companies. The Sponsors have an equal interest in Holdings and share in profits and losses equally. WCP is wholly
owned by Holdings and serves as a holding company for El Segundo Power, LLC (ESP), El Segundo Power II LLC (ESP II), Long Beach Generation LLC (LBG), Cabrillo Power I LLC (Cabrillo I) and Cabrillo
Power II LLC (Cabrillo II). NRG became an independent public company upon its emergence from bankruptcy on December 5, 2003 and no longer has any material affiliation or relationship with Xcel Energy.



Upon formation of WCP, the assets and liabilities of ESP, LBG, Cabrillo I and
Cabrillo II (collectively, the LLCs) were contributed to WCP by the Sponsors and were recorded at their historical costs because the transfer represented a reorganization of entities under common control. Operations are governed by the
executive committee, which consists of two representatives from each Sponsor.



From March 2001 through December 2004, WCPs facilities operated under a contract with the California Department of Water Resources (CDWR) Sales to CDWR represented a substantial portion of WCPs
capacity.



ESP owns a 670-megawatt (MW) plant
located in EI Segundo, California, consisting of two operating steam electric generating units. The facility has operated as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and
other western markets. In December 2004, the California Independent System Operator (Cal ISO), pursuant to its tariff, designated ESP units 3 and 4 as Reliability Must Run (RMR) units for the calendar year 2005. On December
21, 2004 ESP filed with the Federal Energy Regulatory Commission (FERC), an application for approval of its rates as an RMR designated facility. ESP made the election to collect rates as a Condition 2 plant, effective January 1,
2005. On February 11, 2005 FERC issued an order that accepted the rates for filing, subject to refund, set the matter for hearing, and held the hearing in abeyance to permit the parties to continue to engage in negotiations and resolve any
outstanding issues. ESP expects that FERC will issue an order approving its rates in the third quarter of 2005.



In October 2004, the FERC approved WCPs settlement of FERC claims relating to western energy market transactions that occurred from January 2000
through June 2001. (See Note 9Commitments and Contingencies for further discussion of this settlement). Included in this settlement was a payment of $22,544,942. In order to provide the funds for this settlement, Dynegy has agreed to forego
approximately $17,000,000 of distributions from WCP, and NRG has agreed to forego approximately $5,500,000 of distributions and contribute El Segundo Power II LLC valued at $5,000,000 to WCP. The contribution of these assets is reflected as a
contribution in the Consolidated Statements of Changes in Equity. $6,244,942 of the settlement was paid by WCP on behalf of Dynegy in accordance with the settlement agreement, and is recorded as a reduction of Dynegys members equity on
the Consolidated Statements of Changes in Equity.



On December
30, 2004, NRG West Coast LLC, a Delaware limited liability company, assigned its right, title, and interest in El Segundo Power II LLC to Holdings, which in turn assigned its interest to WCP, as part of the funding of the settlement agreement with
the FERC. On February 3, 2005, the California Energy Commission approved the certificate for the construction and operation of a proposed 630-megawatt combined-cycle facility by ESP II on the site previously used by ESP units 1 and 2. ESP II became
100% owned by WCP on December 30, 2004. No date has been set to commence construction, although California state law requires that construction commence five years after the issuance of the certificate.



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



On January 27, 2005, Dynegy Power Marketing Inc, an affiliate of ESP, acting as its fully authorized
agent, entered into a power purchase agreement with a major California utility for a term commencing May 1, 2005 and ending December 31, 2005. As part of that agreement, ESP is required to obtain certain consents and waivers from Cal ISO and to file
for an application with FERC to change from Condition 2 to Condition 1 under the Cal ISO tariff. Once all approvals are obtained, the utility will acquire all dispatch rights from ESP for the term of the agreement and assume
responsibility for all Cal ISO grid reliability dispatched as permitted under the RMR contract (See Note 7 for a more detailed explanation).



LBG owns a 560-MW plant located in Long Beach, California. On January 1, 2005, after due notice to the Cal ISO, the plant was shut down and the operator
began decommissioning and environmental remediation of the plant site and equipment salvage and investment recovery efforts.



Cabrillo I owns a 970-MW Plant located in Carlsbad, California, consisting of five steam electric generating units and one combustion turbine. The
facility has operated as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets. Cabrillo I was designated as a RMR unit by the Cal ISO for 2004 and 2005.
Pursuant to an uncontested settlement agreement filed in December 2004 with the Cal ISO and various interveners in FERC Docket No. ER04-308, RMR rates for the years 2004 through 2006 were agreed upon between the parties. As a part of that
settlement, Cabrillo chose to collect rates as a Condition 2 plant, effective January 1, 2005 (See Note 7 below for a more detailed explanation). On February 14, 2005, FERC issued an order approving these rates. Rates for 2006 will only
be effective if the Cabrillo I units are designated RMR units by the Cal ISO in the third or fourth quarter of 2005.



Cabrillo II owns 13 combustion turbines with an aggregate capacity of 202-MW located throughout San Diego County, California. The facility has operated as
a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets. Cabrillo II combustion turbines were designated as RMR units by the Cal ISO for 2004 and 2005. Pursuant
to an uncontested settlement agreement filed in December 2004 with the Cal ISO and various interveners in FERC Docket No. ER04-308, RMR rates for the years 2004 through 2006 were agreed upon between the parties. As a part of that settlement,
Cabrillo II chose to continue collecting rates as a Condition 2 plant, effective January 1, 2005 (See Note 7 below for a more detailed explanation). On February 11, 2005, FERC issued an order approving these rates. Rates for 2006 will
only be effective if the Cabrillo II units are designated RMR units by the CAISO in the third or fourth quarter of 2005.



Note 2Accounting Policies



Our accounting policies conform to GAAP. Our most significant accounting policies are described below. The preparation of consolidated financial
statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. 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
used in, among other things, (1) developing fair value assumptions, including estimates of future cash flows and discounts rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets and
(4) determining amounts to accrue for contingencies, guarantees and indemnifications.



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Principles of Consolidation.The accompanying consolidated financial statements include
our accounts after eliminating intercompany accounts and transactions. Certain reclassifications have been made to prior- period amounts to conform with current-period financial statement classifications.



Cash and Cash Equivalents.Cash and cash equivalents consist of
all demand deposits and funds invested in short-term investments with original maturities of three months or less.



Accounts Receivable and Allowance for Doubtful Accounts.We establish provisions for losses on accounts receivable if it becomes probable we
will not collect all or part of outstanding balances. Trade accounts receivable are recorded at the invoiced amount and do not bear interest. We review collectibility and establish or adjust our allowance as necessary using the specific
identification method. As of December 31, 2004 and 2003,we have reserved $1,032,466 and $391,819,281, respectively, as an allowance for doubtful accounts relating to receivables owed to us by the CDWR, the Cal ISO and the California Power
Exchange (PX). As described in Note 9, in October 2004, we settled our historical disputes with FERC parties.



Concentration of Credit Risk.We sell our electricity production to purchasers of electricity in California, which includes the Cal ISO and
Dynegy Power Marketing, Inc. (DYPM). These industry and geographical concentrations have the potential to impact our overall exposure to credit risk either positively or negatively because the customer base may be similarly affected by
changes in economic industry, weather or other conditions.



Inventory.Inventories are valued at the lower of market or cost using the last-in, first-out (LIFO) or the average cost methods and are comprised of the following:



|                                      |  |                |        |      |   |       
|------------------------------------- |  | -------------- | ------ | ---- | - | ------
|                                      |  | December 31,  
|                                      |  | 2004           |        | 2003
|                                      |  | (in thousands)
|Emissions credits (average cost)      |  | $              | 4,496  |      | $ | 5,366 
|Materials and supplies (average cost) |  |                | 3,446  |      |   | 6,418 
|Fuel oil (LIFO)                       |  |                | 13,376 |      |   | 13,842
|                                      |  |                |        |      |   |       
|                                      |  | $              | 21,318 |      | $ | 25,626
|                                      |  |                |        |      |   |       



In conjunction with
the retirement of the Long Beach facility, a lower of cost or market analysis was performed on the facilitys materials and supplies balance. The vast majority of the materials and supplies were designed for use specifically at the Long Beach
facility or are otherwise obsolete. As a result, an adjustment of $3,027,613, which is included in Operating costs on the consolidated statement of operations, was made to reduce the inventory to net realizable value as of December 31, 2004.



Emission credits represent costs paid by us to acquire
additional NOx credits. We use these credits to comply with emission caps imposed by various environmental laws under which we must operate. As individual credits are used, costs are recognized as operating expense. See additional discussion below
at Other Contingencies.



Property Plant and
Equipment.Property, plant and equipment, which consists primarily of power generating facilities, furniture and fixtures and computer equipment, is recorded at historical cost. Expenditures for major replacements, renewals and major
maintenance are capitalized. We consider major maintenance to be expenditures incurred on a cyclical basis in order to maintain and prolong the efficient operation of our assets. Expenditures for repairs and minor renewals to maintain assets in
operating condition are expensed. Depreciation



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



is provided using the straight-line method over the estimated economic service lives of the assets, ranging from 3 to 25 years. The estimated economic
service lives of our asset groups are as follows:



|                            |  |               
|--------------------------- |  | --------------
|Asset Group                 |  | Range of Years
|Power Generation Facilities |  | 7 to 25       
|Furniture and Fixtures      |  | 3 to 5        
|Other Miscellaneous         |  | 5 to 20       



Gains and losses on
sales of individual assets are reflected in gain on sale of assets in the consolidated statements of operations. We assess the carrying value of our plant and equipment in accordance with SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the related discounted cash flows of the assets and recording a loss if the resulting estimated fair value is
less than the book value. For assets identified as held for sale, the book value is compared to comparable market prices or the estimated fair value if comparable market prices are not readily available to determine if an impairment loss is
required.



On September 30, 2004, the WCP executive committee
consented to a plan to retire the Long Beach facilities effective January 1, 2005. The revision of the expected useful life of Long Beach is a change in accounting estimate, per the guidance in APB 20, Accounting Changes. This change is
accounted for in the current and future periods if the change affects both. The remaining asset value, excluding land, as of September 30, 2004 was $9.9 million. The depreciation was accelerated so that the Long Beach facilities were fully
depreciated by December 31, 2004.



Asset Retirement
Obligations.We adopted SFAS No. 143, Asset Retirement Obligations, effective January 1, 2003.Under the provisions of SFAS No. 143, we are required to record legal obligations to retire tangible, long-lived assets
on our balance sheet as liabilities, which are recorded at a discount when the liability is incurred. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of the cash
flows. If our estimates on the amount or timing of the cash flow change, the change may materially affect earnings.



Upon adoption of SFAS No. 143, existing environmental liabilities in the amount of $5,200,000 were reversed in the first quarter 2003. The fair value of
the remediation costs estimated to be incurred upon retirement of the respective assets is included in the asset retirement obligation (ARO) and was recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities
exceeded the fair value of the future retirement obligations, the impact of adopting SFAS No. 143 was an increase in earnings of $1,029,756 in 2003, which is the cumulative effect of change in accounting principle in the consolidated statement of
operations.



The following pro forma financial information has
been prepared to give effect to the adoption of Statement No. 143 as if it had been adopted January 1, 2002:



|                                                                          |  |                             |            |  
|------------------------------------------------------------------------- |  | --------------------------- | ---------- | -
|                                                                          |  | Year EndedDecember 31, 2002 |           
|Net income, as reported                                                   |  | $                           | 34,144,995 |  
|Pro forma adjustments to reflect retroactive adoption ofStatement No. 143 |  |                             | (1,224,171 | )
|                                                                          |  |                             |            |  
|Pro forma net income                                                      |  | $                           | 32,920,824 |  
|                                                                          |  |                             |            |  



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



During 2004, the timing or fair value of the estimated cost to be incurred upon retirement related to
the dismantlement and remediation changed for four of the Cabrillo II facilities. These changes resulted in an $896,809 decrease in our ARO liability. Since the change in the ARO liability associated with one of the facilities exceeded the asset
retirement cost net of accumulated depreciation, an increase in earnings of $641,236 was recorded during 2004, which is included in Non-affiliate operating costs on the consolidated statements of operations.



At January 1, 2004, our ARO liabilities totaled $7,631,979, which includes
monitoring charges related to El Segundo Units 1 and 2 as well as dismantlement and remediation at the Cabrillo II facilities since these assets reside on leased property. Annual depreciation of the ARO assets resulting from adoption of this
standard and the accretion of the liability towards the ultimate obligation amount were $404,559 and $628,290, respectively, during 2004. Annual depreciation of the ARO assets and the accretion of the liability towards the ultimate obligation amount
were $644,483 and $697,472, respectively, during 2003. During 2004, we settled $2,140,550 relating to our ARO. At December 31, 2004, our ARO liabilities totaled $5,222,910.



In addition to these liabilities, we also have potential retirement obligations for dismantlement of our other power
generation facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. Liabilities will be recorded in accordance with SFAS No. 143 at such time as our operations change and a liability is
incurred.



Other Contingencies. Environmental
costs relating to current operations are expensed or capitalized, as appropriate, depending on whether they provide future economic benefit. Liabilities are recorded when environmental assessment indicate remedial efforts are probable and the costs
can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and site-specific costs. Liabilities may be recognized on a discounted basis if the amount and timing of anticipated
expenditures are fixed or reliably determinable; otherwise, such liabilities are recognized on an undiscounted basis. Liabilities incurred by providing indemnification in connection with assets sold or closed are recognized upon such sale or closure
to the extent they are probable, can be estimated and have not previously been reserved. In assessing liabilities, no offset is made for potential insurance recoveries. Recognition of any joint and several liability is based upon our best estimate
of our final pro rata share of such liability.



Liabilities for
other contingencies are recognized in accordance with SFAS No. 5, Accounting for Contingencies, upon identification of an exposure, which, when fully analyzed, indicates that it is both probable a liability has been incurred and the loss
amount can be reasonably estimated. Non-capital costs to remedy such contingencies or other exposures are charged to a reserve, if one exists, or otherwise to current-period operations. We accrue the lesser end of the range when a range of probable
loss exists.



Goodwill. Goodwill represents, at
the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS No. 142, Goodwill and Other Intangible Assets, when assessing the carrying value
of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis or when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective,
inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rate. In 2003, all goodwill was impaired (See Note 3).



Revenue Recognition. Revenues from the sale of energy and
ancillary services are recorded based upon output delivered and/or service provided priced at market or by contract. Revenues received from the RMR agreement with the Cal ISO are primarily derived from availability payments and amounts based on
reimbursing



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



variable costs. Revenues identified as being subject to future resolution are accounted for as discussed above at Allowance for Doubtful
Accounts.



Federal Income Taxes. We are not
a taxable entity for federal income tax purposes. Accordingly, there is no provision for income taxes in the accompanying consolidated financial statements.



Fair Value of Financial Instruments.Our financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts
payable and derivative instruments to hedge commodity price and interest rate risk. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable are representative of their respective fair values due to the short-term
maturities of these instruments. Additionally, we had entered into fair value hedges and electricity options. The fair value of these instruments is discussed in Note 5.



Accounting for Derivative Instruments.We may enter into various derivative instruments to hedge the risks
associated with changes in commodity prices and interest rates. We use physical forward contracts to hedge a portion of our exposure to price fluctuations of natural gas and electricity.



Under SFAS No. 133, as amended, we recognize all derivative instruments on the balance sheet at their fair values, and
changes in fair value are recognized immediately in earnings, unless the derivatives qualify, and are designated, as hedges of future cash flows or fair values, or qualify, and are designated, as normal purchases and sales. For derivatives treated
as hedges of future cash flows, we record the effective portion of changes in the fair value of the derivative instrument in other comprehensive income until the related hedged items impact earnings. Any ineffective portion of a cash flow hedge is
reported in earnings immediately. For derivatives treated as fair value hedges, we record changes in the fair value of the derivative and changes in the fair value of the hedged risk attributable to the related asset, liability or firm commitment in
current period earnings. Derivatives treated as normal purchases or sales are recorded and recognized in income using accrual accounting.



Note 3Goodwill



We recognized a $39 million impairment charge in 2003 based on our annual goodwill impairment test. We calculated our fair value using a discounted future
cash flows methodology. Fair value was negatively impacted by the expiration of the CDWR contract in December 2004 coupled with decreasing power prices and current market conditions. Please read Note 7. The impairment charge is included in goodwill
impairment on the consolidated statements of operations.



Note
4Impairment of Long-Lived Assets



In December 2004,
we tested our long-lived assets for impairment in accordance with SFAS No. 144. As a result of the expiration of the CDWR contract (See Note 7), our impairment analysis of our Cabrillo II facility indicated future cash flows were insufficient to
recover the carrying value of the long-lived assets. As a result, we recorded an impairment of $24,348,534, which is included in impairment and other charges on the consolidated statements of operations.



In July 2002, we were notified that land leases associated with four Cabrillo
II combustion turbines would not be renewed. We determined that these turbines would be sold rather than relocated to an alternate site for continued use. As a result, an impairment charge of $13,400,000 was recognized in 2002 and represented the
difference between the carrying value of the four turbines and the estimated net proceeds from their prospective sale. In addition, a $5,200,000 liability was recorded for the estimated cost of restoring the land on which the



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



turbines are located to its original condition. This reserve was reversed upon adoption of SFAS No. 143 on January 1, 2003. Please read Note
2Accounting PoliciesAsset Retirement Obligations. During 2004, three of these turbines were sold. We recognized a gain of $689,144.



Note 5Derivatives and Hedging



We entered into a series of fixed price electricity purchases to hedge a portion of the fair value of our fixed price CDWR Power Purchase Agreement
(PPA). During the years ended December 31, 2004, 2003 and 2002, there was no ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. Additionally, no amounts
were reclassified to earnings in connection with forecasted transactions that were no longer considered probable.



The value of the fair value hedges at December 31, 2004 and 2003, were approximately zero and $(8,739,539) and is included in liabilities from
risk-management activities on the consolidated balance sheets. The corresponding value of the hedged risk is approximately zero and $8,739,539 and is included in assets from risk-management activities on the consolidated balance sheets.



Upon acceptance of RMR Condition 2 on December 31, 2004, we are not
exposed to the variability of cash flow from sales of power on a merchant basis. Please read Note 7.



We have also entered into interest rate swap agreements, which effectively exchanged variable interest rate debt for fixed interest rate debt. The
agreements were used to reduce the exposure to possible increases in interest rates. We entered into these swap agreements with major financial institutions. On June 28, 2002, we terminated the interest rate swap agreements concurrently with the
refinancing of our debt. Brokerage fees of approximately $5,200,000 were expensed at the time of refinancing. No interest rate swaps were outstanding at December 31, 2004 or 2003.



Note 6Related Parties



We purchase fuel for our plants under full requirement natural gas supply agreements (GSAs) with Dynegy Marketing and Trade (DMT),
one of our affiliates. Charges for fuel are based upon similar terms and conditions as could be obtained from unrelated third parties. Fuel purchases from DMT are included in affiliated operating costs in the consolidated statement of operations.



We contracted with DYPM to provide all power scheduling, power
marketing and risk management for us under an energy management agreement (the EMA). Sales of power under the EMA through DYPM were $502,554,381, $617,370,571, and $540,114,356 for the years ended December 31, 2004, 2003, and 2002
respectively. Additionally, we contracted with DMT to provide all scheduling of fuel supply.



We entered into Operation and maintenance (O&M) agreements with NRG Cabrillo Power Operations Inc. and NRG El Segundo Operations Inc., two of our affiliates, for Cabrillo I and Cabrillo II effective
May 2001 and for ESP and LBG effective April 2000. Their fees for services primarily include recovery of the costs of operating the plant as approved in the annual budget as well as a base monthly fee. When NRG became operator, we contracted with
NRG Development Company, Inc., one of our affiliates, to provide services under the Administrative Management Agreement (the AMA). Services they provided under the AMA included environmental, engineering, legal and public relations
services not covered under the O&M agreements. Fees for such services are subject to executive committee approval if the amounts exceed a certain percentage of the applicable annual approved budget.



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



We entered into an administrative services management agreement (the ASMA) with Dynegy
Power Management Services, L.P., one of our affiliates, under which Dynegy Power Management Services, L.P. provides administrative services such as business management and accounting to us. Fees for such services are subject to executive committee
approval if the amounts exceed a certain percentage of the applicable annual approved budget.



In addition to the related-party transactions listed above, we made $14,200,000 in interest payments in 2002 to DMT under a forbearance agreement with DMT with respect to noncompliance with the GSA. The effective
interest rate on the deferred balance was prime rate plus 2%. All amounts due under the forbearance agreement have been paid and the forbearance agreement terminated. In 2004 and 2003, no interest was paid to DMT.



As described above, our affiliates provide various services for us. Charges
for these services are included in our operating and general and administrative expenses in the consolidated statements of operations and consisted of the following costs:



|                                                          |  |                          |         |      |   |         |  |   |        
|--------------------------------------------------------- |  | ------------------------ | ------- | ---- | - | ------- |  | - | -------
|                                                          |  | Years Ended December 31,
|                                                          |  | 2004                     |         | 2003 |   | 2002   
|                                                          |  | (in thousands)          
|Dynegys Related Cost                                     |  |                          |         |      |   |         |  |   |        
|Fuel                                                      |  | $                        | 267,844 |      | $ | 258,134 |  | $ | 401,650
|EMA Charges                                               |  |                          | 9,216   |      |   | 9,141   |  |   | 10,346 
|ASMA Charges                                              |  |                          | 55      |      |   | 207     |  |   |       
|                                                          |  |                          |         |      |   |         |  |   |        
|Charges included in operating costs                       |  | $                        | 277,115 |      | $ | 267,482 |  | $ | 411,996
|                                                          |  |                          |         |      |   |         |  |   |        
|ASMA fees included in general and administrative expenses |  | $                        | 1,209   |      | $ | 1,331   |  | $ | 1,298  
|                                                          |  |                          |         |      |   |         |  |   |        
|NRGs Related Cost                                        |  |                          |         |      |   |         |  |   |        
|O&M and AMA charges included in operating costs           |  | $                        | 39,517  |      | $ | 35,472  |  | $ | 44,531 
|                                                          |  |                          |         |      |   |         |  |   |        



Note 7Power Purchase
Agreement



We entered into a long-term Power Purchase
Agreement with the CDWR in March 2001. From January 2002 through December 31, 2004, the CDWR contracted for fixed price firm energy and system contingent capacity and energy representing a substantial portion of WCPs capacity. Sales to CDWR
constituted approximately 71%, 88%, and 93% of revenues, net of reserves, in 2004, 2003 and 2002, respectively.



The CDWR contract expired by its terms on December 31, 2004. For 2005, all of our assets will be operating under RMR Condition 2 contracts with the Cal
ISO, except for the Long Beach facility, which was retired effective January 1, 2005 (See Note 2Accounting PoliciesProperty, Plant and Equipment). Under the terms of these RMR contracts, Cal ISO reimburses WCP for 100% of approved costs
plus a rate of return specified in the contracts. When the facilities are instructed to provide power by the Cal ISO, they are reimbursed for their variable production costs. Under RMR Condition 2, the facilities are 100% committed to the Cal ISO
and, therefore, do not experience changes in market conditions through bilateral energy or capacity sales to third parties that might otherwise be entered. The RMR contracts are effective for calendar year 2005. The Cal ISO may renew or terminate
the RMR contracts at its sole option on an annual basis as of the first of the following year.



In addition, ESP has entered into a power sales agreement with a major California utility for 100% of the capacity and associated energy from the El Segundo facility from May 2005 through December 2005. During the



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##### Index to Financial Statements

WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



term of this agreement, the utility will be entitled to primary energy dispatch right for the facilitys generating capacity. The agreement is subject
to an amendment to the El Segundo RMR agreement to switch to RMR Condition I and to permit the utility to exercise primary dispatch rights under the agreement while preserving Cal ISOs ability to call on the El Segundo facility as a
reliability resource under the RMR agreement, if necessary. The agreement will be accounted for as an operating lease of the facility under the requirements of EITF Issue 01-8.



Note 8Debt



In August 1999, we entered into a credit agreement with a five-year, $322,500,000 amortizing term loan with a balloon payment and a $40,000,000 working
capital facility line of credit (the Credit Agreement). The Credit Agreement was scheduled to mature in June 2004.



In September 1999, we entered into two interest rate swap agreements related to the Credit Agreement. One agreement effectively fixed the interest rate at
6.435% for the first $60,000,000 and matured in June 2002. The second agreement effectively fixed the interest rate at 6.230% for an incremental $40,000,000 and was scheduled to mature in June 2003. These swaps were designated as hedges of the
future cash outflows associated with interest payments on the debt. The second agreement was terminated in 2002 as part of the refinancing discussed below, and the remaining deferred loss was reclassified from other comprehensive income to interest
expense.



In June 2002, we refinanced our Credit Agreement with
a 364-day bank facility consisting of a $100,000,000 letter of credit line, a $10,000,000 term loan commitment and a $10,000,000 working capital loan commitment (the Refinanced Credit Agreement). In conjunction with the refinancing,
$3,400,000 of deferred financing costs related to the original Credit Agreement were expensed. We incurred additional debt issuance costs of $4,900,000 in connection with the refinancing. Such costs were capitalized and amortized over the remaining
term of the Credit Agreement and are included in prepaid expenses and other current assets.



In June 2003, we replaced the Refinanced Credit Agreement with an 18-month $50,000,000 letter of credit facility. With the replacement of the Refinanced Credit Agreement, we are no longer required to maintain
restricted cash funds. This agreement requires us to post equal amounts of cash collateral for all letters of credit issued. This letter of credit facility incurs fees at the rate of 0.50% on any outstanding letters of credit plus a commitment fee
at the rate of 0.25% on any unused amount of the commitment.



In November 2004, the letter of credit facility was extended until December 31, 2005 and increased from $50,000,000 to $85,000,000 effective January 1, 2005. We incurred financing costs of $275,000 in connection with the renewal of the
agreement. Such costs have been capitalized and will be amortized over the remaining term of the renewed agreement and are included in prepaid expenses and other current assets. At December 31, 2004, our deposit for collateral was $35,300,000. Of
this deposit, $28,450,000 was issued in letters of credit.



Our
interest costs on the term loans, working capital loans and interest rate swaps (including swap termination costs and amortization costs, which are included in depreciation and amortization on the consolidated statements of operations) totaled
approximately $500,000, $2,900,000, and $15,400,000 for 2004, 2003, and 2002 respectively.



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 matters will not materially adversely affect our financial condition, results of operations, or cash flows.



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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. For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please see Note 2 for further
discussion. Environmental reserves do not reflect managements assessment of the insurance coverage that may be applicable to the matters at issue. We cannot guarantee that the amount of any reserves will cover any 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.



California Market Litigation. We and numerous other power generators and marketers were the subject of numerous lawsuits arising from our
participation in the western power markets during the California energy crisis. Eight of these lawsuits, which primarily alleged manipulation of the California wholesale power markets and sought unspecified treble damages, were consolidated before a
single federal judge. WCP was identified as a defendant in one of those lawsuits, which was dismissed, together with another of the eight lawsuits, in the first quarter 2003 on the grounds of FERC preemption and the filed rate doctrine. The Ninth
Circuit Court of Appeals affirmed this dismissal in June 2004. The plaintiffs have not appealed.



In addition to the lawsuit discussed above, WCP and/or the LLCs were named as defendants in eight other putative class actions and/or representative
actions that were filed in state and federal court on behalf of business and residential electricity consumers against numerous power generators and marketers between April and October 2002. The complaints alleged unfair, unlawful and deceptive
practices in violation of the California Unfair Business Practices Act and sought an injunction, restitution and unspecified damages. While some of the allegations in these lawsuits were similar to the allegations in the eight lawsuits described
above, these lawsuits included additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. The court dismissed these actions, although the plaintiffs have appealed, and the
briefing on that appeal was completed in October 2004. The Ninth Circuit affirmed the denial of remand and dismissal of these lawsuits in February 2005.



In December 2002, two additional actions naming WCP and/or the LLCs as defendants were filed with similar allegations on behalf of residents of Washington
and Oregon. In May 2003, the plaintiffs voluntarily dismissed these actions and refiled them in California Superior Court as a class action complaint. The complaint, which was brought on behalf of consumers and businesses in Oregon, Washington,
Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleges violations of the Cartwright Act and unfair business practices. We have removed the action from state court and consolidated it with
existing actions pending before the United States District Court for the Northern District of California. The hearing on plaintiffs appeal to remand to state court occurred in February 2004. The judge stayed his ruling on the appeal pending
the Ninth Circuits ruling on the six remaining lawsuits described in the first paragraph above.



In June 2004, the City of Tacoma public utility filed a lawsuit in Washington federal court against a number of energy companies, including us, alleging
it paid inflated prices for electricity due to the defendants



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manipulation of the California wholesale power markets. The defendants filed a motion to dismiss this case in December 2004. On February 11, 2005,
defendants motion to dismiss was granted.



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



FERC and Related Regulatory InvestigationsRequests for Refunds
and RMR Complaints. In October 2004, the FERC approved in all respects the agreement announced by Dynegy and WCP in April 2004 which provides for the settlement of FERC claims relating to western energy market transactions that occurred from
January 2000 through June 2001, including:



| |  |  | FERCs June 2003 order to show cause why the activities of certain participants in the California power markets from January 2000 to June 2001, including WCP, did not
constitute gaming and/or anomalous market behavior as defined in the ISO and PX tariffs, which matter was resolved by the January 2004 settlement providing that WCP will pay approximately $3 million into a fund for the benefit of California and
Western electricity consumers, which January 2004 settlement was incorporated into the broader settlement described below; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | FERCs July 2001 hearings and October 2003 orders relating to the establishment of (i) refunds to electricity customers, or offsets against amounts owed to electricity
suppliers, during the period of October 2000 through June 2001 and (ii) a methodology to calculate mitigated market clearing prices in the ISO and the PX markets.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The parties to this settlement other than Dynegy and WCP include NRG Energy, Inc., FERC Office of Market Oversight and
Investigations, Pacific Gas and Electric Company, Southern California Edison, San Diego Gas & Electric Company, the CDWR, the California Electricity Oversight Board and the California Attorney General. Other market participants are permitted to
opt into this settlement and share in the distribution of the settlement proceeds. Most of these other market participants have agreed to participate in the settlement. The entitlement to refund and/or the liability of each of the non-settling
market participants will be determined by the Cal ISO. Under the terms of the settlement, WCP will have no further liability to these non-settling parties.



As part of the settlement agreement, WCP agreed to (i) forego its right to collect approximately $259 million in past-due receivables, plus interest, from
the Cal ISO and the PX related to the settlement period, (ii) forego natural gas cost recovery claims against the California settling parties related to the settlement period, and (iii) place into escrow accounts a total of $22.5 million, which
includes the above-referenced $3 million settlement with the FERC staff, for subsequent distribution to various California energy purchasers. In exchange, the settling parties agreed to forego (i) all claims relating to refunds or other monetary
damages for sales of electricity during the settlement period, and (ii) claims alleging receipt of unjust or unreasonable rates for the sale of electricity during the settlement period.



The settlement further provides that WCP is entitled to pursue claims for reimbursement of fuel costs against non-settling
market participants. WCP is currently pursuing these claims but is unable to predict the amounts that may be recovered from such parties.



The settlement does not apply to the ongoing civil litigation related to the California energy markets described above in which Dynegy and WCP are
defendants. The settlement also does not apply to the pending



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



appeal by the CPUC and the California Electricity Oversight Board of the FERCs prior decision to affirm the validity of the CDWR contract. We are
currently awaiting a ruling on this appeal and related filings and cannot predict their outcome.



In Docket Nos. EL02-15-000 and EL03-22-000 there is a dispute regarding various payment provisions in previous RMR Contracts with Cabrillo I and II.
Certain California parties and the California ISO have proposed to apply to the Cabrillo RMR Contracts, any changes required by the Commission in similar agreements entered into between the ISO and Mirant Corporation, a matter which is pending in
Docket Nos. ER98-495-000, et al. In a settlement between Mirant and the California parties filed in February, 2005, Mirant and the California parties have requested that the FERC rule on the initial decision in the ER98-495 docket. An adverse ruling
by FERC could have an material adverse impact on WCP in Dockets Nos. EL02-15-000 and EL03-22-000.



We are unable to predict with any certainty how FERC may ultimately decide ER98-495 and to what extent such ruling might have an adverse impact on WCP.



Gas Index Pricing Litigation.We are defending the
following suits claiming damages resulting from the alleged manipulation of gas index publications and prices by WCP and/or the LLCs and numerous other power generators and marketers: ABAG v. Sempra Energy et al. (filed in state court in
November 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); Nurserymens Exchange v. SempraEnergy et
al. (filed in state court in October 2004); Older v. Dynegy Inc. et al. (filed in federal court in September 2004); Sacramento Municipal Utility District (SMUD) v. Reliant Energy Services, et al. (filed in state court in November
2004); Texas-Ohio Energy, Inc. v. CenterPoint Energy Inc., et al. (class action filed in federal court in November 2003); and Utility Savings & Refund v. Reliant Energy Services, et al. (class action filed in federal court in
November 2004). In each of these suits, the plaintiffs allege that we and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to gas index publications, thereby manipulating the price. All
of the complaints rely heavily on the FERC and CFTC investigations into and report concerning index-reporting manipulation in the energy industry. The plaintiffs generally seek unspecified actual and punitive damages relating to costs they claim to
have incurred as a result of the alleged conduct.



Pursuant to
various motions filed by the parties to the litigation described above, the gas index pricing lawsuits pending in state court have been consolidated before a single judge in state court in San Diego. These cases are now entitled the Judicial
Counsel Coordinated Proceeding (JCCP) 4221, 4224, 4226, and 4228, the Natural Gas Anti-Trust Cases, I, II, III, & IV, which we refer to as the Coordinated Gas Index Cases. A case management conference is expected in the next 60
days.



As to the gas index pricing lawsuits that have been
filed in federal court, in Texas-Ohio, the defendants filed a motion to dismiss in May 2004, on which the court held a hearing in January 2005. We are awaiting the courts ruling. The remaining federal court cases are pending transfer,
or have already been transferred, to the federal judge in Nevada who is also currently presiding over the Texas-Ohiomatter.



We are analyzing all of these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or
to estimate the damages, if any, that might be incurred in



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WEST COAST POWER LLC



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



connection with these lawsuits. We do not believe that any liability that we might incur as a result of this litigation would have a material adverse effect
on our financial condition, results of operations or cash flows.



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



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