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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



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FORM 10-K



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



For the fiscal year ended December 31, 2003



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



For the transition period from  to



Commission file number: 000-29311



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DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)



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|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Delaware                                                       |  | 94-3248415                          
|(State 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                |  |                                         



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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  x    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.    x



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



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



TABLE OF CONTENTS



|            |  |                                                                                       |  |     
|----------- |  | ------------------------------------------------------------------------------------- |  | ----
|            |  |                                                                                       |  | Page
|PART I      |  |                                                                                      
|Definitions |  | 2                                                                                    
|Item 1.     |  | Business                                                                              |  | 2   
|Item 2.     |  | Properties                                                                            |  | 22  
|Item 3.     |  | Legal Proceedings                                                                     |  | 22  
|Item 4.     |  | Submission of Matters to a Vote of Security Holders                                   |  | 22  
|            | 
|PART II     |  |                                                                                      
|Item 5.     |  | Market for Registrants Common Equity and Related Stockholder Matters                 |  | 23  
|Item 6.     |  | Selected Financial Data                                                               |  | 24  
|Item 7.     |  | Managements Discussion and Analysis of Financial Condition and Results of Operations |  | 25  
|Item 7A.    |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 60  
|Item 8.     |  | Financial Statements and Supplementary Data                                           |  | 64  
|Item 9.     |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  |  | 64  
|Item 9A.    |  | Controls and Procedures                                                               |  | 64  
|            | 
|PART III    |  |                                                                                      
|Item 10.    |  | Directors and Executive Officers of the Registrant                                    |  | 65  
|Item 11.    |  | Executive Compensation                                                                |  | 65  
|Item 12.    |  | Security Ownership of Certain Beneficial Owners and Management                        |  | 65  
|Item 13.    |  | Certain Relationships and Related Transactions                                        |  | 65  
|Item 14.    |  | Principal Accountant Fees and Services                                                |  | 65  
|            | 
|PART IV     |  |                                                                                      
|Item 15.    |  | Exhibits, Financial Statement Schedules and Reports on Form 8-K                       |  | 66  
|Signatures  |  | 73                                                                                   





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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-64. 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.



Since the beginning of 2003, we have completed a number of restructuring and
refinancing transactions designed to reduce our debt and other obligations, improve our liquidity position and clarify our business strategy. Significant accomplishments during 2003 include the following:



| |  | Sales of non-strategic assets, including the Hackberry LNG development project and ownership interests in domestic power generating projects;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------



| |  | Renewal of our primary bank credit facility through February 2005;
| | - | ------------------------------------------------------------------



| |  | Refinancing of approximately $2.0 billion in near-term debt and extending the related maturities to 2008 and beyond; and
| | - | ------------------------------------------------------------------------------------------------------------------------



| |  | Terminating four of eight power tolling arrangements.
| | - | -----------------------------------------------------



We also continued our exit from the customer risk management business. Our efforts are evidenced by a material reduction in the collateral postings
associated with this business, where the February 23, 2004 amount of $172 million is down from $806 million at year-end 2002. Our remaining customer risk management business, which primarily consists of four power tolling arrangements and related
gas transportation agreements, as well as our legacy gas and power trading positions, will continue to impact negatively our cash flows and operating results until the associated obligations have been terminated, restructured or satisfied.



Most recently, Dynegy entered into an agreement to sell
Illinois Power Company, which currently comprises its regulated energy delivery business, to Ameren Corp. It is targeting closure of the transaction by the end of 2004; however, closing is contingent on the receipt of required regulatory approvals
and other conditions. At closing, Ameren will assume all of Illinois Powers third-party debt and preferred stock obligations, which we estimate will be approximately $1.8 billion. In addition, Ameren will pay Dynegy $400 million in cash,
subject to working capital adjustments, and place $100 million into escrow subject to full release to Dynegy on December 31, 2010 or earlier upon the occurrence of specified events. Dynegy intends to use these proceeds to pay transaction fees and
expenses and to reduce its outstanding debt, including certain debt owed to ChevronTexaco. In addition to reducing its substantial leverage, the closing also would reinforce its business strategy of focusing on unregulated energy businesses.



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.



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Our principal executive office is located at 1000 Louisiana Street, Suite 5800, Houston, Texas 77002, and
our telephone number at that office is (713) 507-6400.



Our SEC
filings on Forms 10-K, 10-Q and 8-K (and amendments to such filings) are 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



Beginning in 2003, we are reporting the financial results of the following three business segments:



| |  | Power Generation (GEN):
| | - | -----------------------



| |  | Natural Gas Liquids (NGL); and
| | - | ------------------------------



| |  | Customer Risk Management (CRM).
| | - | -------------------------------



Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization not attributable
to our operating segments, as well as our discontinued operations. Set forth below is a discussion of our business segments.



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:



| |  | Capacity agreements under which we receive capacity payments from purchasers for regulatory purposes where capacity markets exist based on specific plant characteristics. Under
these types of contracts, the purchasers also acquire the option to call on energy from that specific plant or unit as needed based on an index price for power or the product of a fuel price and a heat rate. Some contracts may also include
provisions for reimbursement of variable operating and maintenance costs.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Tolling agreements under which we receive fixed payments in return for the customers ability to acquire energy from one of our facilities, generally based on an index price
for power or the product of a fuel price and a heat rate. Some contracts provide for the counterparty to handle the procurement and transportation of fuel to the facility for the energy that they require. Some contracts may also include provisions
for reimbursement of variable operating and maintenance costs.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



Our customers include 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 and, from time to time, we either purchase emission credits from third parties
in quantities sufficient to operate our plants within the emission



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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 in the generation of power into the marketplace. Please read RegulationPower Generation Regulation beginning on page 16 and Environmental and Other
Matters beginning on page 18 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 12,713 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.



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

(as of December 31, 2003)



|                         |  |                  |  |                                  |  |                  |  |                  
|------------------------ |  | ---------------- |  | -------------------------------- |  | ---------------- |  | -----------------
|Region/Facility          |  | Location         |  | Total NetGeneratingCapacity(MWs) |  | PrimaryFuel Type |  | Dispatch Type    
|Midwest-MAIN             |  |                  |  |                                  |  |                  |  |                  
|Baldwin                  |  | Baldwin, IL      |  | 1,761                            |  | Coal             |  | Baseload         
|Havana:                  |  |                  |  |                                  |  |                  |  |                  
|Havana Units 1-5         |  | Havana, IL       |  | 238                              |  | Oil              |  | Peaking          
|Havana Unit 6            |  | Havana, IL       |  | 445                              |  | Coal             |  | Baseload         
|Hennepin                 |  | Hennepin, IL     |  | 265                              |  | Coal             |  | Baseload         
|Oglesby                  |  | Oglesby, IL      |  | 54                               |  | Gas              |  | Peaking          
|Stallings                |  | Stallings, IL    |  | 82                               |  | Gas              |  | Peaking          
|Tilton (2)               |  | 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        |  | 416                              |  | Coal             |  | Baseload         
|Rocky Road (3)           |  | East Dundee, IL  |  | 165                              |  | Gas              |  | Peaking          
|Joppa (4)                |  | Joppa, IL        |  | 232                              |  | Coal/Gas         |  | Baseload/ Peaking
|                         |  |                  |  |                                  |  |                  |  |                  
|Combined                 |  |                  |  | 4,155                            |  |                  |  |                  
|Midwest-ECAR             |  |                  |  |                                  |  |                  |  |                  
|Michigan Power (3) (8)   |  | Ludington, MI    |  | 62                               |  | Gas              |  | Baseload         
|Riverside (9)            |  | Louisa, KY       |  | 495                              |  | Gas              |  | Peaking          
|Rolling Hills            |  | Wilkesville, OH  |  | 825                              |  | Gas              |  | Peaking          
|Foothills                |  | Louisa, KY       |  | 330                              |  | Gas              |  | Peaking          
|Renaissance (9)          |  | Carson City, MI  |  | 660                              |  | Gas              |  | Peaking          
|Bluegrass                |  | Oldham Co., KY   |  | 495                              |  | Gas              |  | Peaking          
|                         |  |                  |  |                                  |  |                  |  |                  
|Combined                 |  |                  |  | 2,867                            |  |                  |  |                  
|Northeast-NPCC           |  |                  |  |                                  |  |                  |  |                  
|Roseton (5)              |  | Newburgh, NY     |  | 1,210                            |  | Gas/Oil          |  | Intermediate     
|Danskammer:              |  |                  |  |                                  |  |                  |  |                  
|Danskammer Units 12     |  | Newburgh, NY     |  | 128                              |  | Gas/Oil          |  | Peaking          
|Danskammer Units 3-4 (5) |  | Newburgh, NY     |  | 370                              |  | Coal/Gas/Oil     |  | Baseload         
|                         |  |                  |  |                                  |  |                  |  |                  
|Combined                 |  |                  |  | 1,708                            |  |                  |  |                  
|Southeast-SERC           |  |                  |  |                                  |  |                  |  |                  
|Calcasieu                |  | Sulphur, LA      |  | 320                              |  | Gas              |  | Peaking          
|Heard County             |  | Heard County, GA |  | 495                              |  | Gas              |  | Peaking          
|Rockingham               |  | Rockingham, NC   |  | 825                              |  | Gas/Oil          |  | Peaking          
|Hartwell (3) (8)         |  | Hartwell, GA     |  | 150                              |  | Gas              |  | Peaking          
|Commonwealth (3) (8)     |  | Chesapeake, VA   |  | 172                              |  | Gas              |  | Peaking          
|                         |  |                  |  |                                  |  |                  |  |                  
|Combined                 |  |                  |  | 1,962                            |  |                  |  |                  
|West-WECC                |  |                  |  |                                  |  |                  |  |                  
|Long Beach (6)           |  | Long Beach, CA   |  | 235                              |  | Gas              |  | Peaking          
|Cabrillo IEncina (6)    |  | Carlsbad, CA     |  | 485                              |  | Gas              |  | Intermediate     
|Black Mountain (7) (8)   |  | Las Vegas, NV    |  | 43                               |  | Gas              |  | Baseload         
|El Segundo (6)           |  | El Segundo, CA   |  | 335                              |  | Gas              |  | Intermediate     
|Cabrillo II (6)          |  | San Diego, CA    |  | 101                              |  | Gas              |  | Peaking          
|                         |  |                  |  |                                  |  |                  |  |                  
|Combined                 |  |                  |  | 1,199                            |  |                  |  |                  
|Texas-ERCOT              |  |                  |  |                                  |  |                  |  |                  
|CoGen Lyondell           |  | Houston, TX      |  | 610                              |  | Gas              |  | Baseload         
|Oyster Creek (3) (8)     |  | Freeport, TX     |  | 212                              |  | Gas              |  | Baseload         
|                         |  |                  |  |                                  |  |                  |  |                  
|Combined                 |  |                  |  | 822                              |  |                  |  |                  
|TOTAL                    |  |                  |  | 12,713                           |  |                  |  |                  
|                         |  |                  |  |                                  |  |                  |  |                  

---

|(1) | We own 100% of each unit listed except as otherwise indicated.
|--- | --------------------------------------------------------------

|(2) | DMG subleases the Tilton facility from Illinois Power.
|--- | ------------------------------------------------------

|(3) | We own a 50% interest in these facilities.
|--- | ------------------------------------------

|(4) | Dynegy owns a 20% interest in this facility. Dynegy has agreed to sell this interest to Ameren in connection with the Illinois Power transaction. Please read Note 22Subsequent
Event beginning on page F-62 for further discussion.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(5) | 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 32.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(6) | We own a 50% interest in each of these facilities through West Coast Power, L.L.C., a joint venture with NRG Energy.
|--- | --------------------------------------------------------------------------------------------------------------------

|(7) | We own a 50% interest in this facility through a joint venture with ChevronTexaco.
|--- | ----------------------------------------------------------------------------------

|(8) | We will seek to sell these assets in 2004 as they are considered non-strategic to this business.
|--- | ------------------------------------------------------------------------------------------------

|(9) | We lease these facilities.
|--- | --------------------------



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Midwest regionMid-America Interconnected Network Reliability Council (MAIN). At
December 31, 2003, we owned or leased interests in 10 generating facilities with an aggregate net generating capacity of 4,155 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 is sold pursuant to a power purchase agreement between DMG and Illinois Power. This
agreement, which is served through Illinois Powers former generation facilities now owned or leased by DMG, provides Illinois Power with approximately 70% of its capacity requirements through December 2004. The contract provides 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 agreement, DMG bears ultimate responsibility for serving
Illinois Powers load as the provider of last resort; it also supplies 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
2003.



In connection with Dynegys agreement to sell
Illinois Power to Ameren, which Dynegy is targeting for closing by the end of 2004, we also agreed, conditioned on closing of the sale, to sell 2,800 MWs of capacity and up to 11.5 million MWh of energy to Illinois Power at fixed prices for two
years beginning in January 2005. 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 with an option to purchase energy at market-based prices. Under this arrangement, we would no
longer be the provider of last resort to Illinois Power. If the Illinois Power sale closes before year-end, the parties would continue under the current agreement through its December 31, 2004 expiration. If Dynegy is unable to complete the sale of
Illinois Power, any new agreement with Illinois Power may not be executed at the same rates as our existing agreement. Please read Note 22Subsequent Event beginning on page F-62 for further discussion.



Approximately 5% of our capacity, incremental to the capacity committed under
the Illinois Power power purchase agreement, is sold under capacity contracts, 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 Area, or ECAR, and the Pennsylvania-New Jersey-Maryland market, or PJM.



The MAIN region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERCs
estimated 2003 reserve margin of 25%, which is in excess of the MAIN regions target minimum reserve margin of 15-17%. This overcapacity has depressed energy and capacity prices 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 4-6 years.



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Midwest regionEast Central Reliability Area (ECAR).We own or lease interests in six
generating facilities with an aggregate net generating capacity of 2,867 MWs located within ECAR. Approximately 19% of this capacity is under contract. A contract for the Michigan Power facilitys 62 MWs of net generating capacity expires in
December 2030. A contract for the Renaissance facilitys 495 MWs of net generating capacity expired in September 2003, but at the end of 2003, we entered into another contract for the 495 MWs of the Renaissance facilitys generating
capacity, which expires in September 2004. The generating capacity of the ECAR facilities represents approximately 2% of the generating capacity within the region. We entered into an agreement to sell our interest in the Michigan Power facility in
February 2004.



The majority of the power generated by our ECAR
facilities is sold to wholesale customers in the ECAR market, which includes all or portions of the states of Indiana, Ohio, Michigan, Virginia, West Virginia, Tennessee, Kentucky, Maryland and Pennsylvania.



The ECAR region currently has excess generation capacity as a result of
recent development projects. This overcapacity is evidenced by the NERCs estimated 2003 reserve margin of 29%. ECAR has not explicitly stated a target reserve margin range, but we believe it to be consistent with MAINs 15-17% target.
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 4-6 years.



Northeast region  Northeast Power Coordinating Council (NPCC). We own or 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. We are committed to sell approximately 12% of the capacity from our DNE facilities to Central Hudson Gas & Electric Corporation, from whom we acquired the facilities, pursuant to a transitional power purchase
agreement that expires in October 2004. The revenues and cash flows from this agreement are not material to this segments results of operations.



All of our NPCC facilities are in the New York Independent System Operator (NYISO) control area. Due to transmission constraints, prices vary across the
state and are generally higher in the Eastern part of New York, where our facilities are located, and in New York City. We receive energy and capacity values from our New York facilities that are significantly higher than in most other regions.
Current reserve margins of 22% are somewhat above the NYISOs reserve margin target of 18%. However, NYISO stated in its May 2003 report that there are insufficient development projects currently planned to meet its expected load growth of 1.5%
and expected plant retirements through 2008.



Southeast
regionSoutheast Electric Reliability Council (SERC).We own interests in five generating facilities with an aggregate net generating capacity of 1,962 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, Georgia and Florida. The generating capacity of these facilities represents approximately 1% of the generating capacity in SERC.
Of our 1,962 MWs of net generating capacity in SERC, 1,242 MWs, or 63%, is under capacity and energy contracts. A contract for the Rockingham facilitys 600 MWs of capacity expired in December 2003. A contract for the Calcasieu facilitys
320 MWs of capacity expires in December 2004. A contract for the Commonwealth facilitys 172 MWs of capacity expires in May 2017, while a contract for the Hartwell facilitys 150 MWs of capacity expires in May 2019. In January and February
2004, we signed two agreements to sell an aggregate 215 MWs of our Rockingham facilitys net generating 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 expires in September 2004.



The SERC region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERCs estimated 2003 reserve margin of 53%, which significantly exceeds
SERCs 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 until after 2010. Overcapacity is less severe in the VACAR sub-region of SERC, where we believe market conditions may require new
capacity additions within the next 3-5 years.



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West regionWestern Electricity Coordinating Council (WECC).We own interests in five
generating facilities with an aggregate net generating capacity of 1,199 MWs within WECC. The WECC regional market includes the Canadian provinces of Alberta and British Columbia, parts of Mexico and 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 1,199 MWs of net generating capacity in the WECC, 1,156 MWs
consists of our 50% share of the 2,312 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 is substantially covered by a contract between
one of our marketing subsidiaries, as agent for the facility owners, and the CDWR, which expires in December 2004. The agreement provides for a firm commitment of 600 MWs of on-peak capacity and 200 MWs of baseload capacity, in each case at a fixed
price. The agreement also contains a contingent component pursuant to which the CDWR can elect to reserve up to an additional 1,500 MWs of on-peak capacity and 1,500 MWs of off-peak capacity, subject to required minimum reservation amounts of 500
MWs and 200 MWs, respectively. We receive a fixed capacity payment for any contingent amounts reserved as well as payments for contingent energy actually sold, which energy payments are based on fuel, operating and maintenance and start-up costs.



Unless a new contract is signed or the contract is
renegotiated prior to the expiration of the CDWR contract, our West Coast Power assets will operate as merchant facilities beginning in 2005. Due to transmission constraints, power prices vary substantially across WECC and are generally highest in
Southern California, where our West Coast Power facilities are located. While there is not currently an oversupply of generation in Southern California, and power prices are generally strong, it is likely that our West Coast Power facilities will be
significantly less profitable as merchant facilities compared to profits generated under the CDWR contract.



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 16Commitments and ContingenciesSummary of Material Legal Proceedings California Market Litigation beginning on page

F-42.



Texas regionElectric Reliability Council of Texas (ERCOT).We own two generating facilities with an aggregate net generating capacity of 822 MWs located in ERCOT, which represents approximately 1%
of the generating capacity in the ERCOT region. The ERCOT market is comprised of the majority of the state of Texas.



Approximately 30% of our capacity in this region, consisting of the 212 MWs of capacity at the Oyster Creek facility and 65 MWs of capacity at our CoGen
Lyondell facility, is sold under capacity agreements which expire in October 2014 and December 2006, respectively. We entered into an agreement to sell our interest in Oyster Creek in February 2004. Please see Note 9Unconsolidated
InvestmentsGEN Investments beginning on page F-27.



The ERCOT region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERCs estimated 2003 reserve margin of 36%, 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 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 6-9 years.



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 towards Texas, Illinois and New York.



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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 production
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 20 gas processing plants, including 12 plants we operate. We also operate over
9,368 miles of natural gas gathering pipeline systems associated with the 12 operated facilities and two stand-alone gas gathering pipeline systems where gas is treated and/or processed at third-party plants. Our upstream assets are located in the
high-growth oil and gas exploration and production areas of North Texas and Louisiana, and the mature Permian Basin of Texas and New Mexico. During 2003, we processed an average of 1.8 Bcf/d of natural gas and produced an average of 82,000 barrels
per day of natural gas liquids, in each case, net to our ownership interests. We are also party to 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 receiving its share of the
proceeds from our sale of the commodities.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Under percent of liquids, or POL, contracts, a producer delivers to us a percentage of the natural gas liquids as our fee 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 its share of the natural gas liquids in kind or the proceeds from our sale of the natural gas liquids.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  | 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 fee for processing and 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 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 gas pipeline 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 - and 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, 2003 throughput and production levels. Our field plants are in the mature and prolific Permian Basin, located in 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.



LOGO



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In our field plants we process natural gas primarily under POP contracts. In 2003, approximately 85% of
the volumes processed were under POP settlement terms and approximately 15% were processed primarily under KW or WHP contracts. As a result of our successful efforts to restructure certain contracts from KW to POP contracts, approximately 98% of the
volumes we process in our field plants are now settled under POP contracts. This is particularly important because the natural gas processed by all of these facilities contains natural gas liquids in sufficient quantities to require that they 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 driver for our field plants the absolute price of both residue gas and natural gas liquids.



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 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, including our
capacity, 2003 throughput and production levels.



LOGO



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 economical to extract natural gas liquids (i.e., when the
value of the natural gas liquids is less than the value of 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. However, 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 following charts show a volume breakdown of 2003 contract settlements for our straddle plants and an estimate of our 2004 contract mix. With the prevailing market conditions entering 2004, we anticipate 2004
settlements to be similar to the outcome in 2003.



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|     |  | 
|---- |  | 
|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 will settle under POL terms. When processing economics are less
favorable, as they were in 2003, we do have some KW exposure to the frac spread. Our view is that strong natural gas prices will continue to depress the frac spread for the foreseeable future. However, our frac spread exposure is somewhat limited
because most of the hybrid contracts in this price environment settle on fee terms, which are relatively insensitive to price movements that depress the frac spread.



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.



Our field plants recovered an average of 4.24 gallons of natural gas liquids per Mcf of raw gas processed in 2003. The straddle plants recovered an average of 1.10 gallons of natural gas liquids per Mcf of raw gas
processed in 2003. The component split of mixed natural gas liquids produced by our field and straddle plants in 2003 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 produced from all areas other
than the Gulf of Mexico, we process the gas at field plants owned by us or by third parties. The 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 straddle plants in which we own an interest, and in some cases operate, and in plants owned by third parties. 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 processing is uneconomical. 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. The
dedication made by ChevronTexaco may be limited to certain productive horizons and/or may only be partially committed as to acreage.



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Both types of processing agreements with ChevronTexaco allow either party to renegotiate 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 2003 and 2002, respectively, ChevronTexaco gas accounted for 46% and 27% of the total volume of gas we processed.



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



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The percentages of these products produced at our fractionators in 2003 are as follows:



LOGO



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 2003, these facilities fractionated an aggregate average of 167,000 gross barrels per day (net to Dynegys 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 low 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 and Kentucky 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;
| | - | -----------------------------------------------------------------------------------------------------------------------------



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| |  | 85 transport tractors and 114 tank trailers;
| | - | --------------------------------------------



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



| |  | More than 320,000 barrels of capacity in our pressurized LPG barge fleet.
| | - | -------------------------------------------------------------------------



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 in obtaining such supply or through a
minimum fee per gallon. In 2003, we sold an average of 45,100 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. 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 44% and 35% of the refinery services business natural gas liquids purchases in 2003 and 2002, 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 our refinery/gas supply contracts and from our other owned and/or managed distribution and marketing assets. 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. We generally sell propane at a fixed or posted price at the time of delivery. In 2003, we
sold an average of 47,100 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 2003, our distribution and marketing services business sold an average of 219,500 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.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





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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.



In 2003 and 2002, approximately 32% and 28%, respectively, of our 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, as well as gas transportation contracts and our remaining gas and power trading positions. Pursuant to these power tolling arrangements, we are obligated
to make aggregate payments of approximately $2.3 billion to our counterparties in exchange for access to power generated by their facilities. Given our decision to exit the CRM business, we no longer consider this access to power as key to our
business strategy. We are actively pursuing opportunities to terminate, assign or renegotiate the terms of our contractual obligations related to some of 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  |  | ExpirationDate |     |  | MWs |  | 2004                     |     | 2005          |   | 2006 |  | 2007 - 2017
|                               |  |           |  |                |     |  |     |  |                          |     | (in millions) |   |     
|Sterlington/Quachita           |  | Louisiana |  | 9/2017         | (1) |  | 835 |  | $                        | 58  |               | $ | 59   |  | $           | 61  |  | $ | 690  
|Gregory                        |  | Texas     |  | 7/2005         |     |  | 335 |  |                          | 23  |               |   | 13   |  |             |    |  |   |     
|Kendall                        |  | Illinois  |  | 3/2017         | (1) |  | 578 |  |                          | 39  |               |   | 41   |  |             | 42  |  |   | 429  
|Sithe Independence             |  | New York  |  | 11/2014        |     |  | 955 |  |                          | 40  |               |   | 41   |  |             | 42  |  |   | 375  
|                               |  |           |  |                |     |  |     |  |                          |     |               |   |      |  |             |     |  |   |      
|Total Annual Capacity Payments |  |           |  |                |     |  |     |  |                          | 160 |               |   | 154  |  |             | 145 |  |   | 1,494
|Other Fixed Obligations (2)    |  |           |  |                |     |  |     |  |                          | 74  |               |   | 74   |  |             | 74  |  |   | 594  
|                               |  |           |  |                |     |  |     |  |                          |     |               |   |      |  |             |     |  |   |      
|Total Cash Commitments         |  |           |  |                |     |  |     |  | $                        | 234 |               | $ | 228  |  | $           | 219 |  | $ | 2,088
|                               |  |           |  |                |     |  |     |  |                          |     |               |   |      |  |             |     |  |   |      

---

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



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, 2003, we have exited approximately 85% 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. 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.



Corporate and 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, corporate legal, corporate human resources, administration and technology. Corporate general and administrative expenses, income taxes and



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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 15 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 22 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 18 for a discussion of environmental regulations affecting our business.



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.



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 Procedures, or AMP, that caps bid prices based on the cost characteristics of power generating facilities, such as our DNE facilities. In February 2004, the FERC accepted, subject to certain modifications, the NYISOs
proposed real-time scheduling software, which we refer to as RTS. While the RTS further entrenches the AMP in the NYISO market system, the FERC did not permit the NYISO to extend the real-time AMP to areas outside New York City where our DNE
facilities are located. Consequently, our DNE facilities are not presently subject to the real-time AMP.



The California energy crisis, which arose in 2000, precipitated a number of 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. Please read Note 16Commitments and Contingencies  Summary of Material Legal Proceedings  FERC and Related Regulatory
Investigations  Requests for Refunds beginning on page F-43 for further discussion of our California activities and related regulatory matters.



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We are also subject to the FERCs new market behavior rules, which emerged from its consideration of
market manipulation in the Western markets. The new rules apply to sales in organized and bilateral markets and spot markets, as well as long-term sales. The remedies for violating the new 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 new rules will affect the costs or other aspects of our operations is uncertain. However, we do not anticipate that our entities with
market-based rates for wholesale power sales or our entity with blanket natural gas sales certificate authority will be impacted materially by the new rules.



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.



In December 1999, the FERC issued Order No. 2000, which addressed a number of
issues relating to the regional transmission of electricity. In particular, Order No. 2000 provided for regional transmission organizations, or RTOs, to control the transmission facilities within a particular region. After a period of progress
toward voluntary creation of RTOs as envisioned by the FERC, activity has slowed due to controversy and uncertainty concerning required standards and structures for such entities. More recently, the FERC proposed new rules designed to result in the
adoption of generally standardized market terms and conditions governing interstate transmission and operation of markets by RTOs. In April 2003, the FERC issued a white paper on its wholesale power market platform, shifting its focus from market
standardization to allow regional state committees to oversee timelines and market design of RTOs and ISOs in their areas. The impact of these RTOs, ISOs and new rules on our electricity marketing operations cannot be predicted.



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 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, and in some cases, repeal of measures implementing retail competition, are
proceeding in several states, including California, the results of which could affect our operations.



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Legislation. The U.S. Congress is considering passage of comprehensive energy legislation
that will impact us. The legislation includes enhanced reliability measures, various transmission improvement and financing provisions, and new market reporting requirements. 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.



ENVIRONMENTAL AND OTHER MATTERS



General. 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.



Environmental Expenditures. Our aggregate expenditures for compliance with laws and regulations related to the protection of the environment were approximately $50 million in 2003, compared to
approximately $82 million in 2002 and approximately $81 million in 2001. We estimate that total environmental expenditures (both capital and operating) in 2004 will be approximately $20 million. A majority of our environmental expenditures relate to
the federal Clean Air Act and comparable state laws and regulations, and the reduced amount for 2004 reflects the fact that we have already expended significant capital to comply with current regulations. 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. 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 oxide 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.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  | 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 oxide. The current compliance deadline for implementation of these emission reductions is 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 has been largely completed; consequently, we expect the power generation system
will meet 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 $25 million through 2007 pursuant to such plans.
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Baldwin Station Litigation. DMG is the subject of an NOV from the EPA and a complaint filed by the EPA and the Department of Justice in federal district court alleging that we failed to obtain required
construction permits in connection with certain repair and maintenance activities at our Baldwin Station in violation of the Clean Air Act and certain related federal and Illinois regulations. The trial to address the claims of liability in this
matter concluded in September 2003 and we are awaiting the issuance of a decision from the presiding judge. Please read Note 16Commitments and ContingenciesSummary of Material Legal ProceedingsBaldwin Station Litigation beginning
on page F-41 for further discussion of this lawsuit.



Remedial Laws. We are also subject to environmental remediation requirements, 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 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 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. The requirements of this new DOT rule will likely increase the costs of pipeline operations.
We believe that such costs will not be material to our financial position or results of operations.



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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. We are performing further analyses that likely will result in additional security 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 21 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.



Subject to resolution of the complaints filed by the EPA and the DOJ against
DMG, which are described in Note 16Commitments and ContingenciesSummary of Material Legal ProceedingsBaldwin Station Litigation beginning on page F-41, 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 with respect
to which significant capital expenditures could be incurred, depending on the outcome.



Multi-Pollutant Air Emission Initiatives. Various multi-pollutant proposals have been introduced at the federal and state level. Examples are the Clear Skies Act of 2003 and the Interstate
Air Quality rule announced in late 2003. These proposals are aimed at long-term reductions of multiple pollutants produced from electric generating facilities. Additional EPA initiatives include designation of areas as attainment, non-attainment or
non-classifiable for the new particulate matter (PM) 2.5 standard. The PM 2.5 standard is aimed at the reduction of fine (smaller than 2.5 microns in diameter) particulate matter. Fossil fuel-fired power plants in the United States 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.



MACT. The EPA previously announced its determination to regulate hazardous air pollutants, including mercury, from coal and oil-fired steam electric generating units and proposed the Utility MACT rule in
mid December 2003. The proposed rule specified new mercury emission limits applicable to coal-fired steam electric generators and new nickel emission limits applicable to oil-fired steam electric generators. Alternatively, the EPA concurrently
proposed to limit mercury emissions from coal fired power plants under a cap-and-trade program permitting trading of emission allowances. Under either approach, sources will be subject to mercury and nickel air emissions restrictions as soon as 2007
unless an extension is granted.



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 the DNE facilities expired in 1992.
However, under New York State law, each permit remains in effect and allows for continued operation under the terms of the original permits, given that timely applications requesting renewal were



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filed as required. In November 2002, several environmental groups filed suit seeking to require the NYDEC to issue a
draft discharge permit for the Danskammer plant. The Court ordered NYDEC to issue a draft permit, which it did in June 2003. DNE believes the draft permit contains provisions that are more stringent than necessary and has requested a hearing on the
permit. Several environmental groups have intervened as opponents in the administrative permit proceeding, taking the position that the draft permit is not sufficiently stringent. In a related action, we have challenged the NYDEC decision that its
proposed permit would not cause significant environmental impacts based on the agencys failure to consider the impacts of potential forced outages under the terms of the draft permit upon the reliability of the electric power supply to the
Hudson River Valley and New York City.



In November 2001, the
EPA issued rules imposing additional technology-based requirements on new cooling water intake structures. The EPA issued a final rule for existing intake structures in February 2004. We believe that the requirements of this new rule are consistent
with the provisions proposed in the Danskammer permit application. As noted above, the draft permit is the subject of administrative challenges by both DNE and environmental groups. We are evaluating the impact of the new rule on our other
facilities; however, we cannot predict what plant modifications may be necessary to comply with this final 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 several energy companies, including Dynegy, if adopted by the United States. The treaty has not been ratified by the Senate and is unlikely to become effective in the United States. Nevertheless, it has prompted the introduction of
several federal and state legislative and regulatory proposals that would address climate change issues through voluntary emission reductions, emissions trading programs or mandatory emission reductions. If any of these proposals become law, they
could affect our business by imposing substantial additional administrative or capital expenditure burdens. We are currently evaluating the impact of the various proposals on our operations.



For these ongoing matters, 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. With respect to the Danskammer water permit, we similarly cannot predict the results of the related administrative proceedings or their affects on
us. It is possible that the result of these ongoing initiatives, as well as the outcome of the administrative proceedings surrounding our Danskammer water permit, 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 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 will more than likely continue to increase 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.



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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 60 for further discussion of these risks.



In addition to these commercial risks, we also face the risk of reputational damage 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 reputational damage in the industries in which we compete and to financial loss. Please read Item 9A. Controls and Procedures beginning
on page 64 for further discussion of our internal control systems.



SIGNIFICANT CUSTOMER



For the years ended
December 31, 2003, 2002 and 2001, approximately 20%, 19% and 12%, respectively, of our consolidated revenues and approximately 26%, 51% and 50%, respectively, of our consolidated cost of sales were derived from transactions with ChevronTexaco and
its subsidiaries. In addition, for the years ended December 31, 2003, 2002 and 2001, approximately 11%, 9% and 14%, 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 2003, 2002 or 2001.



EMPLOYEES



At December
31, 2003, we had approximately 767 employees at our administrative offices and approximately 1,531 employees at our operating facilities. Approximately 592 employees at Dynegy-operated facilities are subject to collective bargaining agreements with
various unions. We believe relations with our employees are satisfactory.



Item 2.Properties



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 3. 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. Please read Note 12Debt beginning on page F-31 for further discussion of the amended
credit facility.



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, Massachusetts, and Texas; and the Canadian province of Ontario.



Item 3.Legal Proceedings



For a description of our material legal proceedings, please read Note 16Commitments and Contingencies beginning on page F-40, 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.



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PART II



Item 5.Market for Registrants Common Equity and Related Stockholder Matters



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, 2003 for a discussion of these plans.



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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.



Dynegys Selected Financial Data



|                                                     |  |                         |        |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |       |  
|---------------------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | - |  | ---- | ------ | - |  | - | ----- | -
|                                                     |  | Year Ended December 31, |       
|                                                     |  | 2003                    |        |   | 2002 |   |        | 2001 |  |   | 2000   |   |  | 1999 |       
|                                                     |  | (in millions)           |       
|Statement of Operations Data (1):                    |  |                         |        |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |       |  
|Revenues                                             |  | $                       | 4,714  |   |      | $ | 4,245  |      |  | $ | 7,789  |   |  | $    | 8,211  |   |  | $ | 4,821 |  
|General and administrative expenses                  |  |                         | (293   | ) |      |   | (255   | )    |  |   | (350   | ) |  |      | (226   | ) |  |   | (208  | )
|Depreciation and amortization expense                |  |                         | (330   | ) |      |   | (270   | )    |  |   | (296   | ) |  |      | (239   | ) |  |   | (115  | )
|Asset impairment, abandonment and other charges      |  |                         | (4     | ) |      |   | (184   | )    |  |   |       |   |  |      |       |   |  |   |      |  
|Goodwill impairment                                  |  |                         |       |   |      |   | (724   | )    |  |   |       |   |  |      |       |   |  |   |      |  
|Operating income (loss)                              |  |                         | (255   | ) |      |   | (1,129 | )    |  |   | 774    |   |  |      | 648    |   |  |   | 184   |  
|Interest expense                                     |  |                         | (338   | ) |      |   | (187   | )    |  |   | (137   | ) |  |      | (95    | ) |  |   | (77   | )
|Income tax expense (benefit)                         |  |                         | (177   | ) |      |   | (296   | )    |  |   | 321    |   |  |      | 197    |   |  |   | 41    |  
|Net income (loss) from continuing operations         |  |                         | (278   | ) |      |   | (1,146 | )    |  |   | 442    |   |  |      | 358    |   |  |   | 93    |  
|Income (loss) on discontinued operations (2)         |  |                         | (12    | ) |      |   | (100   | )    |  |   | (19    | ) |  |      | 40     |   |  |   | 44    |  
|Cumulative effect of change in accounting principles |  |                         | 42     |   |      |   |       |      |  |   | 2      |   |  |      |       |   |  |   |      |  
|Net income (loss)                                    |  | $                       | (248   | ) |      | $ | (1,246 | )    |  | $ | 425    |   |  | $    | 398    |   |  | $ | 137   |  
|Cash Flow Data:                                      |  |                         |        |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |       |  
|Cash flows from operating activities                 |  | $                       | 760    |   |      | $ | 26     |      |  | $ | 176    |   |  | $    | 408    |   |  | $ | 40    |  
|Cash flows from investing activities                 |  |                         | (423   | ) |      |   | 804    |      |  |   | (1,341 | ) |  |      | (951   | ) |  |   | (391  | )
|Cash flows from financing activities                 |  |                         | (652   | ) |      |   | (282   | )    |  |   | 1,300  |   |  |      | 528    |   |  |   | 399   |  
|Cash dividends or distributions to partners, net     |  |                         |       |   |      |   |       |      |  |   |       |   |  |      |       |   |  |   | (8    | )
|Capital expenditures, acquisitions and investments   |  |                         | (209   | ) |      |   | (766   | )    |  |   | (2,600 | ) |  |      | (959   | ) |  |   | (521  | )
|                                                     | 
|                                                     |  | December 31,            |       
|                                                     |  | 2003                    |        |   | 2002 |   |        | 2001 |  |   | 2000   |   |  | 1999 |       
|                                                     |  | (in millions)           |       
|Balance Sheet Data (1):                              |  |                         |        |   |      |   |        |      |  |   |        |   |  |      |        |   |  |   |       |  
|Current assets                                       |  | $                       | 2,495  |   |      | $ | 7,120  |      |  | $ | 8,699  |   |  | $    | 10,437 |   |  | $ | 2,658 |  
|Current liabilities                                  |  |                         | 2,229  |   |      |   | 6,840  |      |  |   | 7,995  |   |  |      | 9,829  |   |  |   | 2,467 |  
|Property, plant and equipment, net                   |  |                         | 6,302  |   |      |   | 6,415  |      |  |   | 6,767  |   |  |      | 5,117  |   |  |   | 2,090 |  
|Total assets                                         |  |                         | 10,280 |   |      |   | 16,846 |      |  |   | 19,678 |   |  |      | 19,046 |   |  |   | 6,451 |  
|Long-term debt (excluding current portion)           |  |                         | 3,664  |   |      |   | 3,276  |      |  |   | 2,707  |   |  |      | 1,635  |   |  |   | 1,372 |  
|Notes payable and current portion of long-term debt  |  |                         | 150    |   |      |   | 484    |      |  |   | 256    |   |  |      |       |   |  |   | 192   |  
|Non-recourse debt                                    |  |                         |       |   |      |   |       |      |  |   |       |   |  |      |       |   |  |   | 35    |  
|Subordinated debentures                              |  |                         |       |   |      |   | 200    |      |  |   | 200    |   |  |      | 200    |   |  |   | 200   |  
|Minority interest (3)                                |  |                         | 121    |   |      |   | 146    |      |  |   | 1,003  |   |  |      | 977    |   |  |   |      |  
|Total equity                                         |  |                         | 3,021  |   |      |   | 3,239  |      |  |   | 4,465  |   |  |      | 3,959  |   |  |   | 1,240 |  

---

|(1) | The Northern Natural (February 1, 2002) and BGSL (December 1, 2001) 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. Additionally, 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.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | 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).
| | - | ----------------------------------------------------------

|(3) | The 2001 and 2000 amounts include amounts relating to the Black Thunder transaction discussed in Note 12DebtBlack Thunder Secured Financing beginning on page F-34.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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 and
related gas transportation contracts, as well as legacy gas and power trading positions. Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and 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 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 summary of our current liquidity position and items that could impact our liquidity position in 2004 and beyond. Please note that this
Overview section is merely a summary and should be read together with the remainder of Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations, as well as the 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 more than 12,700 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 and, to a lesser extent,
natural gas, 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. Please read Liquidity and Capital ResourcesInternal Liquidity
SourcesCash Flows from Operations beginning on page 34 for a discussion of our views on the current pricing environment and its anticipated long-term recovery.



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 other costs through disciplined
management and safe, efficient operations;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | our ability to optimize our assets through forward 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, particularly the CDWR and Illinois Power power purchase agreements that are scheduled to expire at
the end of 2004. In connection with Dynegys recently announced agreement to sell Illinois Power to Ameren, we agreed,
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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conditioned upon the closing of the sale, to sell 2,800 MWs of capacity and up to 11.5 million MWh of
energy to Illinois Power at fixed prices for two years beginning in January 2005. The closing of the sale to Ameren, which is expected by the end of 2004, is subject to receipt of required regulatory approvals and other closing conditions. Please
read Note 22Subsequent Event beginning on page F-62 for further discussion.



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 the relationship between the
two, commonly referred to as the frac spread. In our upstream business, we continued the restructuring of our contract portfolio in 2003. As a result, our current contract mix has reduced our exposure to frac spread risk. Please read
Item 1. BusinessSegment DiscussionNatural Gas LiquidsUpstream Business beginning on page 8 for a detailed discussion of our current upstream contract mix.



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 other costs through disciplined management and
safe, efficient operations;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | reduced market liquidity and our obligation to post collateral to 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 low frac spread environment and the resulting reduction in volumes available for fractionation, distribution and marketing;
| | - | -----------------------------------------------------------------------------------------------------------------------------



| |  | the petrochemical industrys need for and utilization of our natural gas liquids feedstocks and related natural gas liquids facilities;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------



| |  | 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 our four remaining power tolling arrangements and
related gas transportation contracts, as well as our legacy gas and power trading positions. We have significant, long-term fixed obligations associated with our tolling and gas transportation arrangements, which obligations 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 tolling plants are located, as well as our ability to re-market the related capacity under the transportation arrangements. It also will be significantly impacted by our ability to restructure or terminate one or more of our power
tolling arrangements, which we expect would require a significant cash payment.



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##### Table of Contents

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 15 for further discussion.



Corporate and Other. Beginning January 1, 2003, Corporate and
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 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 expected to yield savings beginning in 2004; general and administrative costs
also will be impacted by, among other things, any future corporate-level litigation reserves or settlements; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | income taxes will be impacted by our ability to realize our significant deferred tax assets, including loss carryforwards.
| | - | --------------------------------------------------------------------------------------------------------------------------



Liquidity. As of February 23, 2004, we had cash on hand of $266
million and available borrowing capacity of $866 million, for total liquidity of approximately $1.1 billion. During 2003, we maintained liquidity between $1.2 billion and $1.6 billion. Our ability to maintain our liquidity position in the future
will depend on a number of factors, including Dynegys ability to consummate the Illinois Power sale to Ameren and, over the longer term, to generate cash flows from our asset-based energy businesses in relation to our substantial debt
obligations and ongoing operating requirements.



For the next
12 months, assuming continuation of the current commodity pricing environment, we expect that our operating cash flows will be insufficient to satisfy our capital expenditures, debt maturities, increased interest expenses and operating commitments.
When combined with our cash on hand, proceeds from anticipated asset sales and capacity under our $1.1 billion revolving credit facility, however, we believe we have sufficient capital resources to satisfy these obligations during this period. To
further the deleveraging efforts of the consolidated enterprise, Dynegy also has stated its intent to explore other capital-raising activities, including potential public or private equity issuances. In addition, we will seek to renew or replace our
$1.1 billion revolving credit facility, which is scheduled to mature on February 15, 2005. Our liquidity position will be materially adversely affected if we are unable to renew or replace this facility, with respect to which our ability to borrow
and/or issue letters of credit could become increasingly important, on or before its scheduled maturity.



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 the restructuring work that we did during 2003 extended a substantial portion of our debt maturities from 2005-2006 to 2008 and beyond, positioning us to benefit from earnings and growth opportunities associated with this expected
recovery in the U.S. power markets. Conversely, although depressed frac spreads have negatively impacted our NGL segments downstream operations, our upstream business is currently operating in a relatively favorable pricing environment. Our
future financial condition and results of operations will be materially affected if the U.S. power markets fail to recover in accordance with our expectations or if we experience significant pricing deterioration in our NGL segment.



27



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##### Table of Contents

LIQUIDITY AND CAPITAL RESOURCES



Debt Maturities



During 2003, we consummated a series of refinancing and restructuring transactions comprised of the following:



| |  | Restructuring of $1.66 billion in credit facilities prior to their scheduled maturities, in connection with which Dynegy granted security interests in a substantial portion of the
available assets and stock of its direct and indirect subsidiaries, excluding Illinois Power;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Issuance of $1.75 billion of senior notes at a weighted average interest rate of 9.71% and a weighted average yield to maturity of 9.65%, which notes are secured on a second
priority basis by substantially the same collateral that secures the obligations under our restructured credit facility; and
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | The purchase of approximately $282 million of our $300 million 8.125% Senior Notes due 2005, virtually all of our $150 million 63⁄4% Senior Notes due 2005 and approximately $177
million of our $200 million 7.450% Senior Notes due 2006.
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In connection with the Refinancing, Dynegy also issued $225 million of convertible subordinated debentures in a private placement transaction at an interest rate of 4.75%, which debentures are convertible into Dynegys Class A common
stock and guaranteed by us on a senior unsecured basis. In addition, Dynegy restructured its $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock, which we refer to as the Series B Preferred Stock, previously held by a
ChevronTexaco subsidiary. Under this restructuring, which we refer to as the Series B Exchange, the Series B Preferred Stock was exchanged for $225 million in cash, $225 million principal amount of Dynegys Junior Unsecured Subordinated Notes
due 2016, which we refer to as the Junior Notes, and 8 million shares of Dynegys Series C Mandatorily Redeemable Convertible Preferred Stock due 2033 (liquidation preference $50 per share), which we refer to as the Series C preferred stock.



We used the net cash proceeds from these transactions,
together with approximately $300 million of cash on hand and additional funds received in the form of returned prepayments from ChevronTexaco under the Series B Exchange, to make the $225 million Series B Exchange payment, to purchase our senior
notes and to otherwise reduce our 2005 debt maturities as follows:



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



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



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



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



For a more complete description of these transactions, including the increasing interest rate
please read Note 11Refinancing and Restructuring Transactions beginning on page F-29.



As a result of these transactions, we extended a substantial portion of our 2005-2006 maturities to 2008 and beyond. Our aggregate maturities for long-term debt are as follows: 2004 - $150 million; 2005 - $102
million; 2006 - $44 million; 2007 - $184 million; 2008 - $225 million; thereafter - $3,109 million. Included in our 2004 maturities of $150 million is $71 million related to the Tilton capital lease. In October 1999, Illinois Power entered into a
sublease with DMG pursuant to which DMG is obligated to make all payments under the lease.



One important near-term maturity that remains is our $1.1 billion revolving credit facility, which is scheduled to mature on February 15, 2005. While we currently have no drawn amounts under this facility, our ability
to borrow and/or issue letters of credit under a revolving credit facility could become increasingly important, particularly if we are unable to generate operating cash flows relative to our substantial debt obligations and ongoing operating
requirements or to realize the asset sale proceeds we anticipate. We currently intend to renew or replace this facility during 2004, although we cannot guarantee that we will be successful.



28



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##### Table of Contents

While our restructuring and refinancing transactions have extended our significant debt maturities, they
also resulted in significantly increased interest expenses, as further described under Results of Operations  Interest Expense beginning on page 47. We also are subject to the more restrictive covenants that are contained in
the related transaction agreements. Specifically, among other limitations, these covenants limit our ability to incur additional indebtedness other than for refinancing purposes and require that a significant portion of proceeds from specified asset
sales and equity issuances be used to pay down outstanding indebtedness. For example, upon closing of Dynegys agreed sale of Illinois Power to Ameren, Dynegy must use 75% of the net cash proceeds to repay its Junior Notes. Dynegy also is
required to use 25% of the net cash proceeds of the sale to reduce permanently or cash collateralize the commitments under the facility, subject to certain exceptions, to the extent the Junior Notes are repaid up to $100 million. If the Junior Notes
are not outstanding, 100% of the net cash proceeds from asset sales are required to be used, subject to certain exceptions, to reduce the commitments under the revolver. While we are currently in compliance with these restrictive covenants, our
future financial condition and results of operations could be significantly affected by our ability to execute our business and financial strategies within the confines of these restrictive covenants.



The following table depicts our consolidated third-party debt obligations,
including the principle-like maturities associated with the DNE leveraged lease, and the extent to which they are secured as of December 31, 2003 and 2002:



|                                       |  |                  |       |   |                  |   |       |  
|-------------------------------------- |  | ---------------- | ----- | - | ---------------- | - | ----- | -
|                                       |  | December 31,2003 |       |   | December 31,2002 |  
|                                       |  | (in millions)    |      
|First Secured Obligations              |  | $                | 1,208 |   |                  | $ | 2,440 |  
|Second Secured Obligations             |  |                  | 1,750 |   |                  |   |      |  
|Unsecured Obligations                  |  |                  | 1,619 |   |                  |   | 2,147 |  
|                                       |  |                  |       |   |                  |   |       |  
|Subtotal                               |  |                  | 4,577 |   |                  |   | 4,587 |  
|Preferred Obligations                  |  |                  |      |   |                  |   | 200   |  
|                                       |  |                  |       |   |                  |   |       |  
|Total Obligations                      |  | $                | 4,577 |   |                  | $ | 4,787 |  
|                                       |  |                  |       |   |                  |   |       |  
|Less: DNE Lease Financing              |  |                  | (758  | ) |                  |   | (746  | )
|Less: Preferred Obligations            |  |                  |      |   |                  |   | (200  | )
|Other (1)                              |  |                  | (5    | ) |                  |   | (81   | )
|                                       |  |                  |       |   |                  |   |       |  
|Total Notes Payable and Long-term Debt |  | $                | 3,814 |   |                  | $ | 3,760 |  
|                                       |  |                  |       |   |                  |   |       |  

---

|(1) | Consists of net discounts on debt (totaling $5 million and zero at December 31, 2003 and December 31, 2002, respectively) 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. At December 31, 2002, the Tilton lease was off-balance sheet as it was accounted for as an operating lease.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Collateral Postings



We have substantially reduced our collateral postings since the end of 2002. As detailed in the table below, total
collateral postings are down by approximately $718 million as of February 23, 2004. The reduction is particularly pronounced in our CRM segment, which we commenced exiting in October 2002. Our collateral postings are down in that segment by more
than $634 million since year-end 2002 and by more than $800 million from their peak at September 30, 2002.



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##### Table of Contents

The following table summarizes our consolidated collateral postings to third parties by operating
division at February 23, 2004, December 31, 2003 and December 31, 2002:



|      |  |                  |     |                  |   |                  |  |   |      
|----- |  | ---------------- | --- | ---------------- | - | ---------------- |  | - | -----
|      |  | February 23,2004 |     | December 31,2003 |   | December 31,2002
|      |  | (in millions)   
|GEN   |  | $                | 146 |                  | $ | 136              |  | $ | 168  
|CRM   |  |                  | 172 |                  |   | 121              |  |   | 806  
|NGL   |  |                  | 144 |                  |   | 179              |  |   | 166  
|Other |  |                  | 8   |                  |   | 8                |  |   | 48   
|      |  |                  |     |                  |   |                  |  |   |      
|Total |  | $                | 470 |                  | $ | 444              |  | $ | 1,188
|      |  |                  |     |                  |   |                  |  |   |      



As described in Note
12DebtCredit Facility beginning on page F-31,we incur a 0.15% fronting fee upon the issuance of letters of credit under our restructured credit facility. A letter of credit fee is also payable on the undrawn amount of each letter
of credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. To reduce these fees, we have used, and expect to continue to use, cash on hand, as opposed to letters of credit, to satisfy our future collateral obligations
where practicable. Our ability to continue this strategy depends to a large extent on the creditworthiness of our counterparties and the availability of cash on hand.



Going forward, we expect counterparties collateral demands to reflect changes in commodity prices, including seasonal
changes in weather-related demand, as well as their view of our creditworthiness. 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 12 months. Over the longer term, we expect to achieve incremental reductions associated with the completion of our exit from the customer risk management business. Please see Results of Operations2004
OutlookCRM Outlook beginning on page 49 for a discussion of the expected collateral roll-off from this 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 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, 2003. Cash obligations reflected are not discounted and do not include related interest, accretion or dividends.



|                                           |  |                        |       |      |   |      |  |      |     |      |   |      |  |            |     |  |   |     |  |   |      
|------------------------------------------ |  | ---------------------- | ----- | ---- | - | ---- |  | ---- | --- | ---- | - | ---- |  | ---------- | --- |  | - | --- |  | - | -----
|                                           |  | Payments Due by Period
|                                           |  | Total                  |       | 2004 |   | 2005 |  | 2006 |     | 2007 |   | 2008 |  | Thereafter
|                                           |  | (in millions)         
|Long-Term Debt (including Current Portion) |  | $                      | 3,743 |      | $ | 79   |  | $    | 102 |      | $ | 44   |  | $          | 184 |  | $ | 225 |  | $ | 3,109
|Capital Leases                             |  |                        | 81    |      |   | 81   |  |      |    |      |   |     |  |            |    |  |   |    |  |   |     
|Operating Leases                           |  |                        | 1,576 |      |   | 79   |  |      | 79  |      |   | 79   |  |            | 126 |  |   | 145 |  |   | 1,068
|Capacity Payments                          |  |                        | 2,786 |      |   | 240  |  |      | 230 |      |   | 222  |  |            | 225 |  |   | 228 |  |   | 1,641
|Conditional Purchase Obligations           |  |                        | 615   |      |   | 17   |  |      | 158 |      |   | 207  |  |            | 126 |  |   | 38  |  |   | 69   
|                                           |  |                        |       |      |   |      |  |      |     |      |   |      |  |            |     |  |   |     |  |   |      
|Total Contractual Obligations              |  | $                      | 8,801 |      | $ | 496  |  | $    | 569 |      | $ | 552  |  | $          | 661 |  | $ | 636 |  | $ | 5,887
|                                           |  |                        |       |      |   |      |  |      |     |      |   |      |  |            |     |  |   |     |  |   |      



Long-Term Debt
(including Current Portion). Total amounts of Long-Term Debt (including Current Portion) are included in the December 31, 2003 Consolidated Balance Sheet. For additional explanation, please read Note 12Debt beginning on page F-31.



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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-26 for
further discussion of these joint ventures.



Capital Leases. Capital leases consist of our Tilton capital lease obligation. Of the $81 million obligation above, $71 million is included in the December 31, 2003 Consolidated Balance Sheet as a component of Notes Payable
and Current Portion of Long-Term Debt. The $10 million difference will be accreted over the remaining term of the capital lease through a charge to interest expense with a corresponding increase to short-term debt. We began reflecting the Tilton
facility and the related debt in our consolidated balance sheets in September 2003 as a result of our delivery of a notice of our intent to purchase the related turbines upon the lease expiration in September 2004. For additional explanation, please
read Note 12DebtTilton Capital Lease beginning on page F-34.



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 32. Amounts also include minimum lease payment obligations associated with office and office equipment leases.



Capacity Payments.Capacity payments include future payments
aggregating $2.3 billion under our four remaining power tolling arrangements, as further described in Item 1. BusinessSegment DiscussionCustomer Risk Management beginning on page 15. This amount includes the fixed payments associated
with a derivative instrument related to the Sithe tolling arrangement, which is reflected at its fair value on our Consolidated Balance Sheet in Risk-Management Liabilities, as well as amounts relating to contracts that are accounted for on an
accrual basis. At December 31, 2003, approximately $325 million of fixed payments have been reflected in the fair value of the Sithe derivative instrument. We are exploring opportunities to renegotiate or terminate one or more of these arrangements
on terms we consider economical. Please read Results of Operations2004 OutlookCRM Outlook beginning on page 49 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 $507 million.



Conditional Purchase Obligations.Amounts include our obligations as of December 31, 2003 to purchase 14 gas-fired turbines. The purchase
orders include milestone requirements by the manufacturer and provide us with the ability to cancel each discrete purchase order commitment in exchange for a fee, which escalates over time. The $479 million included herein assume all 14 turbines
will be purchased. In February 2004, we terminated our conditional purchase obligation related to these gas fired turbines as part of a comprehensive settlement agreement with the manufacturer. No cash, other than $11 million previously paid to the
manufacturer as a deposit, is expected to be provided as consideration for the termination.



Amounts also include $136 million related to our co-sourcing agreement with Accenture Ltd. This 10-year agreement may be cancelled after two years upon
the payment of a termination fee.



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Contingent Financial Obligations



The following table provides a summary of our contingent financial
obligations as of December 31, 2003 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 than1 Year |   | 1  3Years |  | 3-5Years |    | More than5 Years
|                            |  | (in millions)       
|Letters of Credit (1)       |  | $                    | 186 |                 | $ | 186        |  | $        |   |                  | $ |   |  | $ |  
|Surety Bonds (2)(4)         |  |                      | 73  |                 |   | 73         |  |          |   |                  |   |   |  |   |  
|Guarantees (3)              |  |                      | 131 |                 |   | 13         |  |          | 26 |                  |   | 26 |  |   | 66
|                            |  |                      |     |                 |   |            |  |          |    |                  |   |    |  |   |   
|Total Financial Commitments |  | $                    | 390 |                 | $ | 272        |  | $        | 26 |                  | $ | 26 |  | $ | 66
|                            |  |                      |     |                 |   |            |  |          |    |                  |   |    |  |   |   

---

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

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

|(3) | Amounts include two charter party agreements relating to VLGCs previously utilized in our global liquids business sub-chartered to a wholly owned subsidiary of Transammonia Inc. The
terms of the sub-charters are identical to the terms of the original charter party agreements. We are currently in negotiations with the owners of the VLGCs and their lenders to obtain a novation/release of the two charter party agreements and a
release of our guarantees.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | $33 million of the surety bonds were supported by collateral.
|--- | -------------------------------------------------------------



Off-Balance Sheet Arrangements



In September 2003, we delivered notice of our intent to exercise our option to purchase the Tilton assets upon the expiration of the operating lease in
September 2004. As a result of this action, we began accounting for the related lease obligation, which we formerly reported as an off-balance sheet arrangement, as a capital lease. Following is a discussion of our remaining off-balance sheet
arrangement.



DNE Leveraged Lease. As described
in Item 1. BusinessSegment DiscussionPower GenerationNortheast regionNortheast Power Coordinating Council (NPCC) beginning on page 6, we established our presence in the Northeast region by acquiring the DNE power generating
facilities in January 2001 for $950 million from Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc. and Niagara Mohawk Power Corporation.



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 maximize the value of the facilities 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.



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As of December 31, 2003, future lease payments are $60 million for each year 2004 through 2006, with $1.3
billion in the aggregate due from 2007 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, 2003, the present value (discounted at 10%) of future lease payments was $758 million.



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



|                            |  |               |    |      |   |      |  |   |   
|--------------------------- |  | ------------- | -- | ---- | - | ---- |  | - | --
|                            |  | 2003          |    | 2002 |   | 2001
|                            |  | (in millions)
|Lease Expense               |  | $             | 50 |      | $ | 50   |  | $ | 34
|Lease Payments (Cash Flows) |  | $             | 60 |      | $ | 60   |  | $ | 30



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, 2003, the
termination payment at par would be $997 million for all of the DNE facilities, which exceeds the $920 million we received on the sale of 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



In connection with our restructuring, we have undertaken various efforts to tightly manage costs and capital expenditures. We had approximately $205 million in capital expenditures during 2003. This is a significant reduction from the
approximately $735 million in capital expenditures during 2002 and reflects our efforts to improve our capital efficiency without compromising the operational integrity of our facilities. Our 2003 capital spending by segment was as follows (in
millions):



|      |  |   |    
|----- |  | - | ---
|GEN   |  | $ | 149
|NGL   |  |   | 51 
|Other |  |   | 5  
|      |  |   |    
|Total |  | $ | 205
|      |  |   |    



Capital spending in
our GEN segment primarily consisted of maintenance capital projects, as well as approximately $40 million spent on completing the construction of the Rolling Hills facility, which began commercial operation during the summer of 2003. Capital
spending in our NGL segment primarily related to maintenance capital projects and wellconnects, as well as $8 million in development capital at our Cedar Bayou Fractionators, LP.



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We expect capital expenditures for 2004 to approximate $235 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 2004 are as follows (in millions):



|      |  |   |    
|----- |  | - | ---
|GEN   |  | $ | 150
|NGL   |  |   | 75 
|Other |  |   | 10 
|      |  |   |    
|Total |  | $ | 235
|      |  |   |    



Increased capital
spending in the NGL segment is primarily due to $20 million for gathering system expansion, additional compression and plant de-bottlenecking in North Texas related to increased gas from the Barnett Shale formation and $7 million for a significant
upgrade in compression technology and efficiencies at our Monument gas processing plant.



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 $45 million in 2003 and are expected to be $67 million in 2004.



Our capital expenditures in 2004 and beyond will be limited by negative covenants contained in our restructured credit agreements. These covenants place specific dollar limitations on our ability to incur capital
expenditures. Please read Note 11Refinancing and Restructuring Transactions beginning on page F-29 for further discussion of these transactions.



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, changes in law resulting in loss of tax-exempt status on certain bond issuances,
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 have not executed any transactions that require us to issue
equity based on credit ratings or other trigger events.



Commitments and
Contingencies



Please read Note 16Commitments and
Contingencies beginning on page F-40, 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 $1.1 billion revolving credit
facility, which is scheduled to mature on February 15, 2005.



Cash Flows from Operations. We had operating cash flows of $760 million in 2003, which included approximately $500 million associated with our CRM business and $85 million from a federal income tax refund, neither of which is
expected to be repeated in 2004.



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Our operating cash flows are significantly impacted by commodity prices, particularly in our power
generation and NGL businesses. Although the depressed frac spread is negatively impacting our NGL segments downstream operations, our upstream business is currently operating in, and is expected to continue to operate in, a favorable pricing
environment. However, our power generation business is currently operating in a relatively weak pricing environment due to overcapacity in the markets we serve. Management believes, however, that the U.S. power markets will improve and reach a state
of equilibrium  a condition where supply equals demand plus a reasonable reserve  over the longer term. This belief is based on various market indicators, including projected supply-demand imbalances and the perceived reaction to the
risk of supply interruption. If equilibrium were to occur in one or more of the regions in which we operate, we expect that the pricing environment in the applicable regions would significantly improve. As a result, baseload and dual-fuel plants
would produce higher earnings and cash flows and peaking plants would be more economical to operate.



As described above, much of the restructuring work that we have done has extended our significant debt maturities to 2008 and beyond, positioning us to
benefit from this expected long-term recovery in the U.S. power markets. 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 price deterioration in the upstream portion of the NGL segment. Please read Item 1. BusinessSegment DiscussionPower Generation beginning on page 3 for a discussion of our current views on supply and demand in
the regions where our power generation business operates.



Over
the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs and to renew or replace our CDWR agreement. With respect to costs, we launched a value creation project in
early 2003, a company-wide initiative focused on identifying opportunities to improve our operational efficiencies. In connection with this project, we have undertaken a number of initiatives, including our October 2003 co-sourcing agreement with
Accenture Ltd. and a centralized procurement program, designed to reduce costs across the company. We also have sharpened our focus on reducing operating costs and, in January 2004, entered into a new rail transportation contract that we anticipate
will reduce the fees associated with fuel procurement at our coal-fired generation facilities. Our ability to achieve these cost savings in the face of industry-wide increases in labor and benefits costs will impact our future operating cash flows.



In addition, our CDWR and Illinois Power power purchase
agreements expire by their terms on December 31, 2004. We generated approximately $472 million in revenues under the Illinois Power purchase agreement in 2003. In addition, our share of West Coast Powers revenues under the CDWR contract in
2003 totaled $305 million. If we are unable to renew or replace these contracts, we would seek to sell the associated energy and capacity into the open market, where our operating cash flows would be dependent on then prevailing market prices. We
expect that the generating facilities supporting the CDWR contract would be significantly less profitable as merchant facilities. In connection with Dynegys agreement to sell Illinois Power to Ameren, we agreed, conditioned upon the closing of
the sale, to sell 2,800 MWs of capacity and up to 11.5 million MWh of energy to Illinois Power at fixed prices for two years beginning in January 2005. The closing of the sale to Ameren, which is expected by the end of 2004, is subject to receipt of
required regulatory approvals and other closing conditions. Please read Note 22Subsequent Event beginning on page F-62 for further discussion.



Cash on Hand. At February 23, 2004 and December 31, 2003, we had cash on hand of $266 million and $328 million, respectively. We intend to
continue our disciplined cash management practices to maintain our cash position. For example, we have been, and intend to continue, substituting more cash as collateral with certain high-credit quality counterparties than letters of credit under
our revolving credit facility. This has resulted in reduced letter of credit fees relative to cash interest income. However, unforeseen events such as legal judgments or regulatory requirements, as well as litigation settlements or contract
terminations, could negatively impact our ability to do so.



Revolver Capacity.Our primary credit facility is our $1.1 billion revolving credit facility, which is scheduled to mature on February 15, 2005. We currently have no drawn amounts under this facility, although as of February
23, 2004, we had $222 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, particularly if we are unable to generate
operating cash flows relative to our substantial debt obligations and ongoing operating requirements or to realize the asset sale proceeds we anticipate. We currently plan to pursue such a renewal or replacement during 2004, although we cannot
guarantee that we will be successful in this pursuit. We expect to incur significant fees in connection with any such renewal or replacement. Please see Note 11Refinancing and Restructuring TransactionsCredit Facility Restructuring
beginning on page F-29 for a discussion of the fees we incurred in connection with our April 2003 credit facility restructuring.



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Current Liquidity. During 2003, we maintained a strong liquidity position, averaging total
available liquidity of approximately $1.4 billion. The following table summarizes our consolidated credit capacity and liquidity position at February 23, 2004, December 31, 2003 and December 31, 2002:



|                                                              |  |                  |       |     |                  |   |       |                  |  |   |       |  
|------------------------------------------------------------- |  | ---------------- | ----- | --- | ---------------- | - | ----- | ---------------- |  | - | ----- | -
|                                                              |  | February 23,2004 |       |     | December 31,2003 |   |       | December 31,2002 | 
|                                                              |  | (in millions)    |      
|Total Revolver Capacity                                       |  | $                | 1,088 | (1) |                  | $ | 1,100 | (2)              |  | $ | 1,300 |  
|Outstanding Loans                                             |  |                  |      |     |                  |   |      |                  |  |   | (128  | )
|Outstanding Letters of Credit Under Revolving Credit Facility |  |                  | (222  | )   |                  |   | (188  | )                |  |   | (872  | )
|                                                              |  |                  |       |     |                  |   |       |                  |  |   |       |  
|Unused Revolver Capacity                                      |  |                  | 866   |     |                  |   | 912   |                  |  |   | 300   |  
|Cash                                                          |  |                  | 266   | (3) |                  |   | 328   |                  |  |   | 633   |  
|Liquid Inventory (4)                                          |  |                  |      |     |                  |   |      |                  |  |   | 258   |  
|                                                              |  |                  |       |     |                  |   |       |                  |  |   |       |  
|Total Available Liquidity                                     |  | $                | 1,132 |     |                  | $ | 1,240 |                  |  | $ | 1,191 |  
|                                                              |  |                  |       |     |                  |   |       |                  |  |   |       |  

---

|(1) | The February 23, 2004 amount reflects $12 million of mandatory reductions of our revolving credit facility related to asset sales and dividend payments on Dynegys Series C
preferred stock.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Reflects the conversion of $200 million of credit capacity under the former DHI revolving credit facilities into the Term A loan in connection with the April 2003 restructuring of
such facilities.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | Includes approximately $40 million of cash that remains in Canada and the U.K. associated primarily with contingent liabilities relating to our former Canadian and U.K. marketing
and trading operations
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | Amounts reflected for 2003 and 2004 periods do not include liquid inventory, as we have sold the natural gas inventories that comprised that item and converted them to cash.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



External Liquidity Sources



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



Asset Sale Proceeds.As indicated above, assuming continuation of the current commodity pricing environment, our estimated operating cash
flows for 2004 will be insufficient to satisfy our capital expenditures, debt maturities, increased interest expenses and operating commitments. Accordingly, the receipt of proceeds from asset sales that we are currently pursuing or considering will
significantly impact our near-term financial condition.



In
February 2004, Dynegy entered into an agreement to sell Illinois Power and our 20% interest in the Joppa power generation facility to Ameren for $2.3 billion. Upon closing of the transaction, which is subject to regulatory approval and other closing
conditions, Dynegy would receive $400 million in cash, subject to working capital adjustments, and Ameren would put $100 million in escrow, subject to full release to Dynegy on December 31, 2010 or earlier upon the occurrence of specified events.
Please read Note 22Subsequent Event beginning on page F-62 for further discussion of the transaction, which is expected to close before the end of 2004, and the required use of proceeds.



In an effort to maximize our return on investment and to further clarify our
business strategy, we are pursuing or considering sales of other assets that we do not consider core to our operations. These assets primarily include our ownership interests in certain non-strategic and international power generation facilities, as
further described in Item 1. BusinessSegment DiscussionPower Generation beginning on page 3, as well as our minority ownership interests in a gas processing plant and Gulf Coast Fractionators, a partnership that owns a fractionator in
Mont Belvieu. The sales of these non-core assets are expected to generate aggregate cash proceeds of more than $200 million in 2004. These expected proceeds include proceeds from the pending sales of our Oyster Creek and Michigan Power generating
facilities, with respect to which we recently executed sales agreements, as well as proceeds from the recent sale of our remaining interest in the Hackberry LNG project. Generally, the aggregate projected earnings impact of these transactions is not
considered material and is expected to be offset substantially by net gains on sale in 2004.



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Our desire or ability to effect these transactions is subject to a number of factors, many of which are
beyond our control, including the market for the subject assets and investments and the receipt of any regulatory and other approvals that may be required. Accordingly, we cannot make any guarantees that these sales will be consummated or that the
expected proceeds will be received. In addition, if the sales are consummated while the Junior Notes remain outstanding, we and/or Dynegy are required to use: (i) 75% of the net cash proceeds from the sale of Illinois Power to pay down the Junior
Notes and 25% of the net cash proceeds to reduce the commitments of the revolver; (ii) 25% of the net cash proceeds from other sales to pay down the Junior Notes and (iii) 25% of the net cash proceeds from other sales to reduce permanently or cash
collateralize the commitments under our revolving credit facility up to a maximum of $100 million. If the Junior Notes are not outstanding, 100% of the net cash proceeds from asset sales are required to be used, subject to certain exceptions, to
reduce the commitments under the revolver. The remaining proceeds are intended to be used to pay transaction fees and expenses and to repay other outstanding debt.



Although no other asset sales or related transactions have been specifically identified, we discuss and evaluate merger and
acquisition activities as part of our ongoing business strategy.



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 its asset-based businesses, Dynegy has stated that it
intends to explore additional capital-raising transactions both in the near- and longer term. These transactions could include public or private equity issuances. Dynegys ability to issue public equity 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 equity issuance 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 our control. Dynegys ability to issue private equity could be similarly affected and, if such an issuance
were completed, would likely be more costly, both in terms of required rates of return and other requirements typically associated with this type of transaction. Any issuance of equity likely would have other effects as well, including dilution of
the interests of Dynegys shareholders.



The proceeds from
any such issuance would be subject to the mandatory prepayment provisions of our revolving credit agreement and second secured senior notes indenture, which generally do not require prepayment for the first $250 million in proceeds, which may be
used for repayment of the Junior Notes and for dollar-for-dollar commitment reduction under our revolving credit facility up to a maximum of $100 million. Please see Note 12DebtCredit Facility beginning on page F-31 for further
discussion.



Conclusion



During 2003, we completed a series of refinancing and restructuring
transactions that included sales of nearly $2.0 billion in second priority senior secured notes. We used the net proceeds from these offerings, together with a portion of the net proceeds from the sale of Dynegys convertible subordinated
debentures and cash on hand, to repay approximately $2.0 billion in 2005-2006 debt maturities. As a result of these transactions, we have extended a substantial portion of our debt maturities from 2005-2006 to 2008 and beyond.



For the next 12 months, assuming continuation of the current commodity
pricing environment, we expect that our operating cash flows will be insufficient to satisfy our capital expenditures, debt maturities, increased interest expenses and operating commitments. When combined with our cash on hand, proceeds from
anticipated asset sales and capacity under our $1.1 billion revolving credit facility, however, we believe we have sufficient capital resources to discharge these obligations during this period. In order to further the deleveraging efforts of the
consolidated enterprise, Dynegy has also expressed its intent to explore other capital-raising activities, including potential public or private equity issuances. Dynegys ability to raise additional funds may impact our ability to settle our
significant ongoing litigation, as well as one or more of our four remaining power tolling arrangements, with respect to which we have substantial fixed payment obligations extending well into the future.



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Over the longer term, our liquidity position and financial condition will be materially affected by a
number of factors, including Dynegys ability to consummate the Illinois Power sale to Ameren and our ability to generate cash flows from our asset-based energy businesses in relation to our debt and commercial obligations, including a
substantial increase in interest expense, the fixed payment obligations associated with our CRM business and counterparty collateral requirements. The sale of Illinois Power would provide significant cash proceeds to repay outstanding debt of the
consolidated enterprise and advance Dynegys business strategy of focusing on our unregulated energy businesses. Our future financial success is also substantially dependent on our ability to renew or replace our $1.1 billion revolving credit
facility, which is scheduled to mature on February 15, 2005, with respect to which our ability to borrow and/or issue letters of credit could become increasingly important.



Our ability to generate operating cash flows from our asset-based energy businesses 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 and capital expenditures. 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 the restructuring work that we did in 2003 has extended our significant debt maturities from 2005-2006 to 2008 and
beyond, positioning us to benefit from earnings and growth opportunities associated with this expected recovery in the U.S. power markets. Conversely, although depressed frac spreads have negatively impacted our NGL segments downstream
operations, our upstream business is currently operating in a relatively favorable pricing environment. Our future financial condition and results of operations will be materially affected if the U.S. power markets fail to recover in accordance with
our expectations or if we experience significant pricing deterioration in the NGL segment.



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 2003, 2002 and 2001. At the end of this section, we have included our 2004 outlook for each segment.



As reflected in this report, we have changed our reporting segments. We
historically 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 four former reporting segments prior to January 1, 2003. Beginning January 1, 2003, all direct general and administrative expenses 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. Other income (expense) items incurred by us on behalf of our
subsidiaries are allocated directly to the four segments.



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 20Segment Information
beginning on page F-57 for a discussion of the impact of comparing segment results period over period. Regarding our results of operations for 2003, 2002 and 2001, 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 2003 period as compared to the 2002 and 2001 periods. Please read
Cumulative Effect of Change in Accounting Principles beginning on page 47 for further discussion.



Non-GAAP Financial Measures.Management uses EBIT as one measure of financial performance of our business segments. EBIT is a
non-GAAP financial measure and consists of operating income (loss), earnings



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(losses) from unconsolidated investments, other income and expense, net, minority interest income (expense), accumulated
distributions associated with trust preferred securities, discontinued operations and cumulative effect of change in accounting principles. EBIT does not include interest expense or income taxes, each of which is evaluated on a consolidated level.
Because we do not allocate interest expense and income taxes by segment, management believes that EBIT is a useful measure of our segments operating performance for investors. EBIT should not be considered an alternative to, or more meaningful
than, net income or cash flows from operations as determined in accordance with GAAP. Our segment and consolidated EBIT may not be comparable to similarly titled measures used by other companies.



Summary Financial Information.The following tables provide
summary financial data regarding our consolidated and segmented results of operations for 2003, 2002 and 2001, respectively (in millions):



Year Ended December 31, 2003



|                                                     |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|---------------------------------------------------- |  | --- | --- | --- | - | --- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ---- | -
|                                                     |  | GEN |     | NGL |   |     | CRM |  |   | Other andEliminations |   |  | Total |     
|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    |  
|Discontinued operations                              |  |     |    |     |   | (2  | )   |  |   | (12                   | ) |  |       | (3   | ) |  |   | (17  | )
|Cumulative effect of change in accounting principles |  |     | 24  |     |   |    |     |  |   | 43                    |   |  |       |     |   |  |   | 67   |  
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Earnings (loss) before interest and taxes            |  | $   | 359 |     | $ | 149 |     |  | $ | (325                  | ) |  | $     | (250 | ) |  | $ | (67  | )
|Interest expense                                     |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (338 | )
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Pre-tax loss                                         |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | (405 | )
|Income tax benefit                                   |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   | 157  |  
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  
|Net loss                                             |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  | $ | (248 | )
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |  |       |      |   |  |   |      |  



Year Ended December
31, 2002



|                                                  |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   |        |  
|------------------------------------------------- |  | --- | ---- | - | --- | - | --- | --- |  | - | --------------------- | - |  | ----- | --- | - |  | - | ------ | -
|                                                  |  | GEN |      |   | NGL |   |     | CRM |  |   | Other andEliminations |   |  | Total |    
|Operating income (loss)                           |  | $   | (232 | ) |     | $ | 77  |     |  | $ | (974                  | ) |  | $     |    |   |  | $ | (1,129 | )
|Earnings (losses) from unconsolidated investments |  |     | (45  | ) |     |   | 14  |     |  |   | (21                   | ) |  |       |    |   |  |   | (52    | )
|Other items, net                                  |  |     | 9    |   |     |   | (34 | )   |  |   | (49                   | ) |  |       |    |   |  |   | (74    | )
|Discontinued operations                           |  |     |     |   |     |   | (37 | )   |  |   | (51                   | ) |  |       | (25 | ) |  |   | (113   | )
|                                                  |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Earnings (loss) before interest and taxes         |  | $   | (268 | ) |     | $ | 20  |     |  | $ | (1,095                | ) |  | $     | (25 | ) |  | $ | (1,368 | )
|Interest expense                                  |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   | (187   | )
|                                                  |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Pre-tax loss                                      |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   | (1,555 | )
|Income tax benefit                                |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   | 309    |  
|                                                  |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   |        |  
|Net loss                                          |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  | $ | (1,246 | )
|                                                  |  |     |      |   |     |   |     |     |  |   |                       |   |  |       |     |   |  |   |        |  



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Year Ended December 31, 2001



|                                                     |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   |      |  
|---------------------------------------------------- |  | --- | --- | --- | - | --- | --- |  | - | --------------------- | - | ----- | - | - |  | - | ---- | -
|                                                     |  | GEN |     | NGL |   |     | CRM |  |   | Other andEliminations |   | Total |  
|Operating income                                     |  | $   | 377 |     | $ | 133 |     |  | $ | 264                   |   |       | $ |  |  | $ | 774  |  
|Earnings (losses) from unconsolidated investments    |  |     | 189 |     |   | 13  |     |  |   | (24                   | ) |       |   |  |  |   | 178  |  
|Other items, net                                     |  |     | 5   |     |   | (3  | )   |  |   | (54                   | ) |       |   |  |  |   | (52  | )
|Discontinued operations                              |  |     |    |     |   | (2  | )   |  |   | (25                   | ) |       |   |  |  |   | (27  | )
|Cumulative effect of change in accounting principles |  |     |    |     |   |    |     |  |   | 3                     |   |       |   |  |  |   | 3    |  
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   |      |  
|Earnings (loss) before interest and taxes            |  | $   | 571 |     | $ | 141 |     |  | $ | 164                   |   |       | $ |  |  | $ | 876  |  
|Interest expense                                     |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   | (137 | )
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   |      |  
|Pre-tax income                                       |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   | 739  |  
|Income tax provision                                 |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   | (314 | )
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   |      |  
|Net income                                           |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  | $ | 425  |  
|                                                     |  |     |     |     |   |     |     |  |   |                       |   |       |   |   |  |   |      |  



The following table
provides summary segmented operating statistics for 2003, 2002 and 2001, respectively:



|                                                  |  |                         |       |      |   |       |  |   |      
|------------------------------------------------- |  | ----------------------- | ----- | ---- | - | ----- |  | - | -----
|                                                  |  | Year Ended December 31,
|                                                  |  | 2003                    |       | 2002 |   | 2001 
|Power Generation                                  |  |                         |       |      |   |       |  |   |      
|Million megawatt hours generatedgross            |  |                         | 36.2  |      |   | 36.4  |  |   | 37.1 
|Million megawatt hours generatednet              |  |                         | 34.3  |      |   | 34.0  |  |   | 31.3 
|Average natural gas priceHenry Hub ($/MMbtu) (1) |  | $                       | 5.28  |      | $ | 3.35  |  | $ | 3.90 
|Average on-peak market power prices ($/MW hour)   |  |                         |       |      |   |       |  |   |      
|Cinergy                                           |  | $                       | 37.26 |      | $ | 26.89 |  | $ | 34.85
|Commonwealth Edison                               |  |                         | 36.73 |      |   | 26.45 |  |   | 34.15
|Southern                                          |  |                         | 41.27 |      |   | 30.10 |  |   | 38.30
|New YorkZone G                                   |  |                         | 61.47 |      |   | 46.36 |  |   | 51.51
|ERCOT                                             |  |                         | 44.89 |      |   | 29.10 |  |   | 39.26
|                                                  |  |                         |      
|Natural Gas Liquids                               |  |                         |       |      |   |       |  |   |      
|Natural gas processing volumes (MBbls/d):         |  |                         |       |      |   |       |  |   |      
|Field plants                                      |  |                         | 59.6  |      |   | 56.0  |  |   | 56.1 
|Straddle plants                                   |  |                         | 25.6  |      |   | 35.9  |  |   | 27.7 
|                                                  |  |                         |       |      |   |       |  |   |      
|Total natural gas processing volumes              |  |                         | 85.2  |      |   | 91.9  |  |   | 83.8 
|                                                  |  |                         |       |      |   |       |  |   |      
|Fractionation volumes (MBbls/d)                   |  |                         | 185.3 |      |   | 215.2 |  |   | 226.2
|Natural gas liquids sold (MBbls/d)                |  |                         | 311.7 |      |   | 498.8 |  |   | 557.4
|Average commodity prices:                         |  |                         |       |      |   |       |  |   |      
|Crude oilWTI ($/Bbl)                             |  | $                       | 31.01 |      | $ | 25.75 |  | $ | 26.39
|Natural gasHenry Hub ($/MMbtu) (2)               |  | $                       | 5.38  |      | $ | 3.22  |  | $ | 4.26 
|Natural gas liquids ($/Gal)                       |  | $                       | 0.55  |      | $ | 0.40  |  | $ | 0.45 
|Fractionation spread ($/MMBtu)first of month     |  | $                       | 0.87  |      | $ | 1.26  |  | $ | 0.88 
|Fractionation spread ($/MMBtu)daily              |  | $                       | 0.79  |      | $ | 1.13  |  | $ | 1.15 

---

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



40



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##### Table of Contents

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



|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |     |   |  |   |        |  
|---------------------------------------------------- |  | ---------------------------- | ---- | - | --- | - | --- | --- |  | - | ----- | - |  | ----- | --- | - |  | - | ------ | -
|                                                     |  | Year Ended December 31, 2003 |     
|                                                     |  | GEN                          |      |   | NGL |   |     | CRM |  |   | Other |   |  | Total |    
|                                                     |  | (in millions)                |     
|Southern Power tolling settlement                    |  | $                            |     |   |     | $ |    |     |  | $ | (133  | ) |  | $     |    |   |  | $ | (133   | )
|Sithe power tolling contract                         |  |                              |     |   |     |   |    |     |  |   | (121  | ) |  |       |    |   |  |   | (121   | )
|Second quarter accrual of legal reserve              |  |                              |     |   |     |   |    |     |  |   |      |   |  |       | (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 fractionator investment                |  |                              |     |   |     |   | (12 | )   |  |   |      |   |  |       |    |   |  |   | (12    | )
|Taxes                                                |  |                              | (1   | ) |     |   |    |     |  |   |      |   |  |       |    |   |  |   | (1     | )
|Gain on sale of Hackberry LNG                        |  |                              |     |   |     |   | 25  |     |  |   | 2     |   |  |       |    |   |  |   | 27     |  
|Cumulative effect of change in accounting principles |  |                              | 24   |   |     |   |    |     |  |   | 43    |   |  |       |    |   |  |   | 67     |  
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |     |   |  |   |        |  
|Total                                                |  | $                            | (23  | ) |     | $ | 11  |     |  | $ | (285  | ) |  | $     | (77 | ) |  | $ | (374   | )
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |     |   |  |   |        |  
|                                                     | 
|                                                     |  | Year Ended December 31, 2002 |     
|                                                     |  | GEN                          |      |   | NGL |   |     | CRM |  |   | Other |   |  | Total |    
|                                                     |  | (in millions)                |     
|Discontinued operations                              |  | $                            |     |   |     | $ | (37 | )   |  | $ | (51   | ) |  | $     | (25 | ) |  | $ | (113   | )
|Goodwill impairment                                  |  |                              | (376 | ) |     |   |    |     |  |   | (348  | ) |  |       |    |   |  |   | (724   | )
|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                                                |  | $                            | (616 | ) |     | $ | (65 | )   |  | $ | (577  | ) |  | $     | (25 | ) |  | $ | (1,283 | )
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |     |   |  |   |        |  
|                                                     | 
|                                                     |  | Year Ended December 31, 2001 |     
|                                                     |  | GEN                          |      |   | NGL |   |     | CRM |  |   | Other |   |  | Total |    
|                                                     |  | (in millions)                |     
|Discontinued operations                              |  | $                            |     |   |     | $ | (2  | )   |  | $ | (25   | ) |  | $     |    |   |  | $ | (27    | )
|Enron bankruptcy exposure                            |  |                              |     |   |     |   |    |     |  |   | (129  | ) |  |       |    |   |  |   | (129   | )
|Terminated Enron merger costs                        |  |                              | (2   | ) |     |   | (1  | )   |  |   | (3    | ) |  |       | (1  | ) |  |   | (7     | )
|Cumulative effect of change in accounting principle  |  |                              |     |   |     |   |    |     |  |   | 3     |   |  |       |    |   |  |   | 3      |  
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |     |   |  |   |        |  
|Total                                                |  | $                            | (2   | ) |     | $ | (3  | )   |  | $ | (154  | ) |  | $     | (1  | ) |  | $ | (160   | )
|                                                     |  |                              |      |   |     |   |     |     |  |   |       |   |  |       |     |   |  |   |        |  

---

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



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Operating Income (Loss)



Operating income (loss) was $(255) million in 2003, compared to $(1,129) million and $774 million in 2002 and 2001,
respectively.



GEN.Operating income (loss) for
the GEN segment was $198 million in 2003, compared to $(232) million and $377 million in 2002 and 2001, respectively. Operating income for 2003 included general and administrative expense of $61 million and depreciation and amortization expense of
$185 million. Please see Other beginning on page 45 for a consolidated discussion of general and administrative expense and depreciation and amortization expense.



Operating income for 2002 included the following charges:



| |  | a $376 million impairment of goodwill (please see Note 10Goodwill beginning on page F-29 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-20 for further discussion);
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



In addition, operating income for 2002 included general and administrative expense of $65
million and depreciation and amortization expense of $154 million. Operating income for 2001 included general and administrative expense of $97 million and depreciation and amortization expense of $177 million.



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 is 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 percent and 33 percent, 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 remained relatively flat to 2002;
however, the net MW hours 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 income 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 facilities as part of the acquisition, which agreement expires in October 2004. Finally, 2003 operating income includes 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.



Operating income in 2002 included a $155 million decrease related to pricing and a $50 million benefit due to generated volumes versus 2001. GENs
results for 2002 reflect lower power prices on average as compared to 2001. This was primarily driven by a weakening economy, significantly compressed natural gas spark spreads and milder than normal summer and winter temperatures. Average on-peak
prices in the Midwest and Northeast regions during 2002 decreased 23 percent and 10 percent, respectively, from the corresponding prices for 2001. Volumes increased in 2002 by 8 percent over 2001 primarily due to increased coal-fired production in
the Midwest. The net MW hours generated by our Midwest and Northeast facilities were 18 million and 4.3 million, respectively, for 2001.



The decrease in operating income for 2002 also results from the fact that 2001 included approximately $50 million in revenue generating capacity contracts
that expired and were not renewed in 2002. Also, revenues



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associated with the DNE facilities decreased approximately $40 million in 2002 as compared to 2001. This decrease
primarily reflects reduced income recognized through the amortization of a liability established for a transitional power purchase agreement acquired from the seller of the facilities as part of the acquisition, which agreement expires in October
2004.



GENs reported operating income for the 2003 period
also includes approximately $4 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 the 2002 and 2001 periods include approximately $8 million and $11 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
the test, it was concluded that no impairment was necessary as the estimated undiscounted cash flows exceeded the book value of the respective asset.



Operating income for 2002 and 2001 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 and $133 million
in 2002 and 2001, respectively. Operating income for 2003 included general and administrative expense of $37 million and depreciation and amortization expense of $81 million. Please see Other beginning on page 45 for a consolidated
discussion of general and administrative expense and depreciation and amortization expense. 2003 operating income also included a $25 million gain associated with the sale of our Hackberry LNG project. Please see Note 3Discontinued Operations,
Dispositions, Contract Terminations and AcquisitionsDispositions and Contract TerminationHackberry LNG Project beginning on page F-19 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. Operating income for 2001 included
general and administrative expense of $48 million and depreciation and amortization expense of $84 million.



The decrease in operating income in 2002 as compared to 2001 and 2003 relates primarily to the upstream business. As compared to 2002, 2001 and 2003
experienced higher natural gas and natural gas liquids prices, which resulted in a significant increase in processing plant margins at our field plants, where our frac spread risk is largely mitigated as a result of our substantial POP and POL
contracts. In addition to favorable pricing, volumes of natural gas liquids produced at our field plants were 6% higher in 2003 as compared to 2002 and 2001. This is primarily due to increased production in the highly active drilling area in North
Texas. Our 2003 straddle plant volumes were substantially in line with 2001 volumes, but much lower as compared to 2002 because of the low frac spread, 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 have steadily declined over each of the last three years from 226 MBbls per day in 2001 to
185 MBbls per day in 2003 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 and the impact of higher commodity prices on contracts where 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



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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 and 2001 includes income of
approximately $18 million and $14 million, respectively, 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 income (loss) for the CRM segment was $(385) million in 2003, compared to $(974) million and
$264 million in 2002 and 2001, respectively. 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 Sithe Independence power tolling arrangement;
| | - | ---------------------------------------------------------------------------------------------------------------



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



| |  | $30 million 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. Please read Note 2Accounting PoliciesRevenue Recognition beginning on page F-11 for additional details.



Results for 2002 were impacted by the following items:



| |  | $348 million charge for the impairment of goodwill (for further information, please see Note 10Goodwill beginning on page F-29);
| | - | ---------------------------------------------------------------------------------------------------------------------------------



| |  | $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-20);
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | $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 beginning on page 45 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.



Results for 2001 were impacted by the following:



| |  | $129 million charge relating to exposure to Enron as a result of its Chapter 11 filing;
| | - | ---------------------------------------------------------------------------------------



| |  | $35 million mark-to-market gain on the Sithe Independence power tolling arrangement; and
| | - | ----------------------------------------------------------------------------------------



| |  | Higher commodity prices and price and basis volatility as well as market liquidity.
| | - | -----------------------------------------------------------------------------------



In addition, 2001 results included general and administrative expense of $205 million and depreciation and amortization expense of $35
million.



During 2002 and 2001, the CRM segment was actively
managed as part of our ongoing strategy and its results included, in part, settlement with third parties of physical power and other trading positions purchased from our GEN segment at an internally determined transfer price. Please read Note
21Segment Information beginning on page F-57 for further discussion.



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Other. Other operating income (loss) was $(238) million in 2003, compared to zero in 2002
and 2001. The $(238) million 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 and $350 million in 2002 and 2001, respectively. The $38 million increase from 2002 to 2003 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. The $95 million decrease from 2001 to 2002 is primarily due to lower compensation expenses in the 2002 period, due to the June 2002 and
October 2002 work-force reductions, which included 309 and 780 people, respectively, as well as a reduction in variable compensation expense.



Consolidated depreciation and amortization expenses were $330 million in 2003, compared to $270 million and $296 million in 2002 and 2001, respectively.
The $60 million increase from 2002 to 2003 is primarily due to increased depreciation of generation assets due to an increased asset base. The $26 million decrease from 2001 to 2002 is primarily due to a $13 million decrease due to the
implementation of SFAS No. 142, which required the discontinuation of goodwill amortization beginning January 1, 2002. Increases in our asset base during the three-year period include the construction of the Heard and Riverside facilities in 2001,
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 (losses) from unconsolidated investments were approximately $132 million during 2003 compared to $(52) million and $178 million in 2002
and 2001, respectively. Both 2002 and 2003 results include significant impairment charges related to these investments, primarily associated with the GEN segment.



GEN. GENs earnings (losses) from unconsolidated investments were approximately $136 million during 2003
compared to $(45) million and $189 million in 2002 and 2001, respectively. Earnings for 2003 include a $16 million impairment of U.S. and international investments and 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 $117 million impairment of U.S. investments as well as a $50 million charge associated with our 50% share of a bad debt allowance recognized by West Coast
Power. West Coast Power provided equity earnings of approximately $117 million, $17 million and $162 million in the years ended December 31, 2003, 2002 and 2001, respectively. Excluding impairments, earnings from our West Coast Power investment are
the primary driver of results for each of the three periods.



Earnings at West Coast Power were higher in 2003 as compared to 2002 due to higher realized margins resulting from forward hedges put in place in connection with the execution of the CDWR contract. The decrease in earnings at West Coast
Power from 2001 to 2002 is due in part to a reduction in contingent capacity and energy sales under the CDWR contract, as well as lower overall market prices. Please read Item 1. BusinessSegment DiscussionPower GenerationWest
regionWestern Electricity Coordinating Council (WECC) beginning on page 7 for further discussion of the CDWR contract.



As noted above, 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.



As noted above, we recorded a $117 million impairment of U.S. investments in 2002, of which $33 million related to West Coast Power. 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.



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NGL. NGLs earnings (losses) from unconsolidated investments were approximately $(2)
million during 2003 compared to $14 million and $13 million in 2002 and 2001, respectively. 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 and $5 million to our results for the years
ended December 31, 2002 and 2001, respectively.



CRM.CRMs earnings (losses) from unconsolidated investments were approximately $(2) million during 2003 compared to $(21) million and $(24) million in 2002 and 2001, respectively. As of December 31, 2003, CRM has no material unconsolidated
investments. As such, 2004 and 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. The 2001 loss of $24 million is
primarily comprised of a $19 million impairment on a technology investment and a $6 million loss on our investment in Nicor Energy.



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, $(74) million and $(52) million for 2003, 2002 and 2001, respectively.



The 2003 results included the following significant items:



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



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



| |  | The remaining amounts consist of individually insignificant items.
| | - | ------------------------------------------------------------------



The 2002 results included the following significant 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
| | - | ------------------------------------------------------------------------------------------------------------



| |  | The remaining amounts consist of individually insignificant items.
| | - | ------------------------------------------------------------------



The 2001 results included the following significant items:



| |  | $35 million interest income;
| | - | ----------------------------



| |  | $13 million dividend income on our investment in Northern Natural preferred stock;
| | - | ----------------------------------------------------------------------------------



| |  | $93 million minority interest deduction, primarily related to Black Thunder;
| | - | ----------------------------------------------------------------------------



| |  | $22 million charge for accumulated distributions associated with trust preferred securities; and
| | - | ------------------------------------------------------------------------------------------------



| |  | The remaining amounts consist of individually insignificant items.
| | - | ------------------------------------------------------------------



Discontinued Operations



Discontinued operations include Northern Natural in our other segment, 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.



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During 2002, the $113 million pre-tax loss ($100 million after-tax) from discontinued operations was
primarily comprised of $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. The CRM pre-tax loss of $51 million ($49 million after-tax) 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.



The 2001 pre-tax loss of $27 million
($19 million after-tax) consists primarily of $31 million in pre-tax losses associated with the U.K. CRM business.



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. 46 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, 2001, we adopted SFAS No. 133 and recognized a pre-tax benefit of $3 million ($2 million after-tax) in our CRM segment.



Please read Note 2Accounting Policies beginning on page F-8 for further
discussion of our adoption of recent accounting policies.



Interest Expense



Interest expense
totaled $338 million for 2003, compared with $187 million and $137 million for 2002 and 2001, respectively. The significant increase in 2003, as compared to 2002, is primarily attributable to 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.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The increase in interest expense in 2002 compared to 2001 was due primarily to increased principal borrowed to support our liquidity needs in 2002.
Specifically, these additional principal amounts primarily relate to cash borrowings and letters of credit under our revolving credit facilities used to satisfy counterparty collateral demands. The effect of the increased interest expense relating
to these additional principal amounts was partially offset by lower variable rates than in 2001.



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Income Tax (Provision) Benefit



We reported an income tax benefit from continuing operations of $177 million
in 2003, compared to an income tax benefit from continuing operations of $296 million in 2002 and an income tax provision from continuing operations of $321 million in 2001. These amounts reflect effective rates of 39%, 21% and 42%, respectively.
The 2002 effective rate was impacted significantly by the $724 million goodwill impairment relating to the CRM and GEN segments in 2002. As there was no tax basis in 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 39%, compared to effective rates of 39% and 42% in 2003 and 2001, respectively. 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.



Please see Note 14Income Taxes beginning on page F-38 for further discussion of our income taxes.



2004 Outlook



The following summarizes our 2004 outlook for our four reportable segments.



GEN Outlook.We expect that this segments
financial results will continue to reflect a sensitivity to power prices and that the 2004 pricing environment will be similar to what we experienced in 2003. We will continue our efforts to manage price risk through the optimization of fuel
procurement and the marketing of power generated from our assets. Our sensitivity to prices and our ability to manage this sensitivity is subject to a number of factors, including general market liquidity, particularly in forward years, our ability
to provide necessary collateral support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings.



As discussed in Item 1. BusinessSegment DiscussionPower Generation beginning on page 3, we enter into sales of capacity from our generation
assets, which provide a revenue stream independent of energy sales. In late 2003 and continuing into 2004, we have seen increases in the market for capacity-related products from our peaking and intermediate generation facilities.



At the beginning of 2004, a substantial portion of our 2004 operating margin
was under contract or hedged. The primary contracts included the CDWR contract held by West Coast Power and the Illinois Power power purchase agreement. Our future results of operations will be significantly impacted by our ability to extend or
renew these agreements. West Coast Power, whose equity earnings are primarily derived from the CDWR contract, has been our largest contributor in terms of earnings from unconsolidated investments. The scheduled expiration of the CDWR contract in
December 2004 will negatively impact the fair value of our investment in West Coast Power. As the value of the CDWR contract is realized through 2004, its fair value will decline, and, accordingly, we anticipate that the remaining value of the
investment will be less than its book value. As a result, we will evaluate our investment quarterly and anticipate such reviews will necessitate an impairment of our investment of approximately $70 to $80 million in 2004. Please read Note
16Commitments and ContingenciesSummary of Material Legal ProceedingsWestern Long-Term Contract Complaints beginning on page F-44 for further discussion of the legal challenges to the CDWR contract.



Our power purchase agreement with Illinois Power is scheduled to expire at
the end of 2004. In connection with Dynegys sale of Illinois Power to Ameren, DPM has agreed, conditioned on the closing of the sale, to enter into a two-year power purchase agreement with Ameren with volumes comparable to our current
agreement. If Dynegy is unable to complete the sale of Illinois Power, any new agreement between Illinois Power and another Dynegy affiliate may not be executed at the same rates as our existing agreement. Please read Note 22Subsequent
Event beginning on page F-62 for further discussion of the pending sale of Illinois Power.



The current power purchase agreement between DMG and Illinois Power requires that notice of termination be presented by December 31, 2003, one year prior
to the scheduled expiration. The parties have agreed to amend the agreement to extend this notice date requirement to March 31, 2004.



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We continue to pursue additional sales of our ownership interests in a number of domestic generating
projects that we consider non-strategic to this business. We recently executed purchase and sale agreements for our interests in Oyster Creek and Michigan Power and are continuing to pursue sales of our interests in Commonwealth, Black Mountain and
Hartwell. We hold ownership interests of 50% or less in these projects, which aggregate less than 600 MWs of net generating capacity. These investments contributed approximately $26 million to our results in 2003. Please read Note
9Unconsolidated InvestmentsGEN Investments beginning on page F-27 for further discussion of these investments. Our ability to consummate these sales on the terms and within the timeframes we anticipate is subject to several factors, many
of which are beyond our control.



NGL Outlook.We expect that this segments financial results will continue to reflect a sensitivity to natural gas and natural gas liquids prices and that the 2004 pricing environment will be similar to what we experienced in 2003. Our upstream
volumes under POP and POL contracts will continue to benefit from these relatively higher prices. However, natural gas liquids production from both our own and third-party natural gas processing plants that are exposed to KW economics will continue
to be exposed to depressed frac spreads, as natural gas continues to be higher in value than natural gas liquids on a Btu basis. As a result, we expect a reduced natural gas liquids supply to our fractionation, storage and distribution
infrastructure, similar to 2003.



In some brief periods during
2003, the frac spread increased to a level sufficient to support natural gas liquids extraction, but not enough to generate meaningful upstream margin improvement. We expect this to occur during 2004. The increased natural gas liquids volumes
produced during these brief periods resulted in some incremental margins in our downstream operations.



Drilling rig rates for natural gas throughout our core processing areas in New Mexico, West Texas, North Texas and offshore Louisiana continue to
increase, consistent with natural gas prices that have averaged $5-$6/MMBtu. Continued exploration and production at these levels will benefit our upstream business by providing additional volumes for gathering and processing. If natural gas prices
were to decline 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 for many of our commercial relationships. We expect similar collateral requirements until such time as our credit ratings improve substantially. Our ability to hedge future natural
gas liquids production during 2004 will again be limited by reduced market liquidity, our obligation to post collateral and significant backwardation of natural gas liquids prices.



We intend to continue our aggressive North Texas gathering system expansion, where additional compression and plant
debottlenecking are expected to add volumes to our expanded Chico gas processing plant. We expect to see volume growth in this area of 24% in 2004.



We also intend to continue to review our asset portfolio to maximize our return on investment. We have identified a few assets where our interests are not
aligned with our partners. We may pursue sales of one or more of these 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 36 for further discussion.



CRM Outlook.Our CRM business future results of operations will be significantly impacted by our ability to execute our exit strategy. We continue to explore opportunities to assign or renegotiate
the terms of some of our four remaining power tolling arrangements. If we do not renegotiate or terminate these power tolling arrangements, these arrangements will continue to negatively impact our earnings and cash flows based on the current
pricing environment. Even if we do renegotiate or terminate some of these arrangements, we could be required to pay a significant amount of cash relating to any such renegotiation or termination which may also negatively impact earnings and cash
flows. For a discussion of our annual and long-term obligations under these arrangements, see Item 1. BusinessSegment DiscussionCustomer Risk Management beginning on page 15.



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The earnings of the CRM segment may also be significantly impacted, either positively or negatively, by
mark-to-market changes in the value of a derivative contract associated with the Sithe Independence tolling agreement as power and gas prices change.



We have posted approximately $120 million of collateral associated with this business. Approximately $20 million of this balance relates to our tolling
arrangements. An additional $40 million relates to the ABG Gas Supply gas contract, which will expire in the first quarter of 2006. The remaining $60 million is related to our legacy gas and power positions, which collateral will be substantially
eliminated by 2007.



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:



|                                                       |  |                                      |     |   |     |   |     |     |  |   |                     |   |  |              |      |   |  |   |    
|------------------------------------------------------ |  | ------------------------------------ | --- | - | --- | - | --- | --- |  | - | ------------------- | - |  | ------------ | ---- | - |  | - | ---
|                                                       |  | For the Year Ended December 31, 2003
|                                                       |  | GEN                                  |     |   | NGL |   |     | CRM |  |   | Other &Eliminations |   |  | Consolidated
|                                                       |  | (in millions)                       
|Operating Cash Flows Before Changes in Working Capital |  | $                                    | 454 |   |     | $ | 233 |     |  | $ | (29                 | ) |  | $            | (364 | ) |  | $ | 294
|Changes in Working Capital                             |  |                                      | (36 | ) |     |   | (47 | )   |  |   | 525                 |   |  |              | 24   |   |  |   | 466
|                                                       |  |                                      |     |   |     |   |     |     |  |   |                     |   |  |              |      |   |  |   |    
|Net Cash Provided by (Used in) Operating Activities    |  | $                                    | 418 |   |     | $ | 186 |     |  | $ | 496                 |   |  | $            | (340 | ) |  | $ | 760
|                                                       |  |                                      |     |   |     |   |     |     |  |   |                     |   |  |              |      |   |  |   |    



Operating Cash
Flow. Our cash flow provided by operations totaled $760 million for the 12 months ended December 31, 2003. 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 the 12 months ended December 31, 2003.



For the 12 months ended December 31, 2002, our cash flow provided by operations was $26 million. When compared to 2003, the primary driver of our decrease in operating cash flows 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.



For the 12 months ended December 31, 2001, our cash flow provided by operations totaled $176 million. Our GEN segment experienced strong operational
results, reflecting added generation capacity and a favorable commodity price environment, which contributed operating cash flows of approximately $500 million. Similarly, our NGL segment experienced strong operational results stemming from
beneficial price realization and positive working capital changes related to sales of natural gas liquids in storage due to the favorable business environment.



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Capital Expenditures and Investing Activities. Cash used in investing activities for the 12
months ended December 31, 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 the 12 months ended December 31, 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 billion 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.



Finally,
cash used in investing activities in 2001 totaled $1.3 billion. Included in 2001 capital expenditures is the purchase of the Central Hudson power generation facilities for $903 million. Additional capital expenditures of approximately $1.1 billion
principally related to the construction of power generation assets and investments associated with technology infrastructure. Business acquisitions during 2001 included approximately $595 million related to the purchase of BGSL. Proceeds from asset
sales in 2001 included the sale of the Central Hudson facilities in May 2001 for $920 million pursuant to a leveraged lease transaction, in addition to proceeds from the disposal of non-strategic Canadian assets and investments. Other investing
activities in 2001 primarily include investments relating to a generation lease arrangement.



Financing Activities. 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 notes offering; (2)
$1,393 million associated with the August 2003 refinancing; and (3) $159 million from the Term A loan drawn in connection with the April 2, 2003 credit facility restructuring;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Repayments of long-term debt totaled $2.4 billion for 2003 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 public notes; (3) $360 million prepayment of the Term B loan outstanding under our restructured credit facility; (4) $200 million prepayment of the Term A loan outstanding under our
restructured credit facility; (5) $200 million in payments under the Renaissance and Rolling Hills interim financing; (6) $165 million payment in full for the Generation facility capital lease; (7) $74 million in payments under the ABG Gas Supply
credit agreement; and (8) $62 million in payments under the Black Thunder secured financing prior to its prepayment; and
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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



| |  | 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 credit agreement;
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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
therefrom; 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 our revolving credit facilities.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



During 2001, cash provided by financing activities totaled approximately $1.3 billion. Proceeds from long-term borrowings consisted primarily of (1) the issuance of $496 million of 6.875% Senior Notes due April 1,
2011, net of issuance costs. Such proceeds were used to repay credit facility borrowings obtained to finance the purchase of the Central Hudson generation facilities; (2) $282 million associated with the ABG Gas Supply credit agreement; and (3)
proceeds from lease arrangements of approximately $80 million, which were used in the construction of two generation 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, while the regulated energy delivery business has higher
seasonal gas sales in the winter and higher seasonal electricity sales in the summer. These trends 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 Controllers 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 regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these
estimates and judgments. We have identified the following five critical accounting policies that require a significant amount of judgment and are considered to be the most 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; and
| | - | ---------------------------------



| |  | Accounting for Income Taxes.
| | - | ----------------------------



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, 2003, 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 businesses consist largely of the ownership and operation of physical assets that we use in various
generation, processing and delivery operations. These processes include 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 and 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, 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 LIBOR-based 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



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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 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.



Under SFAS No. 133, as amended, 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, 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 a long-lived asset is held and used, the determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets.
If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss if the 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 to determine if an impairment loss is required.



We follow the guidance of APB 18, The Equity Method of Accounting for Investments in Common Stock, and SFAS No. 115, Accounting for
Certain Investments in Debt and Equity Securities, 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 events warrant an assessment. Fair value utilized in this assessment is also based on our estimate of future cash flows.



Our assessment regarding the existence of impairment factors is based on
market conditions, operational performance and legal factors impacting our businesses. Our review of factors present and the resulting estimation of the appropriate carrying value of our property, plant and equipment, investments and goodwill are
subject to judgments and estimates that management is required to make. Our fair value estimates are impacted significantly by the estimated useful lives of the assets, commodity prices, regulations and discount rate assumptions. If different
judgments were applied to fair value calculations, the fair value estimate, and potential resulting impairment, could differ from our estimate. Actual results could vary materially from these estimates.



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Estimated Useful Lives



The estimated useful lives of our long-lived assets are used to compute depreciation expense and are also used for impairment testing. Estimated useful
lives are based 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.
These estimates could be impacted by future energy prices, environmental regulations and competition. If the useful lives of these assets were found to be shorter than originally estimated, depreciation charges would be accelerated.



Accounting for Contingencies



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, 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 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 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 judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts.



Liabilities are recorded when environmental assessment indicates that
remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based 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. Any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized
immediately in earnings.



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 is recognized immediately in earnings.



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. Please read Note 14Income Taxes beginning on page F-38
for further discussion.



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 exposure together with assessing temporary differences
resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences 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. To the extent we
establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or benefit within the tax provisions in the consolidated statements of operations. Significant management judgment is required in
determining any valuation allowance recorded against our deferred tax assets.



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We have recorded deferred tax assets principally resulting from net operating losses, AMT credits and
capital losses. As of December 31, 2003 and 2002, deferred tax assets related to net operating losses totaled $564 million and $228 million, respectively. As of December 31, 2003 and 2002, deferred tax assets related to AMT credits totaled $3
million and $14 million, respectively. As of December 31, 2003 and 2002, the deferred tax asset related to capital losses totaled zero and $16 million, respectively. We have not established a valuation allowance against these deferred tax assets, as
we believe that it is more likely than not that these deferred tax assets will be realized. We expect that future sources of taxable income, reversing temporary differences and other tax planning strategies will be sufficient to realize these
assets. 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.



RECENT ACCOUNTING PRONOUNCEMENTS



See Note 2Accounting PoliciesAccounting Principles Adopted beginning on page F-14 for a discussion of recently issued accounting
pronouncements affecting us. Specifically, we adopted the net presentation provisions of EITF Issue 02-03 in the third quarter 2002 and we adopted the provision within EITF Issue 02-03 that rescinds EITF Issue 98-10 effective January 1, 2003. We
also adopted SFAS No. 143 effective January 1, 2003. We adopted SFAS No. 150 and EITF Issue 03-11 effective July 1, 2003. We adopted portions of FIN 46R, as required by GAAP, effective December 31, 2003.



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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, 2003 |     
|                                                                                      |  | (in millions)                                |     
|Balance Sheet Risk-Management Accounts                                                |  |                                              |      |  
|Fair value of portfolio at January 1, 2003                                            |  | $                                            | 358  |  
|Risk-management losses recognized through the income statement in the period, net (1) |  |                                              | (184 | )
|Cash received related to risk-management contracts settled in the period, net (2)     |  |                                              | (258 | )
|Changes in fair value as a result of a change in valuation technique (3)              |  |                                              |     |  
|Non-cash adjustments and other (4)                                                    |  |                                              | (53  | )
|                                                                                      |  |                                              |      |  
|Fair value of portfolio at December 31, 2003                                          |  | $                                            | (137 | )
|                                                                                      |  |                                              |      |  
|Income Statement Reconciliation                                                       |  |                                              |      |  
|Risk-management losses recognized through the income statement in the period, net (1) |  | $                                            | (184 | )
|Physical business recognized through the income statement in the period, net (5)      |  |                                              | (128 | )
|Non-cash adjustments and other                                                        |  |                                              | 8    |  
|                                                                                      |  |                                              |      |  
|Net recognized operating loss                                                         |  | $                                            | (304 | )
|                                                                                      |  |                                              |      |  
|Cash Flow Statement                                                                   |  |                                              |      |  
|Cash received related to risk-management contracts settled in the period, net (2)     |  | $                                            | 258  |  
|Estimated cash paid related to physical business settled in the period, net (5)       |  |                                              | (128 | )
|Timing and other, net (6)                                                             |  |                                              | (57  | )
|                                                                                      |  |                                              |      |  
|Cash received during the period                                                       |  | $                                            | 73   |  
|                                                                                      |  |                                              |      |  
|Risk-Management cash flow adjustment for the year ended December 31, 2003 (7)         |  | $                                            | 377  |  
|                                                                                      |  |                                              |      |  

---

|(1) | This amount consists primarily of $121 million in mark-to-market losses on contracts associated with the Sithe Independence power tolling arrangement and a $30 million loss
associated with the settlement of power supply agreements with Kroger.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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

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

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

|(5) | This amount consists primarily of capacity payments on our power tolling arrangements.
|--- | --------------------------------------------------------------------------------------

|(6) | This amount consists primarily of cash paid in connection with the settlement of cash flow hedges.
|--- | --------------------------------------------------------------------------------------------------

|(7) | This amount is calculated as Cash received during the period less Net recognized operating loss.
|--- | ----------------------------------------------------------------------------------------------------



The net risk management liability of $137 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.



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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, 2003. 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.



Net Risk-Management Asset and Liability Disclosures



|                   |  |               |      |   |      |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  
|------------------ |  | ------------- | ---- | - | ---- | - | --- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- |  | - | --- | - |  | - | --- | -
|                   |  | Total         |      |   | 2004 |   |     | 2005 |  |   | 2006 |   |  | 2007 |     |   | 2008 |   |     | Thereafter | 
|                   |  | (in millions) |     
|Mark-to-Market (1) |  | $             | (144 | ) |      | $ | (22 | )    |  | $ | (17  | ) |  | $    | (25 | ) |      | $ | (39 | )          |  | $ | (12 | ) |  | $ | (29 | )
|Cash Flow (2)      |  |               | (152 | ) |      |   | (17 | )    |  |   | (14  | ) |  |      | (24 | ) |      |   | (43 | )          |  |   | (15 | ) |  |   | (39 | )

---

|(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, 2003 of $137 million on the consolidated balance sheets includes the $144 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, 2003, based on our valuation methodology.



Net Fair Value of Risk-Management Portfolio



|                           |  |               |      |   |      |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  
|-------------------------- |  | ------------- | ---- | - | ---- | - | --- | ---- |  | - | ---- | - |  | ---- | --- | - | ---- | - | --- | ---------- |  | - | --- | - |  | - | --- | -
|                           |  | Total         |      |   | 2004 |   |     | 2005 |  |   | 2006 |   |  | 2007 |     |   | 2008 |   |     | Thereafter | 
|                           |  | (in millions) |     
|Market Quotations (1)      |  | $             | (69  | ) |      | $ | (22 | )    |  | $ | (20  | ) |  | $    |    |   |      | $ | (25 | )          |  | $ | (1  | ) |  | $ | (1  | )
|Prices Based on Models (2) |  |               | (75  | ) |      |   |    |      |  |   | 3    |   |  |      | (25 | ) |      |   | (14 | )          |  |   | (11 | ) |  |   | (28 | )
|                           |  |               |      |   |      |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  
|Total                      |  | $             | (144 | ) |      | $ | (22 | )    |  | $ | (17  | ) |  | $    | (25 | ) |      | $ | (39 | )          |  | $ | (12 | ) |  | $ | (29 | )
|                           |  |               |      |   |      |   |     |      |  |   |      |   |  |      |     |   |      |   |     |            |  |   |     |   |  |   |     |  

---

|(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 53.
|--- | -----------------------------------------------------------------------------------------------------



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 60.



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



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can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words
such as anticipate, estimate, project, forecast, plan, may, will, should, expect and other words of similar meaning. In particular, these
include, but are not limited to, statements relating to the following:



| |  | projected operating or financial results, including anticipated cash flows from operations and asset sale proceeds for 2004;
| | - | ----------------------------------------------------------------------------------------------------------------------------



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



| |  | our ability to execute 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 as they come due,
particularly the February 2005 maturity of our $1.1 billion revolving credit facility;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



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



| |  | our ability to consummate the disposition of specified non-strategic assets on the terms and in the timeframes anticipated; and
| | - | -------------------------------------------------------------------------------------------------------------------------------



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



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



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



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



| |  | the effects of the proposed sales of specified non-strategic assets, including Dynegys agreed upon sale of Illinois Power to Ameren;
| | - | -------------------------------------------------------------------------------------------------------------------------------------



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



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



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| |  | increased interest expense and the other effects of our 2003 restructuring and refinancing transactions, including the security arrangements and restrictive covenants contained in
the related financing agreements;
| | - | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | 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 the CRM business and environmental liabilities that may not be covered by indemnity or insurance, as well as the FERC, U.S. Attorney and other similar investigations primarily surrounding Project
Alpha and our past trading practices;
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  | general political conditions and developments in the United States and in foreign countries whose affairs affect our 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.
| | - | --------------------------------------------------------------------------------------------



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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;
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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, including substantial swings
in volatility factors, absolute commodity price changes and the impact of interest rate movements.



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. Average
VaR is not available for 2002 due to the restatement of historical results. While VaR can be calculated at a single point in time, it is not feasible to recalculate the historical results necessary to calculate an average.



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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.



Daily and Average VaR for Risk-Management Portfolio



|                                                                 |  |                  |   |                  |   |    
|---------------------------------------------------------------- |  | ---------------- | - | ---------------- | - | ---
|                                                                 |  | December 31,2003 |   | December 31,2002
|                                                                 |  | (in millions)   
|One Day VaR95% Confidence Level                                 |  | $                | 4 |                  | $ | 8  
|One Day VaR99% Confidence Level                                 |  | $                | 6 |                  | $ | 11 
|Average VaR for the Year-to-Date Period95% Confidence Level (1) |  | $                | 6 |                  |   | N/A

---

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



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, 2003 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          |  | $                       | 151 |                             | $ |      |  | $ | 151
|Commercial/Industrial/End Users |  |                         | 56  |                             |   | 42    |  |   | 98 
|Utility and Power Generators    |  |                         | 18  |                             |   |      |  |   | 18 
|Oil and Gas Producers           |  |                         | 41  |                             |   | 8     |  |   | 49 
|Other                           |  |                         |    |                             |   | 1     |  |   | 1  
|                                |  |                         |     |                             |   |       |  |   |    
|Total                           |  | $                       | 266 |                             | $ | 51    |  | $ | 317
|                                |  |                         |     |                             |   |       |  |   |    



Of the $51 million in
credit exposure to non-investment grade counterparties, approximately 92% ($47 million) is collateralized or subject to other credit exposure protection.



Interest Rate Risk. Interest rate risk primarily results from variable rate debt obligations and, since changing interest rates impact the
discounted value of future cash flows, changes in the value of our risk management portfolios. 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, 2003, our fixed
rate debt instruments as a percentage of total debt instruments was equal to 83%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of December 31, 2003, 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, 2004 would either decrease or increase income before taxes by approximately $3 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.



As we continue to execute our restructuring strategy, our interest rate risk
associated with providing risk-management services to customers has declined significantly. The following table sets forth the daily and average



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VaR associated with the interest rate component of the risk-management portfolio. We seek to manage our interest rate
exposure through application of various hedging strategies. Hedging instruments executed to mitigate such interest rate exposure in the risk-management portfolio are included in the VaR as of December 31, 2003 and December 31, 2002 and are reflected
in the table below.



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



|                                                                 |  |                  |     |                  |   |    
|---------------------------------------------------------------- |  | ---------------- | --- | ---------------- | - | ---
|                                                                 |  | December 31,2003 |     | December 31,2002
|                                                                 |  | (in millions)   
|One Day VaR95% Confidence Level                                 |  | $                | 0.6 |                  | $ | 2.5
|Average VaR for the Year-to-Date Period95% Confidence Level (1) |  | $                | 1.5 |                  |   | N/A

---

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



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



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, or such risk may be hedged through debt denominated in the foreign
currency or through financial contracts.



At December 31, 2003,
our primary foreign currency exchange rate exposures were the U.K. Pound, Canadian Dollar and European Euro. Due to the sale of the U.K. natural gas storage assets in 2002, DGC Europe in January 2003, as well as the wind down of the U.K. CRM
business through the first half of 2003, our foreign currency exchange risk has declined significantly since December 31, 2002.



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



Daily and Average Foreign Currency Exchange VaR



|                                                             |  |                  |     |                  |   |    
|------------------------------------------------------------ |  | ---------------- | --- | ---------------- | - | ---
|                                                             |  | December 31,2003 |     | December 31,2002
|                                                             |  | (in millions)   
|One Day VaR95% Confidence Level                             |  | $                | 0.2 |                  | $ | 0.4
|Average VaR for the Year-to-Date Period95% Confidence Level |  | $                | 0.3 |                  | $ | 2.9



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



Absolute Notional Contract Amounts



|                                                                     |  |                  |       |                  |   |       
|-------------------------------------------------------------------- |  | ---------------- | ----- | ---------------- | - | ------
|                                                                     |  | December 31,2003 |       | December 31,2002
|Natural Gas (Trillion Cubic Feet)                                    |  |                  | 2.364 |                  |   | 7.910 
|Electricity (Million Megawatt Hours)                                 |  |                  | 8.713 |                  |   | 64.563
|Natural Gas Liquids (Million Barrels)                                |  |                  |      |                  |   | 0.265 
|Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)   |  | $                | 25    |                  | $ | 601   
|Fixed Interest Rate Received on Swaps (%)                            |  |                  | 5.706 |                  |   | 5.616 
|Cash Flow Hedge Interest Rate Swaps (In Millions of U.S. Dollars)    |  | $                | 405   |                  | $ | 1,566 
|Fixed Interest Rate Paid on Swaps (%)                                |  |                  | 3.448 |                  |   | 2.824 
|Interest Rate Risk-Management Contract (In Millions of U.S. Dollars) |  | $                | 306   |                  | $ | 1,001 
|Fixed Interest Rate Paid (%)                                         |  |                  | 5.570 |                  |   | 5.530 
|U.K. Pound Sterling (In Millions of U.S. Dollars)                    |  | $                |      |                  | $ | 198   
|Average U.K. Pound Sterling Contract Rate (In U.S. Dollars)          |  | $                |      |                  | $ | 1.574 
|Euro Dollars (In Millions of U.S. Dollars)                           |  | $                |      |                  | $ | 5     
|Average Euro Contract Rate (In U.S. Dollars)                         |  | $                |      |                  | $ | 1.212 
|Canadian Dollar (In Millions of U.S. Dollars)                        |  | $                |      |                  | $ | 523   
|Average Canadian Dollar Contract Rate (In U.S. Dollars)              |  | $                |      |                  | $ | 0.7140



Item 8.Financial Statements and Supplementary Data



Our financial statements and financial statement schedule are set forth at pages F-1 through F-98 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. Effective as of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our
management 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 establishment of a disclosure committee and the various processes carried out under the direction of this 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. Based on this evaluation, our CEO and CFO concluded that the
consolidated enterprises disclosure controls and procedures are effective and designed to ensure that the information required to be disclosed in the consolidated enterprises SEC reports is recorded, processed, summarized and reported
within the requisite time periods. While the consolidated enterprises disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to
limitations inherent in any control system, no matter how well it may be designed or administered.



Changes in Internal Controls. There was no change in the consolidated enterprises internal controls over financial reporting (as
defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) identified in connection with the evaluation of the consolidated enterprises internal controls performed during the last fiscal quarter that has materially affected, or is
reasonably likely to materially affect, the consolidated enterprises internal controls over financial reporting.



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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 Principal Accounting Fees and Services.



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PART IV



Item 15.Exhibits, Financial Statement Schedules and Reports on Form 8-K



| | (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          |  | Exchange and Registration Rights Agreement (Notes) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.3 to the Quarterly Report on
Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                    
|              | 
|4.17          |  | 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                                                                                                                                                                                                                                                                                                                                                                                                                                                         
|4.18          |  | 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).                                                                                                                                                                                        
|              | 
|4.19          |  | Indenture dated August 11, 2003 between Dynegy Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the
Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                                                                                        
|              | 
|4.20          |  | Junior Unsecured Subordinated Note due 2016 in the principal amount of $225,000,000 issued on August 11, 2003 by Dynegy Inc. to Chevron U.S.A. Inc. (incorporated by reference to Exhibit
4.7 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).                                                                                                                                                 
|              | 
|4.21          |  | 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).
|              | 
|4.22          |  | 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).                                                                                                              
|              | 
|4.23          |  | 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).                                                                                                                                                               
|              | 
|4.24          |  | 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).                                                                                                                                           
|              | 
|4.25          |  | 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).                                                                                                                                              
|              | 
|              |  | 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).                                                                                                                                                                                                                                              
|              | 
|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).                                                                                                                                                                                                                                                            



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|              |  |                                                                                                                                                                                                                                                                 
|------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                     
|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          |  | 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. 1-11156).    
|              | 
|10.9          |  | Employment Agreement, effective February 1, 2000, between Charles L. Watson and Dynegy Inc. (incorporated by reference to Exhibit 10.9 to the Annual Report on Form 10-K for the Fiscal
Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156).      
|              | 
|10.10         |  | Employment Agreement, effective February 1, 2000, between Stephen W. Bergstrom and Dynegy Inc. (incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K for the
Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156).  
|              | 
|10.11         |  | Employment Agreement, effective as of September 16, 2002, between R. Blake Young and Dynegy Inc. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the
Quarter Ended September 30, 2002 of Dynegy Inc., File No. 1-15659). 
|              | 
|10.12         |  | Employment Agreement, effective February 1, 2000, between Alec G. Dreyer 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, 2002 of Dynegy Inc., File No. 1-11156).        
|              | 
|10.13         |  | Employment Agreement, effective December 2, 2002, between Nick J. Caruso and Dynegy Inc. (incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the Fiscal
Year Ended December 31, 2002 of Dynegy Inc., File No. 1-11156).        
|              | 
|10.14         |  | 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).       
|              | 
|10.15         |  | 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).                                
|              | 
|10.16         |  | 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).                                         
|              | 
|10.17         |  | 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         |  | 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).             
|              | 
|10.19         |  | 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).              
|              | 
|10.20         |  | 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                                                                                                                                                                                                                                                                                                                                               
|10.21         |  | 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).
                                                                                                                                                                     
|              | 
|10.22         |  | 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).
                                                                                                                                                                               
|              | 
|10.23         |  | 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).
                                                                                                                                                               
|              | 
|10.24         |  | 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).                                                                                                                                     
|              | 
|10.25         |  | 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).                                                                                                                           
|              | 
|10.26         |  | 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).                                                                                                 
|              | 
|10.27         |  | 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).                                                                                                                         
|              | 
|10.28         |  | 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).                                                                                                                                  
|              | 
|10.29         |  | 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).                                                                                                                                                            
|              | 
|10.30         |  | 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).                                                                                      
|              | 
|10.31         |  | 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).                                                                                                           
|              | 
|10.32         |  | 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).                    
|              | 
|10.33         |  |  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).
|              | 
|*10.34        |  | 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).                     
|              | 
|10.35         |  | Dynegy Inc. Severance Pay Plan (incorporated by reference to Exhibit 10.41 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                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|10.36         |  | Credit Agreement, dated as of April 1, 2003, among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the lenders party thereto
(incorporated by reference to Exhibit 10.31 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).                                                                                                                           
|              | 
|10.37         |  | 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).                                                                                                   
|              | 
|10.38         |  | 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).                                                                                                                                                                  
|              | 
|10.39         |  | 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).                                                                           
|              | 
|10.40         |  | Third Amendment to the Loan Documents dated as of July 15, 2003 among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the lenders
party thereto, including the Lender Consent dated August 1, 2003 (incorporated by reference to Exhibit 10.3 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         |  | Fourth Amendment to the Credit Agreement dated as of October 9, 2003 among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the
lenders party thereto (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on October 15, 2003, File No. 1-15659).                                                                                                               
|              | 
|10.42         |  | 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).                                                                                                                                                                                   
|              | 
|10.43         |  | 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).                                                                                                                                                                                           
|              | 
|10.44         |  | 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).
|              | 
|10.45         |  | 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).                                                                                                                  
|              | 
|10.46         |  | 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).                                                                                                                       



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|              |  |                                                                                                                                                                                                                                                                                                            
|------------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|ExhibitNumber |  | Description                                                                                                                                                                                                                                                                                                
|10.47         |  | 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).                  
|              | 
|10.48         |  | 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).
|              | 
|10.49         |  | 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).                   
|              | 
|10.50         |  |  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).                           
|              | 
|**23.1        |  | Consent of PricewaterhouseCoopers LLP.                                                                                                                                                                                                                                                                    
|              | 
|**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.
|- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | (b) | Reports on Form 8-K of Dynegy Holdings Inc. for the fourth quarter of 2003.
| | --- | ---------------------------------------------------------------------------



| | 1. | During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on October 2, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| | 2. | During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on October 15, 2003. Items 5 and 7 were reported and no financial statements were filed.
| | -- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



72



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##### Table of Contents

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 5, 2004 |  | 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 5, 2004
|                                           |  |                                                                                             
|/s/ NICK J. CARUSONick J. Caruso           |  | Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer) |  | March 5, 2004
|                                           |  |                                                                                             
|/s/ HOLLI C. NICHOLSHolli C. Nichols       |  | Senior Vice President and Controller (Principal Accounting Officer)                          |  | March 5, 2004
|                                           |  |                                                                                             
|/s/ CAROL F. GRAEBNERCarol F. Graebner     |  | Director                                                                                     |  | March 5, 2004



73



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DYNEGY HOLDINGS INC.



INDEX TO CONSOLIDATED FINANCIAL STATEMENTS



|                                                                                                                |  |     
|--------------------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                                |  | Page
|Consolidated Financial Statements                                                                               |  |     
|Report of Independent Auditors                                                                                  |  | F-2 
|Consolidated Balance Sheets as of December 31, 2003 and 2002                                                    |  | F-3 
|Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001                      |  | F-4 
|Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001                      |  | F-5 
|Consolidated Statements of Changes in Stockholders Equity for the years ended December 31, 2003, 2002 and 2001 |  | F-6 
|Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2003, 2002 and 2001     |  | F-7 
|Notes to Consolidated Financial Statements                                                                      |  | F-8 
|                                                                                                                | 
|Financial Statement Schedule                                                                                    |  |     
|Schedule II - Valuation and Qualifying Accounts                                                                 |  | F-66
|                                                                                                                | 
|West Coast Power LLC Consolidated Financial Statements*                                                         |  | F-67

---

|* | 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

REPORT OF INDEPENDENT AUDITORS



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, 2003 and 2002, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2003 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 indexpresents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial statements. These financial statements and this financial statement schedule are the responsibility of the Companys management; our responsibility is to express an
opinion on these financial statements and this financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which 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 16, 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, 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 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 December 31, 2003. As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting
Standards No. 132 (revised 2003), Employers Disclosures About Pensions and Other Postretirement Benefits  an Amendment of FASB Statements No. 87, 88, and 106 and a revision of FASB Statement No. 132, as of December 31, 2003.
As discussed in Note 2, the Company adopted the provisions of Emerging Issues Task Force No. 02-03, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, 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 the provisions of Statement of Financial Accounting Standards
No. 142, Goodwill and Other Intangible Assets, and Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, as of January 1, 2002.





/s/    PricewaterhouseCoopers LLP

Houston, Texas

March 4, 2004



F-2



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##### Table of Contents

DYNEGY HOLDINGS INC.



CONSOLIDATED BALANCE SHEETS

(in millions, except share data)



|                                                                                                                    |  |                  |        |   |                  |   |        |  
|------------------------------------------------------------------------------------------------------------------- |  | ---------------- | ------ | - | ---------------- | - | ------ | -
|                                                                                                                    |  | December 31,2003 |        |   | December 31,2002 |  
|ASSETS                                                                                                              |  |                  |        |   |                  |   |        |  
|Current Assets                                                                                                      |  |                  |        |   |                  |   |        |  
|Cash and cash equivalents                                                                                           |  | $                | 328    |   |                  | $ | 633    |  
|Accounts receivable, net of allowance for doubtful accounts of $174 and $140, respectively                          |  |                  | 806    |   |                  |   | 2,570  |  
|Accounts receivable, affiliates                                                                                     |  |                  | 25     |   |                  |   | 31     |  
|Inventory                                                                                                           |  |                  | 194    |   |                  |   | 184    |  
|Assets from risk-management activities                                                                              |  |                  | 818    |   |                  |   | 2,614  |  
|Prepayments and other current assets                                                                                |  |                  | 324    |   |                  |   | 1,088  |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Total Current Assets                                                                                                |  |                  | 2,495  |   |                  |   | 7,120  |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Property, Plant and Equipment                                                                                       |  |                  | 7,691  |   |                  |   | 7,462  |  
|Accumulated depreciation                                                                                            |  |                  | (1,389 | ) |                  |   | (1,047 | )
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Property, Plant and Equipment, Net                                                                                  |  |                  | 6,302  |   |                  |   | 6,415  |  
|Other Assets                                                                                                        |  |                  |        |   |                  |   |        |  
|Unconsolidated investments                                                                                          |  |                  | 577    |   |                  |   | 600    |  
|Assets from risk-management activities                                                                              |  |                  | 629    |   |                  |   | 2,528  |  
|Goodwill                                                                                                            |  |                  | 15     |   |                  |   | 15     |  
|Deferred income taxes                                                                                               |  |                  | 106    |   |                  |   |       |  
|Other long-term assets                                                                                              |  |                  | 156    |   |                  |   | 168    |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Total Assets                                                                                                        |  | $                | 10,280 |   |                  | $ | 16,846 |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                |  |                  |        |   |                  |   |        |  
|Current Liabilities                                                                                                 |  |                  |        |   |                  |   |        |  
|Accounts payable                                                                                                    |  | $                | 488    |   |                  | $ | 1,502  |  
|Accounts payable, affiliates                                                                                        |  |                  | 195    |   |                  |   | 964    |  
|Accrued liabilities and other current liabilities                                                                   |  |                  | 558    |   |                  |   | 1,473  |  
|Liabilities from risk-management activities                                                                         |  |                  | 838    |   |                  |   | 2,417  |  
|Notes payable and current portion of long-term debt                                                                 |  |                  | 79     |   |                  |   | 484    |  
|Current portion of long-term debt to affiliates                                                                     |  |                  | 71     |   |                  |   |       |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Total Current Liabilities                                                                                           |  |                  | 2,229  |   |                  |   | 6,840  |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Long-term debt                                                                                                      |  |                  | 3,464  |   |                  |   | 3,276  |  
|Long-term debt to affiliates                                                                                        |  |                  | 200    |   |                  |   |       |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Total Long-Term Debt                                                                                                |  |                  | 3,664  |   |                  |   | 3,276  |  
|Other Liabilities                                                                                                   |  |                  |        |   |                  |   |        |  
|Liabilities from risk-management activities                                                                         |  |                  | 746    |   |                  |   | 2,367  |  
|Deferred income taxes                                                                                               |  |                  |       |   |                  |   | 83     |  
|Other long-term liabilities                                                                                         |  |                  | 499    |   |                  |   | 695    |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Total Liabilities                                                                                                   |  |                  | 7,138  |   |                  |   | 13,261 |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Minority Interest                                                                                                   |  |                  | 121    |   |                  |   | 146    |  
|Commitments and Contingencies (Note 16)                                                                             |  |                  |        |   |                  |   |        |  
|Subordinated Debentures, redemption value of zero and $200 at December 31, 2003 and December 31, 2002, respectively |  |                  |       |   |                  |   | 200    |  
|Stockholders Equity                                                                                                |  |                  |        |   |                  |   |        |  
|Additional paid-in capital                                                                                          |  |                  | 2,419  |   |                  |   | 2,410  |  
|Accumulated other comprehensive income, net of tax                                                                  |  |                  | 33     |   |                  |   | 12     |  
|Accumulated deficit                                                                                                 |  |                  | (463   | ) |                  |   | (215   | )
|Stockholders Equity                                                                                                |  |                  | 1,032  |   |                  |   | 1,032  |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Total Stockholders Equity                                                                                          |  |                  | 3,021  |   |                  |   | 3,239  |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  
|Total Liabilities and Stockholders Equity                                                                          |  | $                | 10,280 |   |                  | $ | 16,846 |  
|                                                                                                                    |  |                  |        |   |                  |   |        |  



See the notes to the
consolidated financial statements.



F-3



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##### Table of Contents

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions)



|                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|--------------------------------------------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                            |  | Year Ended December 31, |       
|                                                                            |  | 2003                    |        |   | 2002 |   |        | 2001 | 
|Revenues                                                                    |  | $                       | 4,714  |   |      | $ | 4,245  |      |  | $ | 7,789  |  
|Cost of sales, exclusive of depreciation shown separately below             |  |                         | (4,371 | ) |      |   | (3,945 | )    |  |   | (6,404 | )
|Depreciation and amortization expense                                       |  |                         | (330   | ) |      |   | (270   | )    |  |   | (296   | )
|Goodwill impairment                                                         |  |                         |       |   |      |   | (724   | )    |  |   |       |  
|Impairment and other charges                                                |  |                         | (4     | ) |      |   | (184   | )    |  |   |       |  
|Gain on sale of assets                                                      |  |                         | 29     |   |      |   | 4      |      |  |   | 35     |  
|General and administrative expenses                                         |  |                         | (293   | ) |      |   | (255   | )    |  |   | (350   | )
|                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|Operating income (loss)                                                     |  |                         | (255   | ) |      |   | (1,129 | )    |  |   | 774    |  
|Earnings (losses) from unconsolidated investments                           |  |                         | 132    |   |      |   | (52    | )    |  |   | 178    |  
|Interest expense                                                            |  |                         | (338   | ) |      |   | (187   | )    |  |   | (137   | )
|Other income and expense, net                                               |  |                         | 11     |   |      |   | (25    | )    |  |   | 58     |  
|Minority interest income (expense)                                          |  |                         | 3      |   |      |   | (36    | )    |  |   | (93    | )
|Accumulated distributions associated with trust preferred securities        |  |                         | (8     | ) |      |   | (13    | )    |  |   | (17    | )
|                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|Income (loss) from continuing operations before income taxes                |  |                         | (455   | ) |      |   | (1,442 | )    |  |   | 763    |  
|Income tax benefit (expense)                                                |  |                         | 177    |   |      |   | 296    |      |  |   | (321   | )
|                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|Income (loss) from continuing operations                                    |  |                         | (278   | ) |      |   | (1,146 | )    |  |   | 442    |  
|Loss on discontinued operations, net of taxes (Note 3)                      |  |                         | (12    | ) |      |   | (100   | )    |  |   | (19    | )
|                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|Income (loss) before cumulative effect of change in accounting principles   |  |                         | (290   | ) |      |   | (1,246 | )    |  |   | 423    |  
|Cumulative effect of change in accounting principles, net of taxes (Note 2) |  |                         | 42     |   |      |   |       |      |  |   | 2      |  
|                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  
|Net income (loss)                                                           |  | $                       | (248   | ) |      | $ | (1,246 | )    |  | $ | 425    |  
|                                                                            |  |                         |        |   |      |   |        |      |  |   |        |  



See the notes to the
consolidated financial statements.



F-4



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##### Table of Contents

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|--------------------------------------------------------------------------------------- |  | ----------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                                                        |  | Year Ended December 31, |       
|                                                                                        |  | 2003                    |        |   | 2002 |   |        | 2001 | 
|CASH FLOWS FROM OPERATING ACTIVITIES:                                                   |  |                         |        |   |      |   |        |      |  |   |        |  
|Net income (loss)                                                                       |  | $                       | (248   | ) |      | $ | (1,246 | )    |  | $ | 425    |  
|Adjustments to reconcile net income (loss) to net cash flows from operating activities: |  |                         |        |   |      |   |        |      |  |   |        |  
|Depreciation and amortization                                                           |  |                         | 390    |   |      |   | 427    |      |  |   | 294    |  
|Goodwill impairment                                                                     |  |                         |       |   |      |   | 724    |      |  |   |       |  
|Impairment and other charges                                                            |  |                         | 4      |   |      |   | 226    |      |  |   |       |  
|(Earnings) losses from unconsolidated investments, net of cash distributions            |  |                         | 23     |   |      |   | 143    |      |  |   | (90    | )
|Risk-management activities                                                              |  |                         | 377    |   |      |   | 638    |      |  |   | (9     | )
|Loss (gain) on sale of assets                                                           |  |                         | (26    | ) |      |   | 84     |      |  |   | (35    | )
|Deferred income taxes                                                                   |  |                         | (185   | ) |      |   | (117   | )    |  |   | 136    |  
|Cumulative effect of change in accounting principles (Note 2)                           |  |                         | (42    | ) |      |   |       |      |  |   | (2     | )
|Reserve for doubtful accounts                                                           |  |                         | 13     |   |      |   | 52     |      |  |   | 56     |  
|Other                                                                                   |  |                         | (12    | ) |      |   | 105    |      |  |   | 60     |  
|Changes in working capital:                                                             |  |                         |        |   |      |   |        |      |  |   |        |  
|Accounts receivable                                                                     |  |                         | 1,590  |   |      |   | 384    |      |  |   | 1,492  |  
|Inventory                                                                               |  |                         | 123    |   |      |   | 1      |      |  |   | 18     |  
|Prepayments and other assets                                                            |  |                         | 742    |   |      |   | (717   | )    |  |   | (177   | )
|Accounts payable and accrued liabilities                                                |  |                         | (1,884 | ) |      |   | (384   | )    |  |   | (2,042 | )
|Changes in non-current assets and liabilities, net                                      |  |                         | (105   | ) |      |   | (294   | )    |  |   | 50     |  
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|Net cash provided by operating activities                                               |  |                         | 760    |   |      |   | 26     |      |  |   | 176    |  
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|CASH FLOWS FROM INVESTING ACTIVITIES:                                                   |  |                         |        |   |      |   |        |      |  |   |        |  
|Capital expenditures                                                                    |  |                         | (205   | ) |      |   | (735   | )    |  |   | (1,987 | )
|Investments in unconsolidated affiliates                                                |  |                         | (4     | ) |      |   | (11    | )    |  |   | (32    | )
|Business acquisitions, net of cash acquired                                             |  |                         |       |   |      |   | (20    | )    |  |   | (581   | )
|Proceeds from asset sales, net                                                          |  |                         | 58     |   |      |   | 715    |      |  |   | 1,014  |  
|Affiliate transactions                                                                  |  |                         | (272   | ) |      |   | 770    |      |  |   | 421    |  
|Other investing, net                                                                    |  |                         |       |   |      |   | 85     |      |  |   | (176   | )
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|Net cash provided by (used in) investing activities                                     |  |                         | (423   | ) |      |   | 804    |      |  |   | (1,341 | )
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|CASH FLOWS FROM FINANCING ACTIVITIES:                                                   |  |                         |        |   |      |   |        |      |  |   |        |  
|Net proceeds from long-term borrowings                                                  |  |                         | 1,863  |   |      |   | 532    |      |  |   | 1,091  |  
|Net proceeds from short-term borrowings                                                 |  |                         |       |   |      |   | 181    |      |  |   |       |  
|Repayments of borrowings                                                                |  |                         | (2,366 | ) |      |   | (441   | )    |  |   | (233   | )
|Net cash flow from commercial paper and revolving lines of credit                       |  |                         | (128   | ) |      |   | (540   | )    |  |   | 469    |  
|Other financing, net                                                                    |  |                         | (21    | ) |      |   | (14    | )    |  |   | (27    | )
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|Net cash provided by (used in) financing activities                                     |  |                         | (652   | ) |      |   | (282   | )    |  |   | 1,300  |  
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|Effect of exchange rate changes on cash                                                 |  |                         | 10     |   |      |   | (59    | )    |  |   | (23    | )
|Net increase (decrease) in cash and cash equivalents                                    |  |                         | (305   | ) |      |   | 489    |      |  |   | 112    |  
|Cash and cash equivalents, beginning of period                                          |  |                         | 633    |   |      |   | 144    |      |  |   | 32     |  
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  
|Cash and cash equivalents, end of period                                                |  | $                       | 328    |   |      | $ | 633    |      |  | $ | 144    |  
|                                                                                        |  |                         |        |   |      |   |        |      |  |   |        |  



See the notes to the
consolidated financial statements.



F-5



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##### Table of Contents

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS EQUITY

(in millions)



|                                       |  |                           |       |                                     |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  
|-------------------------------------- |  | ------------------------- | ----- | ----------------------------------- | - | --- | ------------------------------------ |  | - | ------------------- | - | ----- | - | ----- |  | - | ------ | -
|                                       |  | AdditionalPaid-In-Capital |       | AccumulatedOtherComprehensiveIncome |   |     | RetainedEarnings(AccumulatedDeficit) |  |   | StockholdersEquity |   | Total |  
|December 31, 2000                      |  | $                         | 2,336 |                                     | $ | (15 | )                                    |  | $ | 606                 |   |       | $ | 1,032 |  | $ | 3,959  |  
|Net income                             |  |                           |      |                                     |   |    |                                      |  |   | 425                 |   |       |   |      |  |   | 425    |  
|Other comprehensive income, net of tax |  |                           |      |                                     |   | 25  |                                      |  |   |                    |   |       |   |      |  |   | 25     |  
|Options exercised                      |  |                           | 32    |                                     |   |    |                                      |  |   |                    |   |       |   |      |  |   | 32     |  
|401(k) plan and profit sharing stock   |  |                           | 6     |                                     |   |    |                                      |  |   |                    |   |       |   |      |  |   | 6      |  
|Options granted                        |  |                           | 9     |                                     |   |    |                                      |  |   |                    |   |       |   |      |  |   | 9      |  
|Capital contribution                   |  |                           | 9     |                                     |   |    |                                      |  |   |                    |   |       |   |      |  |   | 9      |  
|                                       |  |                           |       |                                     |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  
|December 31, 2001                      |  | $                         | 2,392 |                                     | $ | 10  |                                      |  | $ | 1,031               |   |       | $ | 1,032 |  | $ | 4,465  |  
|Net loss                               |  |                           |      |                                     |   |    |                                      |  |   | (1,246              | ) |       |   |      |  |   | (1,246 | )
|Other comprehensive income, net of tax |  |                           |      |                                     |   | 2   |                                      |  |   |                    |   |       |   |      |  |   | 2      |  
|Options exercised                      |  |                           | 11    |                                     |   |    |                                      |  |   |                    |   |       |   |      |  |   | 11     |  
|401(k) plan and profit sharing stock   |  |                           | 7     |                                     |   |    |                                      |  |   |                    |   |       |   |      |  |   | 7      |  
|                                       |  |                           |       |                                     |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  
|December 31, 2002                      |  | $                         | 2,410 |                                     | $ | 12  |                                      |  | $ | (215                | ) |       | $ | 1,032 |  | $ | 3,239  |  
|Net loss                               |  |                           |      |                                     |   |    |                                      |  |   | (248                | ) |       |   |      |  |   | (248   | )
|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                      |  | $                         | 2,419 |                                     | $ | 33  |                                      |  | $ | (463                | ) |       | $ | 1,032 |  | $ | 3,021  |  
|                                       |  |                           |       |                                     |   |     |                                      |  |   |                     |   |       |   |       |  |   |        |  



See the notes to the
consolidated financial statements.



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##### Table of Contents

DYNEGY HOLDINGS INC.



CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in millions)



|                                                                                                   |  |                         |      |   |      |   |        |      |  |   |     |  
|-------------------------------------------------------------------------------------------------- |  | ----------------------- | ---- | - | ---- | - | ------ | ---- |  | - | --- | -
|                                                                                                   |  | Year Ended December 31, |     
|                                                                                                   |  | 2003                    |      |   | 2002 |   |        | 2001 | 
|Net income (loss)                                                                                  |  | $                       | (248 | ) |      | $ | (1,246 | )    |  | $ | 425 |  
|Cash flow hedging activities, net:                                                                 |  |                         |      |   |      |   |        |      |  |   |     |  
|Cumulative effect of transition adjustment                                                         |  |                         |     |   |      |   |       |      |  |   | 61  |  
|Unrealized mark-to-market gains arising during period, net                                         |  |                         | 39   |   |      |   | 73     |      |  |   | 4   |  
|Reclassification of mark-to-market gains to earnings, net                                          |  |                         | (37  | ) |      |   | (73    | )    |  |   | (57 | )
|                                                                                                   |  |                         |      |   |      |   |        |      |  |   |     |  
|Changes in cash flow hedging activities, net (net of tax expense of $1, zero and $5, respectively) |  |                         | 2    |   |      |   |       |      |  |   | 8   |  
|Foreign currency translation adjustments                                                           |  |                         | 19   |   |      |   | 3      |      |  |   | 11  |  
|Minimum pension liability (net of tax benefit of zero, $2 and zero, respectively)                  |  |                         |     |   |      |   | (3     | )    |  |   |    |  
|Unrealized losses on securities, net:                                                              |  |                         |      |   |      |   |        |      |  |   |     |  
|Unrealized holding losses arising during period, net                                               |  |                         |     |   |      |   |       |      |  |   | (6  | )
|Less: Reclassification adjustments for losses realized in net loss                                 |  |                         |     |   |      |   | 2      |      |  |   | 12  |  
|                                                                                                   |  |                         |      |   |      |   |        |      |  |   |     |  
|Net unrealized gains (net of tax expense of zero, $1 and $4, respectively)                         |  |                         |     |   |      |   | 2      |      |  |   | 6   |  
|                                                                                                   |  |                         |      |   |      |   |        |      |  |   |     |  
|Other comprehensive income, net of tax                                                             |  |                         | 21   |   |      |   | 2      |      |  |   | 25  |  
|                                                                                                   |  |                         |      |   |      |   |        |      |  |   |     |  
|Comprehensive income (loss)                                                                        |  | $                       | (227 | ) |      | $ | (1,244 | )    |  | $ | 450 |  
|                                                                                                   |  |                         |      |   |      |   |        |      |  |   |     |  



See the notes to the
consolidated financial statements.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS



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 2003: GEN, NGL and CRM. We reported our results in 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-64.



We are a wholly owned subsidiary of Dynegy Inc. Dynegy Inc. 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 refer to Dynegy Inc. and its consolidated subsidiaries as Dynegy unless the context clearly requires otherwise.



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 develop estimates and to make assumptions that affect reported financial position and results of operation. These
estimates and assumptions also impact the nature and extent of disclosure, if any, of contingent liabilities. We review significant estimates affecting our consolidated financial statements on a recurring basis and record the effect of any necessary
adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time such estimates are made. Adjustments made with respect to the use of these estimates often relate
to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates are primarily used in (1) developing fair value assumptions, including estimates
of future cash flows and discounts 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 and (5) determining
amounts to accrue for contingencies. Actual results could differ materially from any such estimates.



Principles of Consolidation.The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned
or controlled subsidiaries, and our proportionate share of assets, liabilities, revenues and expenses of undivided interests in certain gas processing facilities, 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.



Allowance
for Doubtful Accounts.We establish provisions for losses on accounts receivable if it is reasonable to assume 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. The specific identification method is also used in certain circumstances.



Investment in Unconsolidated Affiliates.Investments in affiliates over which we may exercise significant influence, generally 20% to 50%
ownership interests, are accounted for using the equity method. 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 income (loss). Realized gains and losses on investment



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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.



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.



Inventory.Our natural gas, natural gas liquids, coal and crude oil inventories are valued 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 three to 40 years. Composite depreciation rates (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 of Years
|Power Generation Facilities                                           |  | 27 to 40      
|Natural Gas Gathering Systems and Processing Facilities               |  | 14 to 25      
|Fractionation, Terminaling and Natural Gas Liquids Storage Facilities |  | 14 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 in the
consolidated statements of operations. Through December 31, 2001, we reviewed the carrying value of our long-lived assets in accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed of. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which addresses the accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121 and APB Opinion No. 30, Reporting the Results of OperationsReporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. Under
this standard, we evaluate an asset for impairment when events or circumstances indicate its carrying value may not be recovered. These events include market declines, changes in the manner in which we intend to use an asset or decisions to sell an
asset and adverse changes in the legal or business environment. When we decide to exit or sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to the estimated sales price, less costs to
sell. Our adoption of SFAS No. 144 on January 1, 2002 did not have any impact on our financial position or results of operations. See Note 4Restructuring and Impairment Charges beginning on page F-19 for a discussion of impairment charges we
recognized in 2002 and 2003.



Asset Retirement
Obligations.In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations. We adopted SFAS No. 143, which provides accounting requirements for costs associated with legal obligations to retire tangible,
long-lived assets, effective January 1, 2003. Under SFAS No. 143, an ARO is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is
accreted towards the ultimate obligation amount and the capitalized ARO costs are depreciated over the useful life of the related asset.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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.



At January 1, 2003, our ARO liabilities were $26 million for our GEN segment and $9 million for our NGL segment. These retirement obligations 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 resulting from adoption of this standard and
the accretion of the liability towards the ultimate obligation amount was $6 million in 2003. During 2003, accretion expense recognized for the fair value for all of our ARO liabilities totaled $4 million. There were no additional AROs recorded or
settled during 2003. At December 31, 2003, our ARO liabilities were $30 million for our GEN segment and $10 million for our NGL segment.



The following pro forma financial information has been prepared to give effect to the adoption of SFAS No. 143 as if it had been adopted January 1, 2001:



|                                                                                       |  |                        |        |   |      |   |     |  
|-------------------------------------------------------------------------------------- |  | ---------------------- | ------ | - | ---- | - | --- | -
|                                                                                       |  | Year EndedDecember 31, |       
|                                                                                       |  | 2002                   |        |   | 2001 |  
|                                                                                       |  | (in millions)          |       
|Income (loss) from continuing operations, as reported                                  |  | $                      | (1,146 | ) |      | $ | 442 |  
|Pro forma adjustments to reflect retroactive adoption of SFAS No. 143                  |  |                        | (5     | ) |      |   | (4  | )
|                                                                                       |  |                        |        |   |      |   |     |  
|Pro forma income (loss) from continuing operations                                     |  | $                      | (1,151 | ) |      | $ | 438 |  
|                                                                                       |  |                        |        |   |      |   |     |  
|Income (loss) before cumulative effect of change in accounting principles, as reported |  | $                      | (1,246 | ) |      | $ | 423 |  
|Pro forma adjustments to reflect retroactive adoption of SFAS No. 143                  |  |                        | (3     | ) |      |   | (3  | )
|                                                                                       |  |                        |        |   |      |   |     |  
|Pro forma income (loss) before cumulative effect of change in accounting principles    |  | $                      | (1,249 | ) |      | $ | 420 |  
|                                                                                       |  |                        |        |   |      |   |     |  
|Net income (loss), as reported                                                         |  | $                      | (1,246 | ) |      | $ | 425 |  
|Pro forma adjustments to reflect retroactive adoption of SFAS No. 143                  |  |                        | (3     | ) |      |   | (3  | )
|                                                                                       |  |                        |        |   |      |   |     |  
|Pro forma net income (loss)                                                            |  | $                      | (1,249 | ) |      | $ | 422 |  
|                                                                                       |  |                        |        |   |      |   |     |  



The following table
presents the AROs that would have been included in other long-term liabilities on our consolidated balance sheets if SFAS No. 143 had been adopted January 1, 2001:



|                           |  |               |    |      |   |   
|-------------------------- |  | ------------- | -- | ---- | - | --
|                           |  | 2002          |    | 2001
|                           |  | (in millions)
|Balance, beginning of year |  | $             | 31 |      | $ | 26
|Liabilities incurred       |  |               | 1  |      |   | 2 
|Accretion expense          |  |               | 3  |      |   | 3 
|                           |  |               |    |      |   |   
|Balance, end of year       |  | $             | 35 |      | $ | 31
|                           |  |               |    |      |   |   



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.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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 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 and Other Intangible Assets. Prior to January 1, 2002, intangible assets, principally goodwill, were amortized on a straight-line basis over their estimated useful lives of 25 to 40 years.
However, we adopted SFAS No. 142 effective January 1, 2002, and, accordingly, discontinued amortizing goodwill. In accordance with SFAS No. 142, we subject goodwill to a fair value-based impairment test on at least an annual basis. As further
discussed in Note 10Goodwill beginning on page F-29, we recognized a $724 million goodwill impairment in 2002 related to the CRM and GEN segments. 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.



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 whether to apply one comprehensive accounting model rather than the other based on guidance provided by the FASB and the SEC.



The accrual model has historically been used to account for substantially all of the operations conducted in the GEN and NGL segments. Revenues from power
generation are recognized upon output, product delivery or satisfaction of specific targets, all as specified by contractual terms. Revenues for product sales, gas processing, storage and marketing and refinery services are recognized when title
passes to the customer or when the service is performed. Fractionation and transportation revenues are recognized based on volumes received in accordance with contractual terms. Shipping and handling costs are included in revenue when billed to
customers with the sale of products.



The fair value model is
used to account for certain forward physical and financial transactions, primarily in the GEN and CRM segments, which meet criteria defined by FASB for derivative instruments. These criteria require these contracts to relate to future periods, to
contain price and volume components and to have terms that require or permit net settlement of the contract in cash or its 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. The net gains or losses resulting from the revaluation of these contracts during the period are recognized currently in our consolidated statements of operations unless such
contracts qualify and are designated as cash flow hedges, in which case the same gains or losses are recorded in other comprehensive income (loss) until such time as the hedged transaction occurs. If the underlying transaction being hedged by the
commodity, interest rate or foreign currency transaction is disposed of or otherwise terminated, the gain or loss associated with such contract is no longer deferred and is recognized in the period the underlying contract is eliminated. Subsequent
gains and losses associated with the change in value of interest rate or foreign currency instruments are recognized in other income and expense, net, unless the instrument is redesignated as a hedge. If the hedging transaction is terminated prior
to the occurrence of the underlying transaction being hedged, the gain or loss associated with the hedging transaction is deferred and recognized in income in the period in which the underlying transaction being hedged occurs. Assets and liabilities
associated with these transactions are reflected on our consolidated balance sheets as risk-management assets and liabilities and classified as short- (i.e., current) or long-term pursuant to each contracts individual length.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



We estimate the fair value of our marketing portfolio using a liquidation value approach assuming
that our ability to transact business in the market remains at historical levels. The estimated fair value of our portfolio is computed by multiplying all existing positions in our portfolio by estimated prices, reduced by a LIBOR-based 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 or, if market quotes are unavailable, (2) prices from a proprietary model that
incorporates forward energy prices derived from market quotes and values from executed transactions.



In 2002, the EITF reached consensuses on several issues pursuant to Issue 02-03, Issues Involved in Accounting for Derivative Contracts Held for
Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities. 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.



Second, in October 2002,
as an additional component of EITF Issue 02-03, the EITF rescinded EITF Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities, 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 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 outflows associated with the settlement of risk management activities are recognized in operating 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. Under this method, income taxes are provided for amounts
currently payable and for amounts deferred as tax assets and liabilities caused by differences between financial statement carrying amounts and the tax bases of certain assets and liabilities. Deferred income taxes are measured using the enacted tax
rates



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



that are assumed will be in effect when the differences reverse. Valuation allowances are provided against deferred
tax assets when, based on our estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The estimates used to recognize deferred tax assets are subject to revision, either higher or lower, in
future periods based on new facts or circumstances.



We are
included in the consolidated federal and state income tax returns filed by Dynegy. Pursuant to tax allocation arrangements, we record a receivable 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.



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 zero, gains of $13 million and losses of $10 million for the years ended December 31, 2003, 2002 and 2001, 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. As a result, a charge of approximately $1 million is included in general and administrative expenses for the year ended December 31, 2003.



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 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 Inc. has granted in-the-money options in the past and continue to recognize compensation expense over
the applicable vesting periods. No in-the-money stock options have been granted since 2001.



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 income (loss) would have approximated the following pro forma amounts for
the years ended December 31, 2003, 2002 and 2001, respectively.



|                                                                                                                                            |  |                          |      |   |      |   |        |      |  |   |     |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------------ | ---- | - | ---- | - | ------ | ---- |  | - | --- | -
|                                                                                                                                            |  | Years Ended December 31, |     
|                                                                                                                                            |  | 2003                     |      |   | 2002 |   |        | 2001 | 
|                                                                                                                                            |  | (in millions)            |     
|Net income (loss) as reported                                                                                                               |  | $                        | (248 | ) |      | $ | (1,246 | )    |  | $ | 425 |  
|Add: Stock-based employee compensation expense included in reported net income (loss), net of related tax effects                           |  |                          | 2    |   |      |   | 8      |      |  |   | 6   |  
|Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax
effects |  |                          | (30  | ) |      |   | (70    | )    |  |   | (53 | )
|                                                                                                                                            |  |                          |      |   |      |   |        |      |  |   |     |  
|Pro forma net income (loss)                                                                                                                 |  | $                        | (276 | ) |      | $ | (1,308 | )    |  | $ | 378 |  
|                                                                                                                                            |  |                          |      |   |      |   |        |      |  |   |     |  



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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 2003, 2002 and 2001: dividends per year of zero for 2003, $0.15 for 2002 and $0.30 per share for 2001; expected volatility of 89.6%, 74.3% and 46.4%,
respectively; a risk-free interest rate of 3.9%, 4.2% and 4.3%, respectively; and an expected option life of ten years for all periods.



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. 132. In December 2003, the FASB released SFAS No. 132
(revised 2003), Employers Disclosures about Pensions and Other Postretirement Benefits. The revised standard requires disclosures for pensions and other postretirement benefit plans and replaces existing pension disclosure
requirements. We adopted the new disclosure requirements as of December 31, 2003. Please see Note 19Employee Compensation, Savings and Pension Plans beginning on page F-53 for these required disclosures.



SFAS No. 143. In June 2001, the FASB issued SFAS No. 143, which
we adopted January 1, 2003. For further discussion, please see Asset Retirement Obligations beginning on page F-9.



SFAS No. 146. In July 2002, the FASB issued SFAS No. 146, Accounting for Exit or Disposal Activities, which addresses the
recognition, measurement and reporting of costs associated with exit and disposal activities, including restructuring activities previously accounted for pursuant to the guidance in EITF Issue 94-3, Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). SFAS No. 146 is effective for exit or disposal activities initiated after December 31, 2002. The application of SFAS No. 146 during
2003 did not have a material impact on our financial statements.



SFAS No. 148. In December 2002, the FASB issued SFAS No. 148. 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. For further discussion, please see Employee Stock Options beginning on page F-13.



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



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



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



$200 million of Company Obligated Preferred Securities (now referred to as 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. 45. In November 2002, the FASB issued
FIN No. 45, Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others. As required by FIN No. 45, we adopted the disclosure requirements on December 31, 2002. On
January 1, 2003, we adopted the initial recognition and measurement provisions for guarantees issued or modified after December 31, 2002. The adoption of the recognition and measurement provisions did not materially impact our financial statements.



FIN No. 46. 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 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 will be required to consolidate the
variable interest entity as the primary beneficiary. FIN No. 46 was applicable immediately to variable interest entities created or obtained after January 31, 2003. While we have not entered into any arrangements in 2003 that would be subject to FIN
No. 46, 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. Please also see Note 15Redeemable Preferred SecuritiesSubordinated Debentures beginning
on page F-40. We will adopt FIN No. 46R for non-special purpose entities on March 31, 2004. We are in the process of assessing the impact, if any, that this adoption will have on our financial statements.



CoGen Lyondell, Inc. (CLI) is 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 is a synthetic lease entity which leases 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 does
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 portion of FIN No. 46R on January 1, 2001, our income (loss) before cumulative effect of change in accounting principles would have decreased by zero, $1 million and $3 million for the years ended December 31, 2003, 2002
and 2001, respectively. Our net income (loss) would have increased (decreased) by $15 million, $(1) million and $(3) million for the years ended December 31, 2003, 2002 and 2001, respectively. The $15 million cumulative effect noted above is
primarily a result of recording additional accumulated depreciation on the facility from June 1997, 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Refinancing and Restructuring TransactionsFollow-on Notes Offering beginning on page F-30.



EITF Issue 02-03. During 2002, the EITF reached consensus on several issues pursuant to EITF Issue 02-03. For further discussion, please
see Revenue Recognition beginning on page F-11.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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



Note 3Discontinued Operations,
Dispositions, Contract Terminations and Acquisitions



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, some of 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.



On August 16, 2002, we and Dynegy sold
all of our investment 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 held by Dynegy and 5% of the purchase price was
allocated to the common stock held 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. NNGs results of operations are included as a
discontinued operation in our consolidated statements of operations, as part of our REG 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 five-year carryforward for capital losses under existing federal statutes. Please see Note 14Income Taxes beginning on page F-38 for further discussion of our capital loss
carryforwards.



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. In the fourth quarter 2001, we completed the purchase of BGSL, a wholly owned subsidiary of BG Group plc. Under the terms of the purchase agreement, we paid approximately £421 million
(approximately $595 million at November 28, 2001) for BGSL and its assets. The assets consisted primarily of the Hornsea onshore gas storage facility in the United Kingdom, the Rough offshore natural gas fields in the North Sea and the Easington
natural gas processing terminal on the East Yorkshire coast.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



BGSLs results of operations are included as a discontinued operation in our consolidated
statements of operations, as part of our CRM segment, beginning December 1, 2001. A condensed balance sheet as of the acquisition date is as follows ($ in millions):



|                              |  |   |    
|----------------------------- |  | - | ---
|Current assets                |  | $ | 57 
|Property, plant and equipment |  |   | 792
|Goodwill                      |  |   | 9  
|                              |  |   |    
|Total assets acquired         |  |   | 858
|                              |  |   |    
|Current liabilities           |  |   | 56 
|Long-term liabilities         |  |   | 207
|                              |  |   |    
|Total liabilities assumed     |  |   | 263
|                              |  |   |    
|Net assets acquired           |  | $ | 595
|                              |  |   |    



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, thereby completing the disposition of all BGSL-related assets. 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. As previously
reported, 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. As expected, 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, mostly from selling and terminating all 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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##### Table of Contents

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 |    
|                                           |  | (in millions)   |    
|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   | )
|                                           |  |                 |     |   |            
|2001                                       |  |                 |     |   |             |   |         |  |   |               |   |  |       |     |   |  |   |       |  
|Revenue                                    |  | $               |    |   |             | $ | 15      |  | $ | 20            |   |  | $     | 890 |   |  | $ | 925   |  
|Income (loss) from operations before taxes |  |                 |    |   |             |   | 6       |  |   | (31           | ) |  |       | (2  | ) |  |   | (27   | )
|Income (loss) from operations after taxes  |  |                 |    |   |             |   | 4       |  |   | (22           | ) |  |       | (1  | ) |  |   | (19   | )



Dispositions and
Contract Terminations



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 April 2003, we reached an agreement in principle with Southern Power to terminate three power
tolling arrangements among Dynegy, Southern Power and our respective affiliates covering an aggregate of 1,100 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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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) on this sale. We retained the right to receive additional contingent payments based
upon project development milestones; however, in March 2004, we sold our remaining interest in this project. 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).



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 in the 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.



Acquisitions



DNE.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.



Consideration Paid for Acquisitions.Consideration paid for the
2002 and 2001 business acquisitions was as follows:



|                       |  |               |       |      |   |    
|---------------------- |  | ------------- | ----- | ---- | - | ---
|                       |  | NNG           |       | BGSL
|                       |  | (in millions)
|Cash purchase of stock |  | $             | 65    |      | $ | 595
|Liabilities assumed    |  |               | 1,070 |      |   | 263
|                       |  |               |       |      |   |    
|Total consideration    |  | $             | 1,135 |      | $ | 858
|                       |  |               |       |      |   |    



Note 4Restructuring and
Impairment Charges



During 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-27. In addition, 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-28.



In 2002, we recorded a goodwill impairment relating to our GEN and CRM
segments totaling $724 million. For further discussion, please see Note 10Goodwill beginning on page F-29.



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##### Table of Contents

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 ofUnconsolidatedInvestments |  | 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     |  | $ | 61 
|Severance                                  |  |   | 103
|Asset impairments                          |  |   | 15 
|Change in estimated useful lives of assets |  |   | 28 
|                                           |  |   |    
|                                           |  | $ | 207
|                                           |  |   |    



In accordance with
EITF Issue 94-3, we recognized $61 million in charges ($40 million after-tax) associated with cancellation fees and accruals for the termination of operating leases. These accruals are not discounted.



In addition, we recognized charges of $103 million ($67 million after-tax)
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.



Following is a schedule of 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                   |  |               | 103 |   |                                     |   | 61  |       |  |   | 164 |  
|2002 cash payments            |  |               | (40 | ) |                                     |   |    |       |  |   | (40 | )
|                              |  |               |     |   |                                     |   |     |       |  |   |     |  
|Balance at December 31, 2002  |  | $             | 63  |   |                                     | $ | 61  |       |  | $ | 124 |  
|2003 adjustments to liability |  |               | (8  | ) |                                     |   | 3   |       |  |   | (5  | )
|2003 cash payments            |  |               | (35 | ) |                                     |   | (34 | )     |  |   | (69 | )
|                              |  |               |     |   |                                     |   |     |       |  |   |     |  
|Balance at December 31, 2003  |  | $             | 20  |   |                                     | $ | 30  |       |  | $ | 50  |  
|                              |  |               |     |   |                                     |   |     |       |  |   |     |  



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



The adjustment to the accrued liability during 2003 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.



The severance balance at December 31, 2003 primarily relates
to severance that has not been paid to our former Chief Executive Officer, former President and former Chief Financial Officer, each of whom has initiated an arbitration proceeding against us related to this severance. Please read Note
16Commitments and ContingenciesSummary of Material Legal ProceedingsSeverance Arbitrations beginning on page F-45 for further discussion.



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-29 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.



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.



F-21



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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. On January 1, 2001, we recorded the impact
of the adoption of SFAS No. 133 as a cumulative effect adjustment to our consolidated results as follows:



|                                        |  |               |    |   |                          |   |     |  
|--------------------------------------- |  | ------------- | -- | - | ------------------------ | - | --- | -
|                                        |  | NetIncome     |    |   | OtherComprehensiveIncome |  
|                                        |  | (in millions) |   
|Adjustment to fair value of derivatives |  | $             | 3  |   |                          | $ | 105 |  
|Income tax effects                      |  |               | (1 | ) |                          |   | (44 | )
|                                        |  |               |    |   |                          |   |     |  
|Total                                   |  | $             | 2  |   |                          | $ | 61  |  
|                                        |  |               |    |   |                          |   |     |  



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:



| |  | Cash flow hedges. Under these derivatives, the effective portion of changes in fair value is recorded as a component of accumulated other comprehensive 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. Instruments related to our power generation and natural gas liquids businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in
future margin. Interest rate swaps are used to convert the floating interest-rate component of some obligations to fixed rates.



F-22



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



During the years ended December 31, 2003, 2002 and 2001, 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 year ended December 31, 2003, we recorded a charge of less than $1 million related
to the reclassification of earnings in connection with forecasted transactions that were no longer considered probable of occurring. During the years ended December 31, 2002 and 2001, no amounts were reclassified to earnings in connection with
forecasted transactions that were no longer considered probable of occurring.



The balance in cash flow hedging activities, net at December 31, 2003 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity or natural gas
liquids and payments of interest, as applicable to each type of hedge. Of this amount, after-tax gains of approximately $2 million are currently estimated to be reclassified into earnings over the 12-month period ending December 31, 2004. The actual
amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.



Fair value hedges. We also enter into derivative instruments that qualify as fair value hedges. We use
interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into variable-rate debt. During the years ended December 31, 2003, 2002 and 2001, 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 year ended December 31, 2003, we recorded a $6 million gain related to firm commitments that no longer qualified as fair value hedges. During the years ended December 31,
2002 and 2001, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.



Net investment hedges in foreign operations. We have investments in foreign subsidiaries, the net assets of which are exposed to currency
exchange-rate volatility. We have used derivative financial instruments, including foreign exchange forward contracts and cross-currency interest rate swaps, to hedge this exposure. As of December 31, 2003, we had no net investment hedges in place.
For the years ended December 31, 2002 and 2001, approximately zero and $18 million, respectively, of net losses related to these contracts were included in the foreign currency translation adjustment. This amount offsets the cumulative translation
gains of the underlying net investments in foreign subsidiaries for the period the derivative financial instruments were outstanding.



During the year ended December 31, 2003, our efforts to exit the U.K. CRM 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 stockholders equity were recognized in income,
resulting in an after-tax loss of approximately $5 million.



Accumulated other comprehensive loss.Accumulated other comprehensive loss, net of tax, is included in stockholders equity on the consolidated balance sheets as follows:



|                                                 |  |               |    |   |      |   |    |  
|------------------------------------------------ |  | ------------- | -- | - | ---- | - | -- | -
|                                                 |  | December 31,  |   
|                                                 |  | 2003          |    |   | 2002 |  
|                                                 |  | (in millions) |   
|Cash flow hedging activities, net                |  | $             | 10 |   |      | $ | 8  |  
|Foreign currency translation adjustment          |  |               | 26 |   |      |   | 7  |  
|Minimum pension liability                        |  |               | (3 | ) |      |   | (3 | )
|                                                 |  |               |    |   |      |   |    |  
|Accumulated other comprehensive loss, net of tax |  | $             | 33 |   |      | $ | 12 |  
|                                                 |  |               |    |   |      |   |    |  



F-23



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Notional contract amounts. The absolute notional contract amounts associated with the
derivative instruments designated as hedges were as follows:



|                                                                   |  |              |       |      |   |      
|------------------------------------------------------------------ |  | ------------ | ----- | ---- | - | -----
|                                                                   |  | December 31,
|                                                                   |  | 2003         |       | 2002
|Fair Value Hedge Interest Rate Swaps (in Millions of U.S. Dollars) |  | $            | 25    |      | $ | 601  
|Fixed Interest Rate Received on Swaps (Percent)                    |  |              | 5.706 |      |   | 5.616
|Cash Flow Hedge Interest Rate Swaps (in Millions of U.S. Dollars)  |  | $            | 405   |      | $ | 1,566
|Fixed Interest Rate Paid on Swaps (Percent)                        |  |              | 3.448 |      |   | 2.824
|Natural Gas Cash Flow Hedges (Trillion Cubic Feet) (1)             |  |              | 0.073 |      |   |     
|Electricity Cash Flow Hedges (Million Megawatt Hours) (1)          |  |              | 3.651 |      |   |     
|Fuel Oil Cash Flow Hedges (Million Barrels) (1)                    |  |              | 0.825 |      |   |     

---

|(1) | As of December 31, 2002, we had not designated any commodity derivative instruments as cash flow or fair value hedges.
|--- | ----------------------------------------------------------------------------------------------------------------------



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.



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 12Debt beginning on page F-31. The carrying
amounts and fair values of our other financial instruments were:



|                                        |  |                |     |   |           |   |     |                |  |   |           |   |  |   |     |  
|--------------------------------------- |  | -------------- | --- | - | --------- | - | --- | -------------- |  | - | --------- | - |  | - | --- | -
|                                        |  | December 31,   |    
|                                        |  | 2003           |     |   | 2002      |  
|                                        |  | CarryingAmount |     |   | FairValue |   |     | CarryingAmount |  |   | FairValue |  
|                                        |  | (in millions)  |    
|Subordinated Debentures (1)             |  | $              |    |   |           | $ |    |                |  | $ | 200       |   |  | $ | 14  |  
|Fair Value Hedge Interest Rate Swap     |  |                | 3   |   |           |   | 3   |                |  |   | 73        |   |  |   | 73  |  
|Cash Flow Hedge Interest Rate Swap      |  |                | (3  | ) |           |   | (3  | )              |  |   | (16       | ) |  |   | (16 | )
|Interest Rate Risk-Management Contracts |  |                | (4  | ) |           |   | (4  | )              |  |   | (74       | ) |  |   | (74 | )
|Commodity Cash Flow Hedge Contracts     |  |                | 17  |   |           |   | 17  |                |  |   |          |   |  |   |    |  
|Commodity Risk-Management Contracts     |  |                | (86 | ) |           |   | (86 | )              |  |   | (43       | ) |  |   | (43 | )

---

|(1) | At December 31, 2003, these securities were classified as Debt on the consolidated balance sheets. Please read Note 2Accounting PoliciesAccounting Principles
AdoptedSFAS No. 150 beginning on page F-14 and Note 12Debt beginning on page F-31.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



The fair value of our Subordinated Debentures at December 31, 2002 was based on quoted market prices by financial institutions that actively trade these
debt securities. The fair value of interest rate, foreign currency 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.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 6Cash Flow Information



Following are supplemental disclosures of cash flow and non-cash investing and financing information:



|                                                    |  |                         |     |   |      |   |        |      |  |   |      |  
|--------------------------------------------------- |  | ----------------------- | --- | - | ---- | - | ------ | ---- |  | - | ---- | -
|                                                    |  | Year Ended December 31, |    
|                                                    |  | 2003                    |     |   | 2002 |   |        | 2001 | 
|                                                    |  | (in millions)           |    
|Interest paid (net of amount capitalized)           |  | $                       | 180 |   |      | $ | 182    |      |  | $ | 118  |  
|                                                    |  |                         |     |   |      |   |        |      |  |   |      |  
|Taxes paid (net of refunds)                         |  | $                       | (91 | ) |      | $ | 8      |      |  | $ | 87   |  
|                                                    |  |                         |     |   |      |   |        |      |  |   |      |  
|Detail of businesses acquired:                      |  |                         |     |   |      |   |        |      |  |   |      |  
|Current assets and other                            |  | $                       |    |   |      | $ | 144    |      |  | $ | 57   |  
|Fair value of non-current assets                    |  |                         |    |   |      |   | 990    |      |  |   | 801  |  
|Liabilities assumed, including deferred taxes       |  |                         |    |   |      |   | (1,070 | )    |  |   | (263 | )
|Cash balance acquired                               |  |                         |    |   |      |   | (44    | )    |  |   | (14  | )
|                                                    |  |                         |     |   |      |   |        |      |  |   |      |  
|Cash paid, net of cash acquired                     |  | $                       |    |   |      | $ | 20     |      |  | $ | 581  |  
|                                                    |  |                         |     |   |      |   |        |      |  |   |      |  
|Other non-cash investing and financing activity:    |  |                         |     |   |      |   |        |      |  |   |      |  
|Addition of a capital lease                         |  | $                       | 66  |   |      | $ | 170    |      |  | $ |     |  
|Sale of West Texas LPG Pipeline Limited Partnership |  |                         |    |   |      |   | 45     |      |  |   |     |  



The businesses
acquired included: Northern Natural (2002) and BGSL (2001). Please read Note 3Discontinued Operations, Dispositions, Contract Terminations and AcquisitionsDiscontinued Operations beginning on page F-16 for more information regarding
these acquisitions.



Note 7Inventory



A summary of our inventories is as follows:



|                       |  |               |     |      |   |    
|---------------------- |  | ------------- | --- | ---- | - | ---
|                       |  | December 31, 
|                       |  | 2003          |     | 2002
|                       |  | (in millions)
|Natural gas in storage |  | $             | 5   |      | $ |   
|Natural gas liquids    |  |               | 40  |      |   | 46 
|Coal                   |  |               | 48  |      |   | 49 
|Crude oil              |  |               | 16  |      |   | 10 
|Materials and supplies |  |               | 85  |      |   | 79 
|                       |  |               |     |      |   |    
|                       |  | $             | 194 |      | $ | 184
|                       |  |               |     |      |   |    



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 8Property, Plant and Equipment



A summary of our property, plant and equipment is as follows:



|                                       |  |               |        |   |      |   |        |  
|-------------------------------------- |  | ------------- | ------ | - | ---- | - | ------ | -
|                                       |  | December 31,  |       
|                                       |  | 2003          |        |   | 2002 |  
|                                       |  | (in millions) |       
|Generation assets                      |  | $             | 5,725  |   |      | $ | 5,410  |  
|Natural gas liquids assets             |  |               |        |   |      |   |        |  
|Natural gas processing                 |  |               | 1,048  |   |      |   | 992    |  
|Fractionation                          |  |               | 234    |   |      |   | 221    |  
|Liquids marketing                      |  |               | 35     |   |      |   | 33     |  
|Natural gas gathering and transmission |  |               | 160    |   |      |   | 176    |  
|Terminals and storage                  |  |               | 248    |   |      |   | 254    |  
|Barges                                 |  |               | 29     |   |      |   | 29     |  
|Customer risk management assets        |  |               | 4      |   |      |   | 14     |  
|IT systems and other                   |  |               | 208    |   |      |   | 333    |  
|                                       |  |               |        |   |      |   |        |  
|                                       |  |               | 7,691  |   |      |   | 7,462  |  
|Accumulated depreciation               |  |               | (1,389 | ) |      |   | (1,047 | )
|                                       |  |               |        |   |      |   |        |  
|                                       |  | $             | 6,302  |   |      | $ | 6,415  |  
|                                       |  |               |        |   |      |   |        |  



Interest capitalized
related to costs of projects in process of development totaled $11 million, $16 million and $19 million for the years ended December 31, 2003, 2002 and 2001, 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. These investments are accounted for by the equity method of accounting. Our share of net income from these affiliates is reflected in the consolidated statements of operations as earnings (losses) from unconsolidated investments. 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 13Related Party Transactions beginning on page F-36.



A summary of our unconsolidated investments is as follows:



|                                 |  |               |     |      |   |    
|-------------------------------- |  | ------------- | --- | ---- | - | ---
|                                 |  | December 31, 
|                                 |  | 2003          |     | 2002
|                                 |  | (in millions)
|Equity affiliates:               |  |               |     |      |   |    
|GEN investments                  |  | $             | 495 |      | $ | 498
|NGL investments                  |  |               | 82  |      |   | 102
|                                 |  |               |     |      |   |    
|Total unconsolidated investments |  | $             | 577 |      | $ | 600
|                                 |  |               |     |      |   |    



Cash distributions
received from our equity investments during 2003, 2002 and 2001 were $155 million, $77 million and $87 million, respectively. Our investment balances include unamortized purchase price differences of $61 million and $49 million at December 31, 2003
and 2002, 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, 2003 and 2002 totaled $144 million.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



GEN Investments. Generation investments include ownership interests in seven joint
ventures that own fossil fuel electric generation facilities. Our ownership is 50% in the majority of these ventures. Our aggregate net investment of $495 million at December 31, 2003 represents approximately 2,300 MWs of net generating capacity.
Our most significant investment in generating capacity is our interest in West Coast Power, representing approximately 1,200 MWs of net generating capacity in California. Our net investment in West Coast Power totaled approximately $291 million and
$287 million at December 31, 2003 and December 31, 2002, respectively. West Coast Power provided equity earnings of approximately $117 million, $17 million and $162 million in the years ended December 31, 2003, 2002 and 2001, respectively. West
Coast Power earnings for 2003 include a $20 million charge representing our share of a goodwill impairment. West Coast Power 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 earnings related to the CDWR contract, which expires at the end of 2004.



Summarized financial information for West Coast Power, and our equity share thereof was:



|                        |  |               |     |              |   |       |  |              |     |       |   |              |  |   |       |  |   |    
|----------------------- |  | ------------- | --- | ------------ | - | ----- |  | ------------ | --- | ----- | - | ------------ |  | - | ----- |  | - | ---
|                        |  | December 31, 
|                        |  | 2003          |     | 2002         |   | 2001 
|                        |  | Total         |     | Equity Share |   | Total |  | Equity Share |     | Total |   | Equity Share
|                        |  | (in millions)
|Current assets          |  | $             | 257 |              | $ | 129   |  | $            | 255 |       | $ | 128          |  | $ | 401   |  | $ | 201
|Non-current assets      |  |               | 454 |              |   | 227   |  |              | 532 |       |   | 266          |  |   | 659   |  |   | 330
|Current liabilities     |  |               | 55  |              |   | 28    |  |              | 112 |       |   | 56           |  |   | 138   |  |   | 69 
|Non-current liabilities |  |               | 8   |              |   | 4     |  |              | 34  |       |   | 17           |  |   | 269   |  |   | 135
|Revenues                |  |               | 696 |              |   | 348   |  |              | 585 |       |   | 293          |  |   | 1,562 |  |   | 781
|Operating income        |  |               | 231 |              |   | 116   |  |              | 48  |       |   | 24           |  |   | 345   |  |   | 173
|Net income              |  |               | 233 |              |   | 117   |  |              | 34  |       |   | 17           |  |   | 326   |  |   | 162



Because of their significance, West
Coast Powers audited consolidated financial statements are included herein beginning on page F-67.



In the fourth quarter 2003, we evaluated our domestic and international 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.



During the first quarter 2004, we entered into agreements to sell our
interests in Oyster Creek and Michigan Power. Closing of the transactions, which are subject to regulatory approval and other closing conditions, is expected in the second quarter 2004.



On November 22, 2002, a petition was filed in the United States Bankruptcy Court for the District of Minnesota by several
former officers of NRG Energy, the parent company of the partner and operator in two of our joint ventures (including West Coast Power), to put NRG Energy into bankruptcy. This proceeding was settled and the involuntary bankruptcy was dismissed in
early May 2003. NRG Energy and certain of its affiliates subsequently made voluntary Chapter 11 filings in the United States Bankruptcy Court for the Southern District of New York, together with a filing of a plan of reorganization. In July 2003, we
filed proofs of claim against NRG Energy and certain of its affiliates, and the Bankruptcy Court confirmed NRG Energys plan of reorganization in November 2003. According to a press release issued by NRG Energy, it emerged from bankruptcy in
December 2003, although it has yet to address our proofs of claim. We cannot predict with any degree of certainty the effects of this plan or NRG Energys reorganization on the operations of the joint ventures.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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-19.



NGL Investments. At December 31, 2003, 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 13Related Party Transactions beginning on page F-36 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.



Summarized aggregate financial information for unconsolidated
equity investments, exclusive of the West Coast Power information previously disclosed, and our equity share thereof was:



|                        |  |               |       |              |   |       |  |              |       |       |   |              |  |   |       |  |   |    
|----------------------- |  | ------------- | ----- | ------------ | - | ----- |  | ------------ | ----- | ----- | - | ------------ |  | - | ----- |  | - | ---
|                        |  | December 31, 
|                        |  | 2003          |       | 2002         |   | 2001 
|                        |  | Total         |       | Equity Share |   | Total |  | Equity Share |       | Total |   | Equity Share
|                        |  | (in millions)
|Current assets          |  | $             | 218   |              | $ | 92    |  | $            | 429   |       | $ | 154          |  | $ | 445   |  | $ | 163
|Non-current assets      |  |               | 1,210 |              |   | 543   |  |              | 1,195 |       |   | 532          |  |   | 1,246 |  |   | 552
|Current liabilities     |  |               | 153   |              |   | 64    |  |              | 314   |       |   | 127          |  |   | 295   |  |   | 125
|Non-current liabilities |  |               | 528   |              |   | 263   |  |              | 568   |       |   | 284          |  |   | 609   |  |   | 304
|Revenues                |  |               | 1,190 |              |   | 463   |  |              | 2,247 |       |   | 886          |  |   | 1,941 |  |   | 677
|Operating income        |  |               | 176   |              |   | 75    |  |              | 203   |       |   | 82           |  |   | 175   |  |   | 73 
|Net income              |  |               | 120   |              |   | 45    |  |              | 153   |       |   | 56           |  |   | 122   |  |   | 47 



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 and Note 4  Restructuring and Impairment ChargesImpairment of technology investments both beginning on page F-21). Earnings from unconsolidated
investments of $178 million for the year ended December 31, 2001 consist primarily of the $47 million above and $162 million from West Coast Power, offset by a $19 million pre-tax loss on a technology investment due to impairment.



Other Investments. During 2001, we recognized a
$19 million pre-tax loss on a technology investment due to impairments that were determined by management to be other-than-temporary. We 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-19. The market value of these investments at December 31,
2003 and 2002 was estimated to be zero.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 10Goodwill



The changes in the carrying amount of goodwill for each of our reporting units for the years ended December 31, 2003 and
2002 were as follows:



|                                          |  |               |      |   |     |   |    |     |  |   |       |   |  |       |      |   |  |   |      |  
|----------------------------------------- |  | ------------- | ---- | - | --- | - | -- | --- |  | - | ----- | - |  | ----- | ---- | - |  | - | ---- | -
|                                          |  | GEN           |      |   | NGL |   |    | CRM |  |   | Other |   |  | Total |     
|                                          |  | (in millions) |     
|Balances as of January 1, 2002            |  | $             | 376  |   |     | $ | 16 |     |  | $ | 381   |   |  | $     |     |   |  | $ | 773  |  
|Goodwill acquired during the period       |  |               |     |   |     |   |   |     |  |   |      |   |  |       | 887  |   |  |   | 887  |  
|Purchase price adjustments                |  |               |     |   |     |   |   |     |  |   | (33   | ) |  |       | (28  | ) |  |   | (61  | )
|Goodwill impaired during the period       |  |               | (376 | ) |     |   |   |     |  |   | (348  | ) |  |       |     |   |  |   | (724 | )
|Sale of Canadian Crude business           |  |               |     |   |     |   | (1 | )   |  |   |      |   |  |       |     |   |  |   | (1   | )
|Sale of Northern Natural                  |  |               |     |   |     |   |   |     |  |   |      |   |  |       | (859 | ) |  |   | (859 | )
|                                          |  |               |      |   |     |   |    |     |  |   |       |   |  |       |      |   |  |   |      |  
|Balances as of December 31, 2002 and 2003 |  | $             |     |   |     | $ | 15 |     |  | $ |      |   |  | $     |     |   |  | $ | 15   |  
|                                          |  |               |      |   |     |   |    |     |  |   |       |   |  |       |      |   |  |   |      |  



Significant components
of the 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 segments 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 $724 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 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Discontinued Operations, Dispositions, Contract Terminations and AcquisitionsDiscontinued OperationsNorthern Natural beginning on page F-16 for additional
discussion of the sale of Northern Natural.



All charges
related to goodwill during 2003 and 2002 are the same on a pre-tax or an after-tax basis.



The following table shows what our net income would have been in 2001 if goodwill had not been amortized during those periods, compared to the net loss we recorded for 2003 and 2002:



|                                |  |               |      |   |      |   |        |      |  |   |    
|------------------------------- |  | ------------- | ---- | - | ---- | - | ------ | ---- |  | - | ---
|                                |  | 2003          |      |   | 2002 |   |        | 2001
|                                |  | (in millions)
|Reported net income (loss)      |  | $             | (248 | ) |      | $ | (1,246 | )    |  | $ | 425
|Add back: Goodwill amortization |  |               |     |   |      |   |       |      |  |   | 13 
|                                |  |               |      |   |      |   |        |      |  |   |    
|Net income (loss)               |  | $             | (248 | ) |      | $ | (1,246 | )    |  | $ | 438
|                                |  |               |      |   |      |   |        |      |  |   |    



Note 11Refinancing and
Restructuring Transactions



During 2003, we completed a
series of transactions that significantly altered our outstanding debt balances. The following summarizes the most significant of those transactions.



Credit Facility Restructuring.On April 2, 2003, we entered into a $1.66 billion credit facility, consisting of: (i) a $1.1 billion secured
revolving credit facility; (ii) a $200 million secured term loan (Term A Loan); and (iii) a $360 million secured term loan (Term B Loan). The credit facility replaced, and preserved the commitment of each lender under, our
former $900 million and $400 million revolving credit facilities, which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and Dynegys $360 million DGC secured debt, which had a maturity



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



date of December 15, 2005. For further discussion of the credit facility, please see Note 12DebtCredit
Facility beginning on page F-31. We incurred debt issuance costs aggregating approximately $41 million in connection with the new facility. Such amounts have been capitalized and are amortized over the term of the credit facility and term loans.



Refinancing.In August 2003, we consummated a
series of refinancing transactions, which we refer to collectively as the Refinancing. In connection with the Refinancing, we issued $1.45 billion of second priority senior secured notes in a private placement transaction pursuant to Rule 4(2) of
the Securities Act of 1933 and completed a cash tender offer and related consent solicitation pursuant to which we purchased: approximately (i) $282 million in principal amount of our $300 million 8.125% Senior Notes due 2005; (ii) virtually all of
our $150 million 63⁄4% Senior Notes due 2005; and (iii) $177 million in principal amount of our $200 million 7.450% Senior Notes due 2006. We paid approximately $5 million above par value of the notes in connection with this purchase, and we paid
a consent fee in connection with the related consent solicitation to eliminate several of the restrictive covenants and certain other provisions previously contained in the indentures governing these notes.



Also in connection with the Refinancing, Dynegy issued $225 million of
convertible subordinated debentures in a private placement transaction pursuant to Rule 4(2) of the Securities Act of 1933.



The net proceeds from the Refinancing, along with cash on hand, were used to make the $225 million cash payment required under the Series B Exchange, as
described below, and to prepay or repurchase indebtedness including the Term A loan, $165 million of the Term B loan, $609 million of our outstanding senior notes in the tender offer described above and $696 million of debt outstanding under the
Black Thunder secured financing.



The prepayment of the debt
above resulted in accelerated charges during 2003 of approximately $20 million, pre-tax, of unamortized financing costs and the settlement value of the associated interest rate hedge instruments. We incurred debt issuance costs aggregating
approximately $50 million in connection with the Refinancing. Such amounts have been capitalized and are amortized over the term of the notes issued in connection with the Refinancing.



For further discussion of the second priority senior secured notes and the convertible subordinated debentures, please see
Note 12DebtSecond Priority Senior Secured Notes beginning on page F-33 and Note 12DebtDynegy Convertible Subordinated Debentures beginning on page F-35.



Series B Exchange.Also in August 2003, Dynegy restructured the $1.5 billion in Series B Preferred Stock
previously held by a subsidiary of ChevronTexaco. Pursuant to the restructuring, which we refer to as the Series B Exchange, this ChevronTexaco subsidiary exchanged its Series B Preferred Stock for (i) a $225 million cash payment, (ii) $225 million
principal amount of Dynegys Junior Unsecured Subordinated Notes due 2016, which we refer to as the Junior Notes, and (iii) 8 million shares of Dynegys Series C Mandatorily Redeemable Convertible Preferred Stock due 2033 (liquidation
preference of $50 per share), which we refer to as the Series C convertible preferred stock.



For further discussion of the Junior Notes and the Series C convertible preferred stock, please see Note 12DebtDynegy Junior Unsecured Subordinated Notes beginning on page F-35 and Note
12DebtDynegy Series C Convertible Preferred Stock beginning on page F-35.



Follow-on Notes Offering. In October 2003, we consummated a follow-on offering, which we refer to as the follow-on notes offering, of $300 million aggregate principal amount of additional second priority
senior secured notes in a private placement transaction pursuant to Section 4(2) of the Securities Act of 1933. The net proceeds from the follow-on notes offering, along with cash on hand, were utilized to prepay the $194 million outstanding under
our Term B Loan and retire the $170 million capital lease obligation associated with the CoGen Lyondell generation facility. We incurred debt issuance costs aggregating approximately $3 million in connection with the follow-on notes offering. Such
amounts have been capitalized and will be amortized over the term of the notes issued in connection with the follow-on notes offering.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 12Debt



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



|                                                                    |  |                |       |           |   |                |  |           |       |  |   |    
|------------------------------------------------------------------- |  | -------------- | ----- | --------- | - | -------------- |  | --------- | ----- |  | - | ---
|                                                                    |  | December 31,  
|                                                                    |  | 2003           |       | 2002     
|                                                                    |  | CarryingAmount |       | FairValue |   | CarryingAmount |  | FairValue
|                                                                    |  | (in millions) 
|Revolving Credit Facilities                                         |  | $              |      |           | $ |               |  | $         | 128   |  | $ | 128
|Senior Notes, 6.75% due 2005                                        |  |                |      |           |   |               |  |           | 150   |  |   | 54 
|Senior Notes, 8.125% due 2005                                       |  |                | 18    |           |   | 18             |  |           | 300   |  |   | 114
|Senior Notes, 7.45% due 2006                                        |  |                | 22    |           |   | 24             |  |           | 206   |  |   | 70 
|Senior Notes, 6.875% due 2011                                       |  |                | 519   |           |   | 455            |  |           | 522   |  |   | 158
|Senior Notes, 8.75% due 2012                                        |  |                | 500   |           |   | 501            |  |           | 500   |  |   | 170
|Senior Debentures, 7.125% due 2018                                  |  |                | 179   |           |   | 147            |  |           | 190   |  |   | 47 
|Senior Debentures, 7.625% due 2026                                  |  |                | 181   |           |   | 147            |  |           | 198   |  |   | 46 
|Second Priority Senior Secured Notes, floating rate due 2008        |  |                | 225   |           |   | 225            |  |           |      |  |   |   
|Second Priority Senior Secured Notes, 9.875% due 2010               |  |                | 625   |           |   | 705            |  |           |      |  |   |   
|Second Priority Senior Secured Notes, 10.125% due 2013              |  |                | 900   |           |   | 1,035          |  |           |      |  |   |   
|Subordinated Debentures payable to affiliates, 8.316%, due 2027 (1) |  |                | 200   |           |   | 164            |  |           |      |  |   |   
|ABG Gas Supply Credit Agreement, due through 2006                   |  |                | 185   |           |   | 185            |  |           | 259   |  |   | 252
|Generation Facility Debt, due 2007                                  |  |                | 184   |           |   | 184            |  |           | 184   |  |   | 184
|Generation Facility Capital Lease                                   |  |                |      |           |   |               |  |           | 165   |  |   | 165
|Tilton Capital Lease payable to affiliates                          |  |                | 71    |           |   | 71             |  |           |      |  |   |   
|Black Thunder Secured Financing                                     |  |                |      |           |   |               |  |           | 758   |  |   | 758
|Renaissance and Rolling Hills Credit Facility, due 2003             |  |                |      |           |   |               |  |           | 200   |  |   | 200
|                                                                    |  |                |       |           |   |                |  |           |       |  |   |    
|                                                                    |  |                | 3,809 |           |   |                |  |           | 3,760 |  |   |    
|Unamortized premium (discount) on debt, net                         |  |                | 5     |           |   |                |  |           |      |  |   |    
|                                                                    |  |                |       |           |   |                |  |           |       |  |   |    
|                                                                    |  |                | 3,814 |           |   |                |  |           | 3,760 |  |   |    
|Less: Amounts due within one year                                   |  |                | 150   |           |   |                |  |           | 484   |  |   |    
|                                                                    |  |                |       |           |   |                |  |           |       |  |   |    
|Total Long-Term Debt                                                |  | $              | 3,664 |           |   |                |  | $         | 3,276 |  |   |    
|                                                                    |  |                |       |           |   |                |  |           |       |  |   |    

---

|(1) | At December 31, 2002, these securities, which were formerly known as the Company Obligated Preferred Securities of a Subsidiary Trust, were classified as Subordinated Debentures on
the Consolidated Balance Sheets. See Note 2Accounting PoliciesAccounting Principles AdoptedSFAS No. 150 beginning on page F-15.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Our debt maturities for the next five years and thereafter are as follows: 2004 - $150 million; 2005 - $102 million; 2006 - $44 million; 2007 - $184
million; 2008 - $225 million; thereafter - $3,109 million. Included in our 2004 maturities of $150 million is $71 million related to the Tilton capital lease. Please see Tilton Capital Lease beginning on page F-34 for a discussion of the
delivery of our notice of intent to exercise our option to purchase the leased turbines upon the expiration of the lease in September 2004, with respect to which an $81 million payment is due.



Credit Facility. During the year ended December 31, 2003, we
reduced our exposure under our revolving credit facilities by $812 million. During the period from December 31, 2003 through February 23, 2004, our outstanding letters of credit under these revolving credit facilities increased by $34 million.



As discussed in Note 11Refinancing and Restructuring
TransactionsCredit Facility Restructuring beginning on page F-29, on April 2, 2003, we entered into a $1.66 billion credit facility consisting of a $1.1 billion secured revolving credit facility, which matures on February 15, 2005, and two
secured term loans. We repaid the secured term loans using the proceeds from our August and October 2003 debt offerings, together with cash on hand. We currently have no borrowings under the credit facility, with letters of credit issued of $222
million at February 23, 2004.



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



The amended credit facility provides funding for general corporate purposes and is available for the
issuance of letters of credit. Borrowings under the credit facility bear interest, at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. A letter of credit fee is payable on the undrawn amount of each letter of
credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. A 0.15% fronting fee is incurred upon the issuance of letters of credit. An unused commitment fee of 0.50% per annum is payable on the unused portion of the
revolving facility. We incur additional fees for amending existing letters of credit.



We are required to prepay or cash collateralize outstanding borrowings under our amended credit facility with: (i) all net cash proceeds from non-ordinary course asset sales, subject to certain exceptions, subject to
our prior obligation to use a portion of such proceeds to prepay Dynegys outstanding Junior Notes; (ii) half of the net cash proceeds from issuances of equity, subordinated debt or additional second lien debt, except that we may use up to $250
million of equity issuance proceeds to make mandatory prepayments on the Junior Notes, so long as we reduce permanently or cash collateralize the commitments under the revolving credit facility according to a specified formula; (iii) all net cash
proceeds from the issuance of senior debt; and (iv) half of extraordinary receipts (as defined in the amended credit facility).



We are also required to prepay or cash collateralize an amount of such outstanding borrowings calculated according to a specified formula in the event
Dynegy pays cash dividends on its Series C convertible preferred stock or we repurchase our senior notes that mature on or after 2007, provided we have $500 million of liquidity after such payment or repurchase. Dynegy made the first semi-annual
dividend payment on its Series C convertible preferred stock of $11 million on February 11, 2004, as a result of which capacity under our revolving credit facility was reduced by $11 million.



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



| |  | pay cash dividends on Dynegys Series C convertible preferred stock if, among other things, they make a voluntary prepayment of the credit facility and we have $500 million of
liquidity after giving effect to such payment;
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | prepay, repurchase or redeem, with the net cash proceeds of extraordinary receipts or issuances of equity or subordinated debt, or cash on hand, all of our remaining outstanding
2005-2006 senior notes, and, if we have $500 million of liquidity for 10 days prior to and as of the date of such prepayment, the ABG Gas Supply credit agreement and the generation facility debt; and
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | repurchase up to $100 million of our senior notes that mature on or after 2007 so long as we have $500 million of liquidity for 10 days prior to and as of the date of such
repurchase and the credit facility is prepaid in connection with such repurchase according to a formula; provided that up to $300 million of such notes (including any amount repurchased under the foregoing clause) may be repurchased without a
concurrent prepayment under the credit facility with the net cash proceeds of extraordinary receipts or issuances of equity or subordinated debt.
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Under the amended credit facility, Dynegy and its subsidiaries, including us but excluding Illinois Power and DGC, are prohibited from permitting their
Secured Debt/EBITDA ratio (in each case as defined in the amended credit facility) to be greater than 9.0:1.0 for the measurement period ending December 31, 2003, with the ratios decreasing quarterly until the measurement period ending December 31,
2004, at which point the ratio can not exceed 6.7:1.0.



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



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



under the schedules to the amended credit facility; (iii) extraordinary gains or losses; (iv) any impairment,
abandonment, restructuring or similar non-cash expenses; (v) interest expense; (vi) gains/losses on extinguishment of debt; and (vii) turbine cancellation payments up to $50 million in the aggregate.



Amendments to Credit Facility. In July and October 2003, in
conjunction with the Refinancing and the Series B Exchange, we entered into the third and fourth amendments, respectively, to our credit facility to, among other things, permit the consummation of the then-proposed transactions, which included
repaying the Term A Loan and the Term B Loan. The third amendment became effective in August 2003, upon the closing of the Refinancing, and the fourth amendment became effective in October 2003, immediately prior to the closing of the follow-on
notes offering.



Senior Notes.In July 2002, we
repaid our $200 million 6.875% senior notes. In February 2002, we issued $500 million of 8.75% senior notes due 2012. Interest on the notes is due on February 15 and August 15 of each year, beginning August 15, 2002. The notes are unsecured and are
not subject to a sinking fund.



Second Priority Senior
Secured Notes. In connection with the Refinancing, 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 existing credit facility guarantee the
obligations under the notes on a senior secured basis. In addition, Dynegy and its other subsidiaries that guarantee our existing credit facility guarantee the obligations under the notes on a senior secured basis. The notes and guarantees are
senior obligations secured by a second-priority lien on, subject to certain exceptions and permitted liens, all of 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 Dynegy and its 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 our assets; or (7) engage in certain transactions with
affiliates.



Subordinated Debentures. Please see
discussion in Note 15Redeemable Preferred SecuritiesSubordinated Debentures beginning on page F-40.



ABG Gas Supply Credit Agreement.In April 2001, ABG Gas Supply entered into a credit agreement in order to provide financing associated with
Project Alpha. Advances under the agreement allowed ABG Gas Supply to purchase NYMEX natural gas contracts with the underlying physical gas supply to be sold to DMT under an existing natural gas purchase and sale agreement. The credit agreement
requires ABG Gas Supply to repay the advances in monthly installments commencing February 2002 through March 2006 from funds received from DMT under the natural gas purchase and sale agreement. The advances bear interest at a LIBOR rate plus a
margin as defined in the agreement (2.415% and 2.715% at December 31, 2003 and 2002, respectively).



Generation Facility Debt.We previously executed lease arrangements for the purpose of constructing two generation facilities located in
Georgia and Kentucky. As originally constituted, these arrangements require variable-rate interest only payments that include an option to purchase the related assets at maturity of the facility



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



for a balloon payment equal to the principal balance on the financing. In December 2002, we repaid the principal
balance under one of the generation facility lease arrangements. We incurred upfront fees of approximately $6 million in connection with the remaining generation facility lease arrangement which were capitalized and are being amortized over the term
of the arrangement. The remaining generation lease arrangement expires in 2007 and bears interest at LIBOR plus 1.5% to 2.5%, depending on the tranche (2.713% and 2.983% at December 31, 2003 and 2002).



Generation Facility Capital Lease.In June 2002, we
unilaterally undertook certain actions, the effect of which altered the accounting for one of our existing lease obligations. These actions included the delivery of a guarantee of the lessor debt in the lease of our CoGen Lyondell power generation
facility. As a result of these actions, the lease is now accounted for as a capital lease and approximately $165 million of generation assets and the associated debt were consolidated on our balance sheet. We had the option to purchase the related
assets at lease maturity in 2005. This obligation bore interest at a rate of LIBOR plus 1.5% to 2.75%, depending on the tranche. As a part of the Refinancing and the follow-on notes offering, we exercised our option to purchase the related assets
from the lessors and repaid the balance owed on the capital lease. Please read Note 11Refinancing and Restructuring TransactionsRefinancing beginning on page F-30 for further discussion.



Black Thunder Secured Financing.In June 2000, Dynegy and Black
Thunder Investors LLC (Investor) invested in Catlin Associates, L.L.C. (Catlin), an entity that we consolidated, with the Investors ownership in Catlin reflected as minority interest on the consolidated balance sheets.
We invested $100 million in Catlin and the Investor contributed $850 million. As a result of its investment, the Investor received a preferred interest in Catlin, which holds indirect economic interests in some of our Midwest generation assets,
including the coal-fired generation units in Illinois. This preferred interest is a passive interest and generally is not entitled to management rights. Originally, on or before June 29, 2005, we were effectively obligated to purchase the
Investors preferred interest for $850 million unless the Investor agreed to extend or refinance this obligation. Alternatively, we could liquidate Catlins assets, including DMGs generating assets, to satisfy this obligation.



We completed an amendment to this transaction in June 2002
that permanently removed a $270 million obligation that could have been triggered by declines in our credit ratings. As a result of this amendment, $796 million related to Catlin was reclassified from minority interest to debt on our consolidated
balance sheets. We repaid the balance owed on the Black Thunder secured financing as part of the Refinancing. Please read Note 11Refinancing and Restructuring TransactionsRefinancing beginning on page F-30 for further discussion.



Renaissance and Rolling Hills Credit Facility.
In July 2002, we completed a $200 million interim financing, bearing interest at LIBOR plus 1.38%. This loan was scheduled to mature in January 2003 and was secured by interests in our Renaissance and Rolling Hills merchant power generation
facilities. In January 2003, we repaid $94 million of this facility and refinanced the remaining $106 million. The maturity date on the remaining $106 million was extended to October 15, 2003, and the interest rate on the remaining balance was
changed to LIBOR plus 5%. In April 2003, we prepaid the remaining $106 million and recognized a pretax charge of $4 million ($3 million after-tax) related to the acceleration of unamortized financing costs as a result of our prepayment on this
facility.



Interim Financing.In June 2002, we
completed a $250 million interim financing, bearing interest at LIBOR plus 1.75%. This loan was scheduled to mature in June 2003 and represented 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 net 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 therefrom. We incurred upfront fees of approximately $6 million in connection with these interim financings.



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, Illinois Power 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, with respect to which DMG is



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



obligated under the parties sublease to make the purchase option payment, we began accounting for DMGs
lease obligation as a capital lease. Accordingly, we recorded a $66 million increase to property, plant and equipment and a corresponding increase to short-term debt. The recorded amount of $66 million represents the fair market value of the leased
assets at the inception of the capital lease. The difference between the recorded amount and the $81 million purchase price will be accreted over the 12-month term of the capital lease through a charge to interest expense with a corresponding
increase to short-term debt. This obligation was previously disclosed as a residual value guarantee of approximately $70 million in the footnotes to our financial statements and the Contingent Financial Commitments table on page 43 of our 2002 Form
10-K.



Dynegy Convertible Subordinated
Debentures. As described above, in August 2003, Dynegy issued $225 million in 4.75% convertible subordinated debentures due 2023. The debentures are convertible into shares of Dynegys Class A common stock at any time at a conversion
price of $4.1210 per share, subject to specified adjustments for dividend payments and other actions. The debentures are subordinated to Dynegys existing and future senior indebtedness and effectively subordinated to all indebtedness and
liabilities of its non-guarantor subsidiaries. The debentures are guaranteed by us on a senior unsecured basis.



Dynegy Junior Unsecured Subordinated Notes. As described above, in August 2003, Dynegy issued $225 million principal amount of Junior
Unsecured Subordinated Notes due 2016 to CUSA which bear interest at a rate of 9.00% per annum during the first two years and a rate of 13.75% per annum thereafter, in each case, compounded semi-annually and, at Dynegys option, payable in kind
by issuance of additional Junior Notes.



The Junior Notes are
subject to mandatory prepayment during the first two years and until such time as CUSA elects otherwise with: (i) all net cash proceeds from Dynegys qualified capital stock issuances in excess of the first $250 million of such issuances, (ii)
50% of net cash proceeds from issuances of subordinated or convertible debt, mandatorily redeemable preferred stock or convertible equity (excluding refinancings thereof), (iii) 25% of net cash proceeds from asset sales (other than Dynegys
sales of Illinois Power assets or equity), not to exceed an aggregate of $200 million in asset sale proceeds and (iv) 75% of net cash proceeds from Dynegys sale of Illinois Power assets or equity, excluding net cash proceeds used for the
payment of any debt associated with Illinois Power. Please read Note 22Subsequent Event beginning on page F-62 for a discussion of Dynegys pending sale of Illinois Power to Ameren.



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



To the extent any mandatory prepayment is not made due to restrictions contained in Dynegys current or future debt instruments or applicable law,
interest will accrue at the rate of 13.75% on the blocked prepayment amount. The Junior Notes may be prepaid at Dynegys option at par plus accrued interest at any time prior to maturity, provided, however, that the junior noteholders may, at
any time after the date that is 90 days prior to the two-year anniversary of the closing of the Series B Exchange, elect to terminate the mandatory prepayment provisions with such election being effective after expiration of the 90 day period. If
such an election is made, Dynegy will be prohibited from redeeming the Junior Notes through the seven-year anniversary of the Series B Exchange. Following this seven-year anniversary, Dynegy will be entitled to redeem the Junior Notes at par plus
accrued interest plus a premium equal to one-half the coupon, declining ratably to par in year 10.



Dynegy Series C Convertible Preferred Stock. In August 2003, Dynegy issued 8 million shares of its Series C convertible preferred stock to
CUSA. Each share carries a liquidation preference of $50, and the aggregate redemption value is $400 million. Dividends are payable at a rate of 5.5% per annum in cash semi-annually. At its election, Dynegy may defer dividend payments for up to 10
consecutive semi-annual dividend payment periods. Upon termination of any deferral period, all accrued and unpaid amounts are due in cash. Dynegy may not pay dividends on its common stock during any deferral period. Additionally, if Dynegy fails to
obtain shareholder approval within one year for conversion of the Series C convertible preferred stock into shares of its Class B common stock, the dividend rate on the Series C convertible preferred stock will increase to 10% until such time as it
obtains such approval or it is determined that such approval is not required under applicable rules and



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



regulations. Following the receipt of such approval, the shares of Series C convertible preferred stock generally are
convertible, at the option of the holder, at a price of $5.78 per share. The initial holder of the Series C convertible preferred stock may not transfer the shares of the Series C convertible preferred stock (other than to affiliates) until the
earlier of (a) 18 months following the closing of the Series B Exchange or (b) 120 days following the consummation of one or more public or private sales of our qualified capital stock resulting in gross proceeds to us of at least $250 million. On
or after the third anniversary of this lock-up period, Dynegy may cause the Series C convertible preferred stock to be converted into shares of its Class B common stock at any time the closing price of its Class A common stock exceeds
130% of the conversion price then in effect for at least 20 trading days within any period of 30 consecutive trading days prior to such conversion. Upon any conversion of the Series C convertible preferred stock, Dynegy has the right to deliver, in
lieu of shares of its Class B common stock, cash or a combination of cash and shares of its Class B common stock. At any time after the 10th anniversary of the closing of the Series B Exchange, Dynegy may redeem all of the shares of Series C
convertible preferred stock for a redemption price equal to $50 per share plus accrued and unpaid dividends.



Note 13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Discontinued Operations, Dispositions, Contract
Terminations and AcquisitionsDiscontinued OperationsNorthern Natural beginning on page F-16 above. The accelerated payment totaled $176 million at December 31, 2002.



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,
2003, 2002 and 2001, our marketing business recognized net purchases from ChevronTexaco of $0.3 billion, $1.5 billion and $2.7 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, 2003, 2002 and 2001, our other businesses recognized aggregate sales to ChevronTexaco
of $0.9 billion, $0.8 billion and $0.9 billion, respectively, and aggregate purchases of $0.8 billion, $0.5 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, 2003, 2002 and 2001, our portion of the net income from joint
ventures with ChevronTexaco was approximately $10 million, $17 million and $14 million, respectively.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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 ended December 31, 2003, 2002 and 2001, our marketing business recognized net sales to affiliates related to these transactions of $0.7
billion, $1.0 billion and $1.8 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, 2003, 2002 and 2001, our other businesses recognized aggregate sales to these affiliates of $25 million, $15 million and $19 million, respectively, and aggregate purchases of $177 million,
$152 million and $185 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.



Also during 2001, we earned approximately $8 million of interest income related to cash loaned to West Coast Power. The loan was created as a result of
natural gas fuel costs owed by West Coast Power to one of our subsidiaries. As of December 31, 2001, West Coast Power had repaid in full all amounts owed to us.



At December 31, 2002, we had two financing arrangements, which originated during 2001, under which we were owed an aggregate of approximately $12
million from our equity investee, Nicor Energy. Under a gas purchase agreement, Nicor Energy was obligated to purchase a total of 3.5 million MMBtu over the 15-month period October 2001 through December 2002 at a contract price of $18 million.
Approximately $4 million of the $18 million per the agreement was outstanding at December 31, 2002. Additionally, under a loan agreement, which bears interest at a rate of prime plus 2%, we advanced $8.2 million to Nicor Energy to satisfy a
third-party debt, all of which was outstanding at December 31, 2002. All outstanding balances were paid in 2003, and no outstanding balances remained as of December 31, 2003. During the first quarter of 2003, substantially all of the operations of
Nicor Energy were sold and we are in the process of liquidating the company. We anticipate that all amounts due to us from Nicor Energy will be repaid with the proceeds of this liquidation.



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 $2.8 million and $86,000 in an accounts payable, affiliates balance at December 31, 2003 and 2002, respectively.



Additionally, certain of our subsidiaries received revenues of approximately
$569 million, $486 million and $459 million from Illinois Power during the years ended December 31, 2003, 2002 and 2001, respectively. These revenues primarily related to a power purchase agreement that we have with Illinois Power that provides
Illinois Power the right to purchase power from us for a primary term extending through December 31, 2004. The primary term may be extended on an annual basis, subject to concurrence by both parties. The power purchase agreement defines the terms
and conditions under which we provide power and energy to Illinois Power using a tiered pricing structure. The agreement requires Illinois Power to compensate us for capacity charges through 2004 at a total contract cost of $639.6 million. According
to the power purchase agreement, Illinois Power is to provide a security guarantee of $50 million upon a credit downgrade event. This guarantee is being fulfilled by a $50 million guarantee from Dynegy on Illinois Powers behalf. The power
purchase agreement obligates us to provide power up to the reservation amount even if we have individual units unavailable at various times. Please read Note 22Subsequent Event beginning on page F-62 for a discussion of Dynegys pending
sale of Illinois Power to Ameren, and the related power purchase agreement.



These subsidiaries also purchased approximately $9 million, $10 million and $10 million of natural gas from Illinois Power during the years ended December 31, 2003, 2002 and 2001, respectively.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 14Income Taxes



General.We are subject to U.S. federal, foreign and state income taxes on our operations. Components of
income tax benefit (expense) related to income (loss) from continuing operations were:



|                                |  |                         |     |   |      |   |      |  |   |      |  
|------------------------------- |  | ----------------------- | --- | - | ---- | - | ---- |  | - | ---- | -
|                                |  | Year Ended December 31, |    
|                                |  | 2003                    |     |   | 2002 |   | 2001 | 
|                                |  | (in millions)           |    
|Current tax benefit (expense):  |  |                         |     |   |      |   |      |  |   |      |  
|Domestic                        |  | $                       | (3  | ) |      | $ | 218  |  | $ | (168 | )
|Foreign                         |  |                         |    |   |      |   |     |  |   | (9   | )
|Deferred tax benefit (expense): |  |                         |     |   |      |   |      |  |   |      |  
|Domestic                        |  |                         | 179 |   |      |   | 74   |  |   | (144 | )
|Foreign                         |  |                         | 1   |   |      |   | 4    |  |   |     |  
|                                |  |                         |     |   |      |   |      |  |   |      |  
|Income tax benefit (expense)    |  | $                       | 177 |   |      | $ | 296  |  | $ | (321 | )
|                                |  |                         |     |   |      |   |      |  |   |      |  



Components of income
(loss) from continuing operations before income taxes were as follows:



|                                                              |  |                         |      |   |      |   |        |      |  |   |    
|------------------------------------------------------------- |  | ----------------------- | ---- | - | ---- | - | ------ | ---- |  | - | ---
|                                                              |  | Year Ended December 31,
|                                                              |  | 2003                    |      |   | 2002 |   |        | 2001
|                                                              |  | (in millions)          
|Income (loss) from continuing operations before income taxes: |  |                         |      |   |      |   |        |      |  |   |    
|Domestic                                                      |  | $                       | (457 | ) |      | $ | (1,433 | )    |  | $ | 751
|Foreign                                                       |  |                         | 2    |   |      |   | (9     | )    |  |   | 12 
|                                                              |  |                         |      |   |      |   |        |      |  |   |    
|                                                              |  | $                       | (455 | ) |      | $ | (1,442 | )    |  | $ | 763
|                                                              |  |                         |      |   |      |   |        |      |  |   |    



Significant components
of deferred tax liabilities and assets were:



|                                               |  |               |     |   |      |   |     |  
|---------------------------------------------- |  | ------------- | --- | - | ---- | - | --- | -
|                                               |  | December 31,  |    
|                                               |  | 2003          |     |   | 2002 |  
|                                               |  | (in millions) |    
|Deferred tax assets:                           |  |               |     |   |      |   |     |  
|NOL carryforwards                              |  | $             | 564 |   |      | $ | 228 |  
|AMT credit carryfowards                        |  |               | 3   |   |      |   | 14  |  
|Capital loss carryforward                      |  |               |    |   |      |   | 16  |  
|Book/tax differences from liabilities          |  |               | 155 |   |      |   | 175 |  
|Miscellaneous book/tax recognition differences |  |               | 256 |   |      |   | 239 |  
|                                               |  |               |     |   |      |   |     |  
|Subtotal                                       |  |               | 978 |   |      |   | 672 |  
|Less: valuation allowance                      |  |               | (5  | ) |      |   | (5  | )
|                                               |  |               |     |   |      |   |     |  
|Total deferred tax assets                      |  |               | 973 |   |      |   | 667 |  
|                                               |  |               |     |   |      |   |     |  
|Deferred tax liabilities:                      |  |               |     |   |      |   |     |  
|Investments                                    |  |               | 640 |   |      |   | 638 |  
|Depreciation and other property differences    |  |               | 184 |   |      |   | 92  |  
|Miscellaneous book/tax recognition differences |  |               | 43  |   |      |   | 20  |  
|                                               |  |               |     |   |      |   |     |  
|Total deferred tax liabilities                 |  |               | 867 |   |      |   | 750 |  
|                                               |  |               |     |   |      |   |     |  
|Net deferred tax asset (liability)             |  | $             | 106 |   |      | $ | (83 | )
|                                               |  |               |     |   |      |   |     |  



Realization of the
aggregate deferred tax asset is dependent on, among other things, our ability to generate taxable income of the appropriate character in the future. At December 31, 2003 and 2002, all of the valuation allowance relates to foreign tax credit
carryforwards, which management believes is not more likely than not to be fully realized in the future based on our ability to generate foreign income.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Income tax provisions on continuing operations for the years ended December 31, 2003, 2002 and 2001,
were equivalent to effective rates of 39%, 21% and 42%, respectively. Differences between taxes computed at the U.S. federal statutory rate and our reported income tax benefit (expense) were:



|                                          |  |                         |     |      |   |      |      |  |   |      |  
|----------------------------------------- |  | ----------------------- | --- | ---- | - | ---- | ---- |  | - | ---- | -
|                                          |  | Year Ended December 31, |    
|                                          |  | 2003                    |     | 2002 |   |      | 2001 | 
|                                          |  | (in millions)           |    
|Expected tax at U.S. statutory rate (35%) |  | $                       | 159 |      | $ | 505  |      |  | $ | (267 | )
|State taxes                               |  |                         | 12  |      |   | 29   |      |  |   | (17  | )
|Foreign taxes                             |  |                         |    |      |   | 1    |      |  |   | (6   | )
|Valuation allowance                       |  |                         |    |      |   | (5   | )    |  |   |     |  
|Goodwill impairments                      |  |                         |    |      |   | (253 | )    |  |   |     |  
|Basis differentials and other             |  |                         | 6   |      |   | 19   |      |  |   | (31  | )
|                                          |  |                         |     |      |   |      |      |  |   |      |  
|Income tax benefit (expense)              |  | $                       | 177 |      | $ | 296  |      |  | $ | (321 | )
|                                          |  |                         |     |      |   |      |      |  |   |      |  



At December 31, 2003,
we had approximately $1.5 billion of regular federal tax net operating loss carryforwards after considering the effect of carryback to prior years, $3 million of AMT credit carryforwards and $990 million of AMT net operating loss carryforwards. The
federal net operating loss carryforwards expire from 2009 through 2023. The AMT credit carryforwards do not expire. Certain provisions of the Internal Revenue Code place an annual limitation on our ability to utilize tax carryforwards existing as of
the date of a 1995 and a 2000 business acquisition. These limitations are not expected to have a material impact on our overall ability to utilize such tax carryforwards. There was no valuation allowance established at December 31, 2003 for a net
operating loss carryforward, as management believes the net operating loss 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 and future
reversals of existing taxable temporary differences



State net
operating loss carryforwards total $975 million. In states where we file unitary state income tax returns, net operating loss carryforwards are $24 million in New Mexico, $37 million in California and $386 million in Illinois. These state net
operating loss carryforwards will begin to expire in 2007, 2012 and 2015, respectively. State net operating loss carryforwards (in states where we file separate returns) are $8 million in Virginia, $23 million in Texas, $36 million in Michigan, $40
million in both North Carolina and Pennsylvania, $62 million in Georgia, $74 million in Louisiana, $103 million in New York, $111 million in Kentucky and a total of $31 million in various other states. These state net operating loss carryforwards
will begin to expire in Texas in 2007, Michigan and Pennsylvania in 2011, North Carolina in 2015 and in 2022 for the remaining separately listed states. We believe such carryforwards will be fully realized prior to expiration.



Based on 2002 operating results, Dynegy generated a significant current tax
net operating loss that was carried back to reclaim certain U.S. federal income taxes paid in prior years. Accordingly, we received a tax refund in the first quarter of 2003 of approximately $85 million for U.S. federal income taxes paid in 2001 and
2000.



We have disposed of or discontinued the majority of our
foreign operations. We do not have any material undistributed earnings from these foreign operations. 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.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 15Redeemable Preferred Securities



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 DHIs 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 DHIs option, at specified redemption prices. The Subordinated Debentures represent DHIs unsecured obligations and rank subordinate and junior in right of
payment to all of DHIs 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 special purpose entity, FIN No. 46R must be adopted effective
December 31, 2003. The holders of the Trust Securities absorb a majority of the Trusts expected losses. Accordingly, DHIs 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 does 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, 2003 and 2002, 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.



Note 16Commitments and Contingencies



Summary of Material Legal Proceedings



Set forth below is a description of material legal proceedings pending against us and Dynegy. Because Dynegy is a holding company and relies on us for
substantially all of its liquidity and capital resource requirements, adverse outcomes in actions involving Dynegy could similarly impact us. 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.



We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and
the amount of the loss is reasonably estimable under SFAS No. 5, Accounting for Contingencies. For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please see Note
2Accounting Policies beginning on page F-8 for further discussion. 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 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



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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.



Shareholder
Litigation. Dynegy is defending a class action lawsuit filed on behalf of purchasers of its publicly traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit principally asserts
that Dynegy and certain of its current and former officers and directors violated the federal securities laws in connection with its disclosures, including accounting disclosures, regarding Project Alpha (i.e., 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
financial statements for periods since 1999. The Regents of the University of California have been appointed as lead plaintiff and Milberg Weiss is class counsel. Dynegys original motions to dismiss this action have yet to be heard. Recently,
the plaintiff filed an amended complaint which provides further explanation of the allegations in the plaintiffs former complaints. Briefing on the motions to dismiss the amended complaint, and the plaintiffs response to such motions,
will occur from March to June 2004. An adverse result in this action could have a material adverse effect on our financial condition, results of operations and cash flows. Dynegy previously recorded a reserve in connection with this litigation.



In addition, Dynegy is a nominal defendant in several
derivative lawsuits brought on Dynegys behalf by certain of our shareholders 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 and the other pending in state court. Dynegys motion to dismiss the federal derivative claim is currently pending and is set for hearing on March 15, 2004. We do not expect to incur any material
liability with respect to these claims.



ERISA/401(k)
Litigation. Dynegy is defending a purported class action complaint filed in federal district court alleging violations of ERISA in connection with our 401(k) Savings Plan. The lawsuit claims that Dynegys Board and certain of its former
and current officers, past and present members of its 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 putative 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 its financial statements, Project Alpha, round-trip trades and the gas price index investigation. 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. Hearing on this motion is likely to occur in the second quarter of 2004, but no date has been set.



Dynegy is analyzing these claims and has stated that it intends 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 connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of
operations and cash flows.



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



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Emissions at the Baldwin Station have been significantly reduced since the 1999 complaint through
conversion of the Baldwin Station from high to low sulfur coal, resulting in sulfur dioxide emission reductions of over 90% from 1999 levels, and installation of selective catalytic reduction equipment at two of the three Baldwin Station units,
resulting in significant emission reductions of nitrogen oxides. However, the EPA may seek to require the installation of the best available control technology, or the equivalent, at the Baldwin Station, which we estimate could require
us to incur capital expenditures of up to $410 million. The EPA also has the authority to seek penalties for the alleged violations at the rate of up to $27,500 per day for each violation.



In February 2003, the Court granted our motion for partial summary judgment
based on the five-year statute of limitations. As a result, the EPA is not permitted to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Courts ruling also precludes monetary
civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. We believe that we have meritorious defenses against the remaining claims and vigorously defended against them at trial. The trial to
resolve claims of liability began in June 2003 and closing arguments occurred in September 2003. Shortly after closing arguments, several interveners were granted the right to file briefs in support of arguments they believe the United States has
ceased to pursue. The judge indicated at the end of the trial that he intended to issue a liability decision before the end of 2003. However, delays in post-trial briefing and associated with the intervention have postponed the issuance of the
liability order. We have recorded a reserve in an amount we consider reasonable for potential penalties that could be imposed if the Court finds us liable and the EPA prosecutes successfully the remaining claims for penalties.



In August 2003, two significant decisions were handed down in other cases
that are part of the Utility Enforcement Initiative. In United States v. Ohio Edison, the Court found the defendant liable for violations of the Clean Air Act and applied the EPAs narrow interpretation of the routine maintenance,
repair and replacement exclusion, which defines it with respect to what is routine for the specific unit where the projects occurred. In United States v. Duke Energy Company, however, the Court rejected the EPAs narrow
interpretation, holding that the exclusion should be defined relative to what is routine for the particular industry, not what is routine for the particular unit at issue. The Duke case also held that the government bears the burden of proof
on the issue of whether a particular project is routine.



Also
in August 2003, the EPA issued a new rule, the Equipment Replacement Provision of the Routine Maintenance, Repair and Replacement Exclusion, which was scheduled to go into effect in December 2003. Several northeastern states and
environmental groups challenged the new rule by filing an appeal. Prior to its effective date, the Court stayed the effect of the new rule pending a ruling on the appeal. The new rule, if sustained, would provide that the replacement of components
of a process unit with identical components (or their functional equivalents) will fall within the scope of the routine maintenance, repair and replacement exclusion if (i) the replacement cost is less than 20% of the total cost of replacing the
unit, (ii) the replacement does not alter the units basic design and (iii) the unit will continue to comply with applicable emission and operational standards.



None of our other facilities are covered in the complaint and NOV, but the EPA previously requested information, which we
provided, concerning activities at our Vermilion, Wood River, Hennepin, Danskammer and Roseton plants. The EPA could eventually commence enforcement actions based on activities at these plants, although the uncertainty surrounding the new rule makes
it difficult to assess the likelihood of 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. A decision



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on the plaintiffs appeal of that dismissal is not expected before May 2004. Regarding the other six
consolidated cases, we are awaiting a ruling from the Ninth Circuit Court of Appeals on our appeal of a prior decision to remand those cases to state court.



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 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 to enjoin illegal conduct, 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 granted our motion to dismiss eight of these nine actions, although the plaintiffs have appealed.
The ninth case was recently remanded to state court where we are preparing to file a motion to dismiss it.



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. 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
consolidated cases referenced above. Most recently, the Montana Attorney General has filed a case alleging similar antitrust and market manipulation claims, although we have not 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 to 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 July 2001, the FERC initiated a hearing to establish refunds to
electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2000 through June 2001. In particular, the FERC established a methodology to calculate mitigated market clearing prices in the Cal ISO and
the Cal PX markets. In December 2002, an administrative law judge issued his recommendations regarding the appropriate level of refunds or offsets. Those recommendations, however, do not fully reflect proposed refund or offset amounts for individual
companies. In October 2003, the FERC issued two orders addressing various applications for rehearing, including ours, relating to its previous refund orders. The orders addressed numerous requests by the parties, the most significant of which was
the refusal to change the gas pricing methodology and a requirement that the Cal ISO and Cal PX recalculate the refund liability of market participants. The gas price methodology approved by the FERC in March 2003 replaces the gas prices used in the
computation, thus reducing the mitigated market clearing price for power and increasing calculated refunds, subject to a provision that provides full recoverability of actual gas costs paid by the generators to unaffiliated third parties. We do not
expect a final refund calculation prior to August 2004.



Also
in October 2003, DPM and subsidiaries of West Coast Power filed a Petition for Review in federal appeals court, challenging numerous FERC orders relating to our potential refund liability and similar matters arising out of various energy
transactions in California and elsewhere in the western U.S. for the period of May 2000 to June 2001. We are unable to predict when the case will be heard, when a decision will be issued or the affects of the decision on our financial condition,
results of operations and cash flows.



In June 2003, the FERC
issued an order to show cause why the activities of certain participants in the California power markets from January 2000 to June 2001, including us, did not constitute gaming and/or



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anomalous market behavior as defined in the Cal ISO and Cal PX tariffs. In January 2004, we and the FERC staff
submitted a stipulation and settlement agreement to the presiding administrative law judge to settle the issues raised in the June 2003 show cause order. The settlement provides that West Coast Power will pay approximately $3 million, following
final FERC approval into a fund established at the U.S. Treasury for the benefit of California and Western electricity consumers. Under the terms of the proposed settlement, this payment will not constitute an admission of any wrongdoing by West
Coast Power or us. This settlement does not include the pending refund proceedings described above.



Also in June 2003, the FERC issued an order requiring parties to demonstrate that certain bids did not constitute anomalous market behavior. Specifically,
the order requires the FERC staff to investigate all parties who bid above the level of $250/MWH in the Cal ISO and Cal PX markets during the period from May 2000 to October 2000. Parties identified through this process will be required to
demonstrate why this bidding behavior did not violate market protocols. The order also states that, to the extent such practices are not found to be legitimate business behavior, the FERC will require the disgorgement of all unjust profits for that
period and will consider other non-monetary remedies, such as the revocation of market-based rate authority.



West Coast Power recorded a reserve in the fourth quarter 2003 relating to its estimated refund exposure.



Data Requests.In addition to civil litigation and refund
proceedings, we and/or Dynegy are also subject to a number of investigations and inquiries by FERC and others regarding our past trading practices. In 2002 and 2003, the FERC issued data requests to us and numerous other energy companies seeking
information with respect to reporting by these companies of trade data to index publications and whether these companies engaged in physical withholding of power in California and in wash or round-trip trading. We also received a request
for information from the PUCT in June 2002 regarding our trading practices in ERCOT. We have responded timely to all such requests and intend to cooperate fully with these investigations. Nevertheless, we cannot predict with certainty how or when
these investigations will be resolved.



Western Long-Term
Contract Complaints. In February 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the FERC asking that it void or reform power supply contracts between the CDWR and, among
others, DPM. The complaints allege that prices under the contracts exceed just and reasonable prices permitted under the FPA. In June 2003, the FERC ruled that long-term contracts with the CDWR, including DPMs, were valid and would be upheld.
In August 2003, various California parties filed a request for a rehearing on the long-term contract issue with FERC. In November 2003, the FERC denied the applications for rehearing, again upholding the long-term contracts. The complainants have
now appealed the decision to a federal appeals court. The California Public Utilities Commission has also filed a Petition of Review appealing the denial of the application for rehearing at FERC. We are awaiting rulings on all of these filings and
cannot predict their outcome.



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



At December 31, 2003, our portion of the receivables owed to West Coast Power by the Cal ISO and Cal PX approximated $195 million. Management periodically assesses our exposure through West Coast Power, relative to our California
receivables and establishes and maintains reserves under SFAS 5. Our share of the total reserve taken by West Coast Power at December 31, 2003 was approximately $196 million.



Enron Trade Credit Litigation. At December 31, 2002, Enrons net exposure to us, including certain
liquidated damages and other amounts relating to the termination of the transactions, was determined to approximate $84 million and was calculated by setting off approximately $230 million owed from various Dynegy entities to various Enron entities
against approximately $314 million owed from various Enron entities to various Dynegy entities. The master netting agreement between 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



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period, remain subject to dispute by Enron. We are engaged in an ongoing process with Enron to reconcile the
differences between our respective valuations of the various contracts and accounts receivable. As a result of this process, we have reduced the amount owed to us by Enron to approximately $68 million, including the liabilities under the gas
transportation agreement related to the Sithe Independence power tolling arrangement. This reduction from the previous calculation results largely from our own recalculation of the mark-to-market value of certain Canadian power transactions. If the
parties cannot resolve their disputes, the agreement calls for arbitration. In 2002 we instituted arbitration proceedings against those Enron parties not in bankruptcy 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 have responded by opposing our request to enforce the arbitration requirement and filing an adversary proceeding against us, alleging that the master
netting agreement should not be enforced and that the Enron companies should recover approximately $230 million from us. We have disputed such allegations and are vigorously defending our position regarding the setoff rights provided for in the
master netting agreement, although 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. In response, Enron Canada Corp. filed a lawsuit in
Canadian District Court against Dynegy Canada Inc. to recover the amounts that it claims to be owed under the master netting agreement. The lawsuit states that the complainants remedy is 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, to which we responded in January 2004. In February 2004, 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. We intend to appeal this ruling.



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. We cannot predict with certainty whether we will incur any liability in connection with these disputes. However, 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, have each filed
for arbitration pursuant to the terms of their employment/severance agreements. In each case, the parties disagree as to the amounts that may be owed pursuant to their respective agreements. These former officers have made arbitration claims that
seek payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. Their agreements are subject to interpretation and we believe that the amounts owed are substantially lower than the amounts sought. In particular, the
severance agreement with Mr. Bergstrom provides that the amounts identified in the agreement are not due him if material financial restatements have occurred or allegations of wrongdoing are made against him by a state or federal law enforcement
agency. Dynegy has recorded reserves in amounts it considers reasonable and appropriate in the event these arbitrations are decided adversely to Dynegy. These arbitrations are currently scheduled to commence in March 2004 (Bergstrom) and June 2004
(Doty and Watson).



Farnsworth Litigation. In
August 2002, Bradley Farnsworth filed a lawsuit against us 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 alleges, in the words of his amended complaint, that certain of our former executive officers requested that he shave or reduce for accounting purposes the forward price curves associated with the natural gas business in the
United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a reduction in our mark-to-market losses. He also claims that Project Alpha and the round-trip trades provide evidence to support his theory that these
same former executive officers were engaged in a conspiracy to manipulate our financial results and statements. Mr. Farnsworth, who seeks unspecified actual and exemplary damages and other compensation, also alleges that he is entitled to a
termination



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payment under his employment agreement equal to 2.99 times the greater of his average base salary and incentive
compensation for the highest three calendar years preceding termination or his base salary and target bonus amount for the year of termination (currently estimated at a range of approximately $700,000 to $1,200,000). We filed a motion for summary
judgment on all claims in early October 2003, on which we expect a ruling in the first quarter of 2004. Trial, which was scheduled for January 2004, has been rescheduled to October 18, 2004. Although we have recorded a reserve with respect to this
litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.



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 amended petition alleges that Versado
engages in sham transactions with affiliates, resulting in Versado not receiving fair market value when it sells gas and liquids, and 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. In May 2003, we filed a motion for partial summary judgment relating to lost gas
and related matters. The Court granted substantially all of our motions in September 2003. Trial on the remaining claims occurred in January 2004. The jury found in favor of the plaintiff and awarded approximately $1.9 million in damages. Although
DMS recorded a reserve with respect to this litigation, it intends to appeal this decision. DMSs motion to set aside the judgment notwithstanding the verdict will be filed in March 2004. In any case, 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 in some cases several other natural gas marketers, are the subject of a number of lawsuits seeking
damages as the result of alleged false reporting of pricing and volume information regarding natural gas transactions. One such suit is a class action lawsuit filed on behalf of purchasers of natural gas and electricity in the state of California.
We have successfully dismissed this case twice, but plaintiffs were permitted to file another amended complaint in December 2003 in pursuit of their claims. We filed another motion to dismiss in January 2004 and are awaiting a ruling from the court.
The court has ruled expeditiously on the two prior motions.



In
another case, Sierra Pacific Resources and Nevada Power Company filed suit against various sellers of natural gas, including some of our subsidiaries, in federal district court. Plaintiffs claim that they purchased natural gas from us to produce
electricity for their customers at artificially high prices based on published index prices at the California-Arizona border market. Plaintiffs claim that we were part of a conspiracy to restrict natural gas transmission capacity on the El Paso
pipeline system, which in turn raised the California border price. Plaintiffs also claim that we withheld capacity from the market in concert with El Paso and that there was an illicit agreement between the other defendants, El Paso and
us to restrict output and raise prices in violation of the Nevada Unfair Trade Practices Act. Plaintiffs further allege that we conspired with El Paso, in violation of Nevadas Racketeering Influenced Corrupt Organizations Act, to intentionally
misrepresent natural gas prices and volumes to trade publications that compile and report index prices in an effort to fraudulently induce plaintiffs to enter into natural gas purchase contracts and associated hedging transactions at artificially
high prices. Plaintiffs sought an award of unspecified treble damages with respect to these claims based on the alleged excess natural gas costs they incurred. In response to our September 2003 motion to dismiss, the court dismissed the
Plaintiffs claims in their entirety in January 2004.



In
addition to the Sierra Pacific suit, we have been named as defendants in a third-party lawsuit originally initiated by Nelson Brothers, LLC against Cherokee Nitrogen in Alabama state court. The underlying suit relates to an agreement between
Cherokee and Nelson Brothers pursuant to which Cherokee allegedly agreed to supply ammonium nitrate to Nelson Brothers and to use its commercially reasonable efforts to reduce its supply costs. When Nelson Brothers sued Cherokee under their
agreement, Cherokee filed a third-party complaint alleging that it purchased natural gas from DMT based on index pricing and, citing our December 2002 settlement with the CFTC, that the index prices used were artificially inflated by DMT due to
fraudulent and inaccurate reporting to index services, which resulted in higher costs that it passed on to Nelson Brothers. Cherokee claims that DMT is liable to



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it for alleged overcharges and seeks actual and punitive damages in unspecified amounts. Our motion to dismiss this
action on grounds of FERC preemption was denied. We have petitioned the Court for permission to immediately appeal the denial, and are awaiting a ruling on that request.



We also are among some 40 defendants named in a consolidated class action titled In re Natural Gas Commodity
Litigation pending in the United States District Court for the Southern District of New York. This complaint was filed in January 2004 and consolidates at least two former cases in which we were a defendant. The complaint alleges that during the
class period from January 2000 through December 2002, defendants unlawfully manipulated the prices of natural gas futures and options contracts traded on the New York Mercantile Exchange through, among other things, deliberately reporting
inaccurate, misleading and false trading information to industry trade publications that compile and publish indices of natural gas prices. In addition, plaintiff alleges that defendants engaged in a variety of trades, including wash trades, whose
sole purpose was to create the perception of increased liquidity and demand for natural gas. No firm dates regarding this new matter have been established.



Recently, Texas-Ohio Energy, Inc. filed a class action in federal district court, naming several defendants, including Dynegy, Inc. Holding
Co. The complaint alleges that at least 17 defendants and their co-conspirators engaged in wash trades and false reporting to the various gas indices. Plaintiff alleges that defendants made money by manipulating prices to increase margins.
Shortly before the scheduled answer date, this case was transferred via the multi-district litigation process to the United States District Court for the District of Nevada, where at least seven other index manipulation cases are currently pending.
Plaintiffs objection to the transfer is expected shortly and our response to the original complaint is due following the courts resolution of the transfer dispute.



Most recently, in February 2004, Mark and Susan Benscheidt initiated class action litigation on behalf of purchasers of
natural gas in California against 16 defendants, including Dynegy, DMT and DPM. The complaint is similar to the above-described gas index manipulation cases. Plaintiffs also allege that all defendants engaged in wash trades with Enron and with each
other which had no rational economic basis; and agreed not to compete with each other in the pricing and sale of bundled natural gas in California, in the pricing and sale of interstate gas transportation contracts into California in the secondary
(or replacement) market and in the pricing and sale of derivatives known as basis swaps derived from California natural gas market prices. Plaintiffs maintain that all defendants actions constitute violations of the Cartwright Act
and the California Unfair Competition Act. Accordingly, Plaintiffs seek an award of unspecified treble damages with respect to these claims.



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 connection with this lawsuit. We do not believe that any liability that we might incur as a result of this litigation would have a material adverse effect on our financial condition, results
of operations or cash flows.



Triad Litigation.
In March 2003, Triad Energy Resources Corp. and five other alleged representatives of two plaintiffs classes filed a putative antitrust class action against NiSource Inc. and other defendants, including us, in federal district court. The
plaintiffs purport to represent classes of purchasers, marketers, wholesalers, managers, sellers and shippers of natural gas that allegedly were damaged by an illegal gas scheme devised by three federally regulated interstate pipeline systems which
are now owned by NiSource, and certain shippers on these pipelines. It alleges that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate, in violation of FERC regulations,
and in return for percentages of the profits reaped by the marketing affiliate. The complaint also alleges that certain shippers, including us, having learned of the Columbia arrangements, demanded and received similar preferential storage and
transportation services that were not available to all shippers.



Although this alleged scheme was the subject of an October 2000 FERC order, which required the Columbia companies to pay $27.5 million to certain customers of Columbia Gas and Columbia Gulf, plaintiffs claim that the FERC order did not
remedy the competitive injury to plaintiffs caused by the scheme. The complaint seeks aggregate damages of approximately $1.716 billion, which under the federal antitrust laws, damages are subject to trebling. In October 2003, the court granted
defendants motion to dismiss for lack of jurisdiction and allowed time



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for the plaintiffs to amend their complaint. The plaintiffs have since filed a motion to voluntarily dismiss their
complaint and indicated an intent to refile in a proper jurisdiction, although plaintiffs have not yet re-filed. We are analyzing 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 we might incur in connection with this lawsuit.



Atlantigas Corp. Litigation.In November 2003, Atlantigas Corporation filed a suit similar to Triad in Maryland against us and
several other defendants alleging certain conspiracies between natural gas shippers and storage facilities. The complaint seeks unspecified compensatory and punitive damages. In addition, we are alleged to have conspired with the other defendants to
receive preferential natural gas storage and transportation services at off-tariff prices. Defendants are currently challenging plaintiff on the threshold issues of standing, statute of limitations and jurisdiction. These issues will be fully
briefed in February 2004 and are expected to be resolved in the spring of 2004.



We are analyzing 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 we might incur in connection
with this lawsuit.



Maxus Litigation. In April
2001, in the case of Natural Gas Clearinghouse v. Midgard Energy, formerly known as Maxus Exploration Co., the District Court of Potter County, Texas found DMS liable for failing to deliver processable wet gas to a Maxus
processing plant and entered an adverse ruling in DMSs third party action against Transok Inc. for causing it to breach the processing contract. Following our appeal of the judgment, which in May 2003 was upheld in part, we filed an expedited
writ with the Texas Supreme Court seeking further review.We have established a reserve in connection with this matter, although we do not believe that any liability we might incur would have a material adverse effect on our financial
condition, results of operations and cash flows.



Alleged
Marketing Contract Defaults. We have posted collateral to support a substantial portion of our obligations in our customer risk management business, including our obligations under 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 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. Six of our natural gas traders were terminated in October 2002 for violating
our Code of Business Conduct after an ongoing internal investigation conducted by our Audit and Compliance Committee in collaboration with independent counsel discovered that inaccurate information regarding natural gas trades had been reported to
various energy industry publications. In January 2003, one of our former natural gas traders was indicted in Houston on three counts of knowingly causing the transmission of false trade reports used to calculate the index price of natural gas and
four counts of wire fraud. In August 2003, however, several of these counts were dismissed as unconstitutional. 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 appeals are pending and a new trial date has not
been set.



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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 pleaded guilty to conspiracy to commit securities fraud and are scheduled to be sentenced in August 2004. Trial on the indictment against
the third employee was held in November 2003, and the defendant was convicted on all charges and is scheduled to be sentenced in March 2004. We are cooperating fully with the U.S. Attorneys office in its continuing investigation of both of
these matters and cannot predict the ultimate outcome of these investigations.



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



Nicor Energy Investigations. We own a 50% interest in Nicor Energy, a joint venture with Nicor Inc. that marketed retail gas and electricity in the Midwest. During the first quarter 2003, substantially
all of the operations of Nicor Energy were sold, and are in the process of completing the liquidation of the company. We historically provided gas and electricity to Nicor Energy for resale to its retail customers; however, we ceased providing gas
to Nicor Energy in March 2003 in connection with our exit from third-party marketing and trading and ceased providing electricity to Nicor Energy in the second quarter 2003 in connection with its assignment of our wholesale electricity contracts to
the purchasers of its retail electricity business.



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



In December 2003, the SEC filed a civil enforcement action against four
former executives of Nicor Energy, charging the defendants with misstatement of Nicor Energys financial statements and various violations of GAAP. Also in December, a federal grand jury convened by the U.S. Attorney for the Northern District
of Illinois returned criminal indictments against three of the four former executives and a former outside counsel charging conspiracy, securities fraud and wire fraud. All three of the former Nicor employee defendants pled guilty to the criminal
charges and, according to a recent statement by the Department of Justice, are cooperating with the investigation. We intend to cooperate fully with respect to these matters and cannot predict their ultimate outcomes.



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



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, 2003.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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 $2.3 billion at December 31, 2003. This amount includes
the capacity payments on our four remaining tolls as well as a cash obligation under a derivative contract related to the Sithe 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 $507 million as of December 31, 2003.



Additionally, pursuant to our prior capital asset expansion program we entered into purchase orders to acquire at least 14
gas-fired turbines, representing a capital commitment of approximately $479 million. Commitments under these purchase orders are generally payable consistent with the delivery schedule. Approximately 95% are scheduled to be delivered by the end of
2006. The purchase orders include milestone requirements by the manufacturer and provide us with the ability to cancel each discrete purchase order commitment in exchange for a fee, which escalates over time. At December 31, 2003, we could have paid
approximately $48 million to cancel all 14 purchase orders. In February 2004, we terminated our conditional purchase obligation related to these gas fired turbines as part of a comprehensive settlement agreement with the manufacturer. No cash, other
than $11 million previously paid to the manufacturer as a deposit, is expected to be provided as consideration for the termination.



We also have conditional purchase obligations in the amount of $136 million related to our co-sourcing agreement with Accenture Ltd. This 10-year
agreement may be cancelled after two years upon the payment of a termination fee.



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, 2003 was approximately $57 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.



Other Minimum Commitments.Minimum commitments in connection with office space, equipment, plant sites and
other leased assets, including the DNE sale-leaseback transaction discussed in Note 3Discontinued Operations, Dispositions, Contract Terminations and AcquisitionsAcquisitionsDNE beginning on page F-19, at December 31, 2003, were as
follows: 2004$79 million, 2005$79 million; 2006$79 million; 2007$126 million; 2008$145 million and beyond$1.1 billion.



Rental payments made under the terms of these arrangements totaled $78 million in 2003, $90 million in 2002 and $97 million in 2001.



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 2004 through 2008, and approximately $66 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 $66 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/release of the two charter party agreements and a release of our guarantees. Until such time as the novations/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.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Guarantees. As discussed in Note 2Accounting PoliciesAccounting Principles
AdoptedFIN 45 beginning on page F-15, FIN No. 45 requires disclosure of information relating to guarantees issued. These guarantees include letters of credit, indemnities and other forms of guarantees provided by us to third parties.



At December 31, 2003, guarantees included letters of credits
of $186 million and surety bonds totaling $73 million. $33 million of the $73 million in surety bonds were supported by collateral. All of the surety bonds expire in 2004; however, these bonds are generally renewed on a rolling twelve-month basis.



We have indemnified various parties against specific
liabilities that third parties might incur in connection with acquisitions, divestitures and leasing arrangements that we enter into. These indemnities are contingent upon the other party incurring liabilities that are not recoverable from other
third parties and reach a certain threshold.



In connection
with the sale of Northern Natural, the Rough and Hornsea gas storage facilities and certain natural gas liquids assets, we have provided certain indemnities to third parties acquiring the assets. These indemnities relate to environmental, tax,
employee and other representations provided by us. Maximum recourse under such indemnities under the Northern Natural, Rough and Hornsea storage facilities and the natural gas liquids assets total $209 million, £316 million (approximately $564
million at December 31, 2003), £130 million (approximately $232 million at December 31, 2003), and $28 million, respectively.



At December 31, 2003, we do not expect any of the indemnities provided to third parties to have a material impact on our financial statements. However, we
may incur a liability under such indemnity in the future, and it may have a material adverse effect on our financial position, results of operations and cash flows.



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 the amounts of which decrease 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, 2003, 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 $39 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 17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 existing regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these bills or other regulatory developments or
the effects that they might have on our business.



Note 18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.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Stock Options.As further discussed in Note 2Accounting PoliciesEmployee
Stock Options beginning on page F-13, Dynegy has six stock option plans in which our employees participate, all of which contain authorized shares of Dynegys Class A common stock. Dynegy Inc. grants options, from time to time, to certain of
our employees. Each option granted is valued at an option price, which ranges from $0.88 per share to $57.95 per share at date of grant. 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 Dynegy 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.
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | 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 Inc., 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 our option plans cease vesting for employees who are terminated for cause. For voluntary and involuntary termination, disability, retirement or death, all of our option plans cease vesting, with the exception of the Employee Equity
Plan, which contains partial vesting provisions for the events noted above, exclusive of voluntary terminations or retirement. Options awarded to our executive officers and others who participate in our 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 Plan.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Compensation expense related to options granted totaled $3 million, $11 million and $9 million for
the years ended December 31, 2003, 2002 and 2001, respectively. Of the total compensation expense recognized for the year ended December 31, 2001, $1 million related to the extension of the exercise period and acceleration of vesting for various
stock options. No accelerated compensation expense recognition occurred during the year ended December 31, 2003. Total options outstanding and exercisable for 2003, 2002 and 2001 were as follows:



|                                                                           |  |                         |   |      |                              |       |         |        |   |                              |   |         |  |        |                                |  |   |      
|-------------------------------------------------------------------------- |  | ----------------------- | - | ---- | ---------------------------- | ----- | ------- | ------ | - | ---------------------------- | - | ------- |  | ------ | ------------------------------ |  | - | -----
|                                                                           |  | Year Ended December 31,
|                                                                           |  | 2003                    |   | 2002 |                              | 2001 
|                                                                           |  | Options                 |   |      | WeightedAverageExercisePrice |       | Options |        |   | WeightedAverageExercisePrice |   | Options |  |        | Weighted Average ExercisePrice
|                                                                           |  | (options in thousands) 
|Outstanding at beginning of period                                         |  | 26,897                  |   |      | $                            | 20.10 |         | 32,202 |   |                              | $ | 20.72   |  | 19,768 |                                |  | $ | 10.16
|Granted                                                                    |  | 1,583                   |   |      | $                            | 1.78  |         | 2,274  |   |                              | $ | 2.78    |  | 15,172 |                                |  | $ | 33.68
|Exercised                                                                  |  | (1,958                  | ) |      | $                            | 2.88  |         | (2,985 | ) |                              | $ | 2.80    |  | (2,217 | )                              |  | $ | 8.19 
|Cancelled or expired                                                       |  | (10,989                 | ) |      | $                            | 24.03 |         | (4,594 | ) |                              | $ | 26.95   |  | (521   | )                              |  | $ | 27.34
|                                                                           |  |                         |   |      |                              |       |         |        |   |                              |   |         |  |        |                                |  |   |      
|Outstanding at end of period                                               |  | 15,533                  |   |      | $                            | 18.50 |         | 26,897 |   |                              | $ | 20.10   |  | 32,202 |                                |  | $ | 27.34
|                                                                           |  |                         |   |      |                              |       |         |        |   |                              |   |         |  |        |                                |  |   |      
|Exercisable at end of period                                               |  | 11,416                  |   |      | $                            | 21.12 |         | 14,163 |   |                              | $ | 18.08   |  | 11,168 |                                |  | $ | 10.35
|                                                                           |  |                         |   |      |                              |       |         |        |   |                              |   |         |  |        |                                |  |   |      
|Weighted average fair value of options granted during the period at market |  |                         |   |      | $                            | 1.55  |         |        |   |                              | $ | 0.61    |  |        |                                |  | $ | 18.04
|                                                                           |  |                         |   |      |                              |       |         |        |   |                              |   |         |  |        |                                |  |   |      



During the three-year
period ended December 31, 2003, we granted no options at an exercise price less than market price on the date of grant.



Options outstanding as of December 31, 2003 are summarized below:



|                         |  |                                                |  |                                                 |  |                              |       |                                                |        |                                 |   |      
|------------------------ |  | ---------------------------------------------- |  | ----------------------------------------------- |  | ---------------------------- | ----- | ---------------------------------------------- | ------ | ------------------------------- | - | -----
|                         |  | Options Outstanding                            |  | Options Exercisable                            
|Range of Exercise Prices |  | Number ofOptionsOutstanding atDecember 31,2003 |  | WeightedAverageRemainingContractualLife (Years) |  | WeightedAverageExercisePrice |       | Number ofOptionsExercisable atDecember 31,2003 |        | Weighted Average Exercise Price
|                         |  | (options in thousands)                        
|$0.88-$2.15              |  | 3,881                                          |  | 8.3                                             |  | $                            | 1.29  |                                                | 1,118  |                                 | $ | 1.13 
|$2.16-$5.15              |  | 1,653                                          |  | 4.4                                             |  | $                            | 4.19  |                                                | 1,592  |                                 | $ | 4.19 
|$5.16-$11.59             |  | 1,205                                          |  | 4.9                                             |  | $                            | 9.73  |                                                | 1,181  |                                 | $ | 9.77 
|$11.60-$23.98            |  | 5,095                                          |  | 6.8                                             |  | $                            | 20.55 |                                                | 4,492  |                                 | $ | 20.12
|$23.99-$34.77            |  | 1,052                                          |  | 7.7                                             |  | $                            | 34.05 |                                                | 858    |                                 | $ | 34.07
|$34.78-$40.57            |  | 185                                            |  | 7.1                                             |  | $                            | 37.63 |                                                | 153    |                                 | $ | 37.56
|$40.58-$46.36            |  | 95                                             |  | 7.2                                             |  | $                            | 43.95 |                                                | 77     |                                 | $ | 43.87
|$46.37-$52.16            |  | 2,258                                          |  | 7.1                                             |  | $                            | 47.24 |                                                | 1,838  |                                 | $ | 47.24
|$52.17-$57.95            |  | 109                                            |  | 7.1                                             |  | $                            | 56.17 |                                                | 107    |                                 | $ | 56.22
|                         |  |                                                |  |                                                 |  |                              |       |                                                |        |                                 |   |      
|                         |  | 15,533                                         |  |                                                 |  |                              |       |                                                | 11,416 |                                 |   |      
|                         |  |                                                |  |                                                 |  |                              |       |                                                |        |                                 |   |      



Pursuant to terms of
the Illinova acquisition, certain vesting requirements on outstanding options were accelerated and the option shares and strike prices were subject to the exchange ratios applicable in the acquisition.



Note 19Employee Compensation, Savings and Pension Plans



Short-Term Incentive Plan. Our parent maintains a
discretionary incentive 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 Dynegy
Board of Directors.



In addition, in 2003 our parent adopted
the Mid-Term Incentive Performance Award Program. This program is limited to select employees who are eligible to receive cash compensation of up to 200% of their annual base salary, paid in installments over a two-year period, based on the
performance of our Class A common stock during the last 30 trading days in 2004 and stock performance over the entire year in 2005. We account for this cash plan using variable plan accounting, and recognized less than $1 million in compensation
expense during 2003 associated with the plan.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



401(k) Savings Plan. Our employees participate in two 401(k) savings plans, both 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 and
certain expatriates. All employees of certain entities are eligible to participate in the plan. Employee pre-tax contributions to the plan 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. We may also make discretionary contributions to employee accounts, subject to our performance. Matching and discretionary contributions are made in Dynegy common stock. During the years
ended December 31, 2003, 2002 and 2001, Dynegy issued approximately 1.8 million, 2.7 million and 0.3 million shares, respectively, of its common stock to fund the plan. Dynegy discontinued the additional 5% profit sharing contribution to active
employee accounts in 2001. However, in 2001, active employees who normally would have received the profit sharing contribution under the plan began participating in the pension plan described below. No discretionary contributions were made for 2002
or 2003; and
| | - | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  | Dynegy Northeast Generation, Inc. Savings Incentive Plan  this plan, which is for union employees, matches 24% of employee contributions up to 6% of base salary. For non-union
employees, we match 50% of employee contributions up to 8% of base salary. Our guaranteed match is subject to a maximum of 6 or 8% of base pay, subject to IRS limitations. Employees are immediately 100% vested in our contributions. Matching
contributions to this northeast plan are made in cash.
| | - | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Similar plans are available to other employees resident in foreign countries and are subject to the laws of each country. During the years ended December 31, 2003, 2002 and 2001, we recognized aggregate costs related to these employee
compensation plans of $5 million, $10 million and $17 million, respectively.



Pension and Other Post-Retirement Benefits.



We have various defined benefit pension plans and post-retirement benefit plans. We use a December 31 measurement date for all of our plans. Additionally, we participate in several multi-employer pension and other
postretirement benefits plans including the Dynegy Inc. Retirement Plan, the Illinois Power Collectively Bargained Plan and the Illinois Power Retiree Welfare Plans, all sponsored by Dynegy. All domestic employees participate in these pension plans,
but only some of our domestic employees participate in the other post-retirement benefit plans. Dynegy added a cash balance feature effective for 2001 and thereafter with respect to employees who would have otherwise received a profit sharing
contribution under the Dynegy Inc. 401(k) Savings Plan (the contribution credit under such cash balance feature is generally 6% of base pay). During the years ended December 31, 2003, 2002 and 2001, we recognized pension expense (income) for these
plans totaling approximately $12 million, $9 million and $(4) million, respectively. We were not required to make any cash contributions to these plans during 2003, 2002 and 2001. The applicable portions of the plans accrued benefit
liabilities and fair value of plan assets are not recorded on our balance sheets, as the legal rights and obligations associated with these plans rest at the Dynegy level.



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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 |  
|                                                    |  | 2003             |     |   | 2002           |   |     | 2003 |  |   | 2002 |  
|                                                    |  | (in millions)    |    
|Projected benefit obligation, beginning of the year |  | $                | 35  |   |                | $ | 26  |      |  | $ | 10   |   |  | $ | 6   |  
|Service cost                                        |  |                  | 2   |   |                |   | 1   |      |  |   |     |   |  |   |    |  
|Interest cost                                       |  |                  | 2   |   |                |   | 2   |      |  |   | 1    |   |  |   | 1   |  
|Actuarial (gain) loss                               |  |                  | 4   |   |                |   | 6   |      |  |   | 1    |   |  |   | 3   |  
|Benefits paid                                       |  |                  | (1  | ) |                |   |    |      |  |   |     |   |  |   |    |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Projected benefit obligation, end of the year       |  | $                | 42  |   |                | $ | 35  |      |  | $ | 12   |   |  | $ | 10  |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Fair value of plan assets, beginning of the year    |  | $                | 25  |   |                | $ | 26  |      |  | $ |     |   |  | $ |    |  
|Actual return on plan assets                        |  |                  | 5   |   |                |   | (2  | )    |  |   |     |   |  |   |    |  
|Employer contributions                              |  |                  |    |   |                |   | 1   |      |  |   |     |   |  |   |    |  
|Benefits paid                                       |  |                  | (1  | ) |                |   |    |      |  |   |     |   |  |   |    |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Fair value of plan assets, end of the year          |  | $                | 29  |   |                | $ | 25  |      |  | $ |     |   |  | $ |    |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Funded status                                       |  | $                | (13 | ) |                | $ | (10 | )    |  | $ | (12  | ) |  | $ | (10 | )
|Unrecognized actuarial (gain) loss                  |  |                  | 10  |   |                |   | 9   |      |  |   | 4    |   |  |   | 3   |  
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  
|Net amount recognized                               |  | $                | (3  | ) |                | $ | (1  | )    |  | $ | (8   | ) |  | $ | (7  | )
|                                                    |  |                  |     |   |                |   |     |      |  |   |      |   |  |   |     |  



Amounts recognized in
the consolidated balance sheets consist of:



|                                       |  |                  |    |   |                |   |    |      |  |   |      |   |  |   |    |  
|-------------------------------------- |  | ---------------- | -- | - | -------------- | - | -- | ---- |  | - | ---- | - |  | - | -- | -
|                                       |  | Pension Benefits |    |   | Other Benefits |  
|                                       |  | December 31,     |    |   | December 31,   |  
|                                       |  | 2003             |    |   | 2002           |   |    | 2003 |  |   | 2002 |  
|                                       |  | (in millions)    |   
|Accrued benefit liability              |  | $                | (7 | ) |                | $ | (6 | )    |  | $ | (8   | ) |  | $ | (7 | )
|Accumulated other comprehensive income |  |                  | 4  |   |                |   | 5  |      |  |   |     |   |  |   |   |  
|                                       |  |                  |    |   |                |   |    |      |  |   |      |   |  |   |    |  
|Net amount recognized                  |  | $                | (3 | ) |                | $ | (1 | )    |  | $ | (8   | ) |  | $ | (7 | )
|                                       |  |                  |    |   |                |   |    |      |  |   |      |   |  |   |    |  



The accumulated
benefit obligation for all defined benefit pension plans was $34 million and $28 million at December 31, 2003 and 2002, respectively.



On December 31, 2003 and December 31, 2002, 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, 
|                               |  | 2003          |    | 2002
|                               |  | (in millions)
|Projected benefit obligation   |  | $             | 42 |      | $ | 35
|Accumulated benefit obligation |  |               | 34 |      |   | 28
|Fair value of plan assets      |  |               | 29 |      |   | 25



The following
summarizes the change to accumulated other comprehensive loss associated with the minimum pension liability:



|                                                                                                                                   |  |               |   |      |   |    |      |  |   |  
|---------------------------------------------------------------------------------------------------------------------------------- |  | ------------- | - | ---- | - | -- | ---- |  | - | -
|                                                                                                                                   |  | 2003          |   | 2002 |   |    | 2001
|                                                                                                                                   |  | (in millions)
|Change in minimum liability included in other comprehensive income (net of tax benefit of zero, $2 million and zero,
respectively) |  | $             |  |      | $ | (3 | )    |  | $ | 



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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



|                                              |  |                  |    |   |                |   |    |      |  |   |      |   |      |   |      |  |   |   |  |   |  
|--------------------------------------------- |  | ---------------- | -- | - | -------------- | - | -- | ---- |  | - | ---- | - | ---- | - | ---- |  | - | - |  | - | -
|                                              |  | Pension Benefits |    |   | Other Benefits
|                                              |  | 2003             |    |   | 2002           |   |    | 2001 |  |   | 2003 |   | 2002 |   | 2001
|                                              |  | (in millions)   
|Service cost benefits earned during period    |  | $                | 1  |   |                | $ | 1  |      |  | $ | 1    |   |      | $ | 1    |  | $ |  |  | $ | 
|Interest cost on projected benefit obligation |  |                  | 2  |   |                |   | 2  |      |  |   | 2    |   |      |   | 1    |  |   | 1 |  |   | 1
|Expected return on plan assets                |  |                  | (2 | ) |                |   | (3 | )    |  |   | (2   | ) |      |   |     |  |   |  |  |   | 
|Amortization of prior service costs           |  |                  |   |   |                |   |   |      |  |   | (1   | ) |      |   |     |  |   |  |  |   | 
|Recognized net actuarial (gain)/loss          |  |                  | 1  |   |                |   |   |      |  |   |     |   |      |   |     |  |   |  |  |   | 
|                                              |  |                  |    |   |                |   |    |      |  |   |      |   |      |   |      |  |   |   |  |   |  
|Net periodic benefit cost (income)            |  | $                | 2  |   |                | $ |   |      |  | $ |     |   |      | $ | 2    |  | $ | 1 |  | $ | 1
|                                              |  |                  |    |   |                |   |    |      |  |   |      |   |      |   |      |  |   |   |  |   |  



Assumptions.The following weighted average assumptions were used to determine benefit obligations:



|                              |  |                  |   |  |                |   |  |      |   |  |      |  
|----------------------------- |  | ---------------- | - |  | -------------- | - |  | ---- | - |  | ---- | -
|                              |  | Pension Benefits |   |  | Other Benefits |  
|                              |  | December 31,     |   |  | December 31,   |  
|                              |  | 2003             |   |  | 2002           |   |  | 2003 |   |  | 2002 |  
|Discount rate                 |  | 6.00             | % |  | 6.50           | % |  | 6.00 | % |  | 6.50 | %
|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, |  
|                               |  | 2003                    |   |  | 2002                    |   |  | 2001 |   |  | 2003 |   |  | 2002 |   |  | 2001 |  
|Discount rate                  |  | 6.50                    | % |  | 7.50                    | % |  | 7.99 | % |  | 6.50 | % |  | 7.50 | % |  | 8.00 | %
|Expected return on plan assets |  | 9.00                    | % |  | 9.50                    | % |  | 9.67 | % |  | 9.00 | % |  | 9.50 | % |  | 9.50 | %
|Rate of compensation increase  |  | 4.50                    | % |  | 4.50                    | % |  | 4.11 | % |  | 4.50 | % |  | 4.50 | % |  | 4.50 | %



Our expected long-term
rate of return on plan assets for the year ended December 31, 2004 will be 8.75%. 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, |  
|                                                   |  | 2003         |   |  | 2002  |  
|Health care cost trend rate assumed for next year  |  | 11.0         | % |  | 11.50 | %
|Ultimate trend rate                                |  | 5.00         | % |  | 5.00  | %
|Year that the rate reaches the ultimate trend rate |  | 2016         |   |  | 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       |  | $             |  |          | $ |   |  
|Impact on accumulated post-retirement benefit obligation |  | $             | 2 |          | $ | (2 | )



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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 are 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, |  
|                  |  | 2003         |   |  | 2002 |  
|Equity securities |  | 64           | % |  | 59   | %
|Debt securities   |  | 28           | % |  | 30   | %
|Real estate       |  | 5            | % |  | 6    | %
|Other             |  | 3            | % |  | 4    | %
|Cash              |  |             |   |  | 1    | %
|                  |  |              |   |  |      |  
|Total             |  | 100          | % |  | 100  | %
|                  |  |              |   |  |      |  



Equity securities did
not include any Dynegy common stock at December 31, 2003 or 2002.



Our other postretirement benefit plans weighted-average asset allocations by asset category were as follows:



|                  |  |              |   |  |      |  
|----------------- |  | ------------ | - |  | ---- | -
|                  |  | December 31, |  
|                  |  | 2003         |   |  | 2002 |  
|Equity securities |  | 75           | % |  | 74   | %
|Debt securities   |  | 25           | % |  | 26   | %
|                  |  |              |   |  |      |  
|Total             |  | 100          | % |  | 100  | %
|                  |  |              |   |  |      |  



Equity securities did
not include any Dynegy common stock at December 31, 2003 or 2002.



Contributions. We expect to contribute $1 million to our pension plans in 2004.



Note 20Segment Information



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 four former reporting segments prior to January 1, 2003. Beginning January 1, 2003, all direct general and administrative expenses 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. Other income (expense) items incurred by us on behalf of our subsidiaries are allocated
directly to the four segments.



Prior to January 1, 2003, the
GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business, then referred to as the WEN segment. Most, but not all, of the WEN third-party purchase and sale contracts were held by a
subsidiary which is currently included within the CRM



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



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 years ended December 31, 2002 and 2001 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 years ended December 31, 2002 and 2001 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 continues to transact with third parties on behalf of GEN for contracts which were identified as GEN contracts, as well as new transactions
executed on behalf of GEN but for which CRM is the legal party to the third-party purchase and sale contract. CRM continues to record net unaffiliated revenue from these third-party contracts, together with all of its other third-party marketing and
trading positions unrelated to the GEN segment. However, rather than purchasing such capacity, forward sales and related trading positions from GEN at an internally determined transfer price, pricing between CRM and GEN is set at the actual amount
received or paid for the purchases and sales to the third parties. Therefore, GEN intersegment revenues for the year ended December 31, 2003 include the effects of intra-month market price volatility and represent amounts actually received from or
paid to third parties.



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, 2003, 2002 and 2001.



Revenues from third-party sales in which GEN is the legal party to the third-party sales contracts are presented gross in GEN unaffiliated revenues for
the years ended December 31, 2003, 2002 and 2001.



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 2002 prior to its 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, 2003, 2002 and 2001 is presented below.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Dynegy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                                                 |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 177    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Loss from continuing operations                                    |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (278   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Loss on discontinued operations, net of taxes                      |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (12    | )
|Cumulative effect of change in accounting principles, net of taxes |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 42     |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Net loss                                                           |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  | $ | (248   | )
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Identifiable assets:                                               |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                           |  | $   | 6,145 |   |     | $ | 1,422 |     |  | $ | 2,631                 |   |  | $     | (241 | ) |  | $ | 9,957  |  
|Other                                                              |  |     |      |   |     |   | 1     |     |  |   | 291                   |   |  |       | 31   |   |  |   | 323    |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total                                                              |  | $   | 6,145 |   |     | $ | 1,423 |     |  | $ | 2,922                 |   |  | $     | (210 | ) |  | $ | 10,280 |  
|                                                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Unconsolidated investments                                         |  | $   | 495   |   |     | $ | 82    |     |  | $ |                      |   |  | $     |     |   |  | $ | 577    |  
|                                                                   |  |     |       |   |    
|Capital expenditures and investments in unconsolidated affiliates  |  | $   | (151  | ) |     | $ | (51   | )   |  | $ | (2                    | ) |  | $     | (5   | ) |  | $ | (209   | )



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Dynegys Segment Data for the Year Ended December 31, 2002

(in millions)



|                                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|----------------------------------------------------------------- |  | --- | ----- | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ------ | -
|                                                                  |  | GEN |       |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |     
|Unaffiliated revenues:                                            |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                          |  | $   | 379   |   |     | $ | 2,530 |     |  | $ | 308                   |   |  | $     |     |   |  | $ | 3,217  |  
|Other                                                             |  |     |      |   |     |   | 723   |     |  |   | (181                  | ) |  |       |     |   |  |   | 542    |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|                                                                  |  |     | 379   |   |     |   | 3,253 |     |  |   | 127                   |   |  |       |     |   |  |   | 3,759  |  
|Affiliate revenues                                                |  |     | 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                                               |  |     | (376  | ) |     |   |      |     |  |   | (348                  | ) |  |       |     |   |  |   | (724   | )
|Impairment and other charges                                      |  |     | (71   | ) |     |   | (18   | )   |  |   | (95                   | ) |  |       |     |   |  |   | (184   | )
|                                                                  |  |     |       |   |    
|Operating income (loss)                                           |  | $   | (232  | ) |     | $ | 77    |     |  | $ | (974                  | ) |  | $     |     |   |  | $ | (1,129 | )
|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                      |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (1,442 | )
|Income tax benefit                                                |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 296    |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Loss from continuing operations                                   |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (1,146 | )
|Loss on discontinued operations, net of taxes                     |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (100   | )
|                                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Net loss                                                          |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  | $ | (1,246 | )
|                                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Identifiable assets:                                              |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                          |  | $   | 6,151 |   |     | $ | 2,088 |     |  | $ | 6,309                 |   |  | $     |     |   |  | $ | 14,548 |  
|Other                                                             |  |     | 281   |   |     |   | 5     |     |  |   | 2,012                 |   |  |       |     |   |  |   | 2,298  |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total                                                             |  | $   | 6,432 |   |     | $ | 2,093 |     |  | $ | 8,321                 |   |  | $     |     |   |  | $ | 16,846 |  
|                                                                  |  |     |       |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Unconsolidated investments                                        |  | $   | 498   |   |     | $ | 102   |     |  | $ |                      |   |  | $     |     |   |  | $ | 600    |  
|                                                                  |  |     |       |   |    
|Capital expenditures and investments in unconsolidated affiliates |  | $   | (616  | ) |     | $ | (105  | )   |  | $ | (14                   | ) |  | $     | (11  | ) |  | $ | (746   | )



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##### Table of Contents

DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Dynegys Segment Data for the Year Ended December 31, 2001

(in millions)



|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|------------------------------------------------------------------ |  | --- | ------ | - | --- | - | ----- | --- |  | - | --------------------- | - |  | ----- | ---- | - |  | - | ------ | -
|                                                                   |  | GEN |        |   | NGL |   |       | CRM |  |   | Other andEliminations |   |  | Total |     
|Unaffiliated revenues:                                             |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                           |  | $   | 290    |   |     | $ | 3,910 |     |  | $ | 2,072                 |   |  | $     |     |   |  | $ | 6,272  |  
|Other                                                              |  |     |       |   |     |   | 1,463 |     |  |   | (405                  | ) |  |       |     |   |  |   | 1,058  |  
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|                                                                   |  |     | 290    |   |     |   | 5,373 |     |  |   | 1,667                 |   |  |       |     |   |  |   | 7,330  |  
|Affiliate revenues                                                 |  |     | 459    |   |     |   |      |     |  |   |                      |   |  |       |     |   |  |   | 459    |  
|Intersegment revenues                                              |  |     | 792    |   |     |   | 264   |     |  |   | (842                  | ) |  |       | (214 | ) |  |   |       |  
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total revenues                                                     |  | $   | 1,541  |   |     | $ | 5,637 |     |  | $ | 825                   |   |  | $     | (214 | ) |  | $ | 7,789  |  
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Depreciation and amortization                                      |  | $   | (177   | ) |     | $ | (84   | )   |  | $ | (35                   | ) |  | $     |     |   |  | $ | (296   | )
|                                                                   |  |     |        |   |    
|Operating income                                                   |  | $   | 377    |   |     | $ | 133   |     |  | $ | 264                   |   |  | $     |     |   |  | $ | 774    |  
|Earnings (losses) from unconsolidated investments                  |  |     | 189    |   |     |   | 13    |     |  |   | (24                   | ) |  |       |     |   |  |   | 178    |  
|Other items, net                                                   |  |     | 5      |   |     |   | (3    | )   |  |   | (54                   | ) |  |       |     |   |  |   | (52    | )
|Interest expense                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (137   | )
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Income from continuing operations before taxes                     |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 763    |  
|Income tax expense                                                 |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (321   | )
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Income from continuing operations                                  |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 442    |  
|Loss on discontinued operations, net of taxes                      |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | (19    | )
|Cumulative effect of change in accounting principles, net of taxes |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   | 2      |  
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Net income                                                         |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  | $ | 425    |  
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Identifiable assets:                                               |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Domestic                                                           |  | $   | 7,638  |   |     | $ | 2,308 |     |  | $ | 6,910                 |   |  | $     |     |   |  | $ | 16,856 |  
|Other                                                              |  |     | (53    | ) |     |   | 130   |     |  |   | 2,745                 |   |  |       |     |   |  |   | 2,822  |  
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Total                                                              |  | $   | 7,585  |   |     | $ | 2,438 |     |  | $ | 9,655                 |   |  | $     |     |   |  | $ | 19,678 |  
|                                                                   |  |     |        |   |     |   |       |     |  |   |                       |   |  |       |      |   |  |   |        |  
|Unconsolidated investments                                         |  | $   | 334    |   |     | $ | 422   |     |  | $ | 47                    |   |  | $     |     |   |  | $ | 803    |  
|                                                                   |  |     |        |   |    
|Capital expenditures and investments in unconsolidated affiliates  |  | $   | (1,323 | ) |     | $ | (391  | )   |  | $ | (305                  | ) |  | $     |     |   |  | $ | (2,019 | )



Note 21Quarterly Financial
Information (Unaudited)



The following is a summary of our
unaudited quarterly financial information for the years ended December 31, 2003 and 2002:



|                                                                              |  |                                      |       |          |   |      |               |  |   |              |   |  |   |       |  
|----------------------------------------------------------------------------- |  | ------------------------------------ | ----- | -------- | - | ---- | ------------- |  | - | ------------ | - |  | - | ----- | -
|                                                                              |  | Quarter Ended                        |      
|                                                                              |  | March2003                            |       | June2003 |   |      | 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          | ) |  |   | (72   | )
|Net income (loss)                                                             |  |                                      | 133   |          |   | (280 | )             |  |   | (14          | ) |  |   | (87   | )



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



|                                                                              |  |                                      |       |          |   |       |               |  |   |              |   |  |   |      |  
|----------------------------------------------------------------------------- |  | ------------------------------------ | ----- | -------- | - | ----- | ------------- |  | - | ------------ | - |  | - | ---- | -
|                                                                              |  | Quarter Ended                        |      
|                                                                              |  | March2002                            |       | June2002 |   |       | September2002 |  |   | December2002 |  
|                                                                              |  | (in millions, except per share data) |      
|Revenues                                                                      |  | $                                    | 1,189 |          | $ | 1,102 |               |  | $ | 1,018        |   |  | $ | 936  |  
|Operating income (loss)                                                       |  |                                      | 41    |          |   | (204  | )             |  |   | (789         | ) |  |   | (177 | )
|Net income (loss) before cumulative effect of change in accounting principles |  |                                      | 16    |          |   | (132  | )             |  |   | (923         | ) |  |   | (207 | )
|Net income (loss)                                                             |  |                                      | 16    |          |   | (132  | )             |  |   | (923         | ) |  |   | (207 | )



Note 22Subsequent Event



In February 2004, Dynegy entered into a purchase
agreement to sell all of the outstanding common and preferred shares of Illinois Power, which currently comprises Dynegys regulated energy delivery segment, owned by Illinova and its 20% interest in the Joppa power generation facility to
Ameren for $2.3 billion. By acquiring Illinois Power, Ameren will also effectively assume Illinois Powers debt and preferred stock obligations, estimated to approximate $1.8 billion at closing. Ameren will also pay Dynegy:



| |  | approximately $400 million of cash to be received at closing, subject to working capital adjustments; and
| | - | ---------------------------------------------------------------------------------------------------------



| |  | $100 million of cash to be placed in an escrow account and to be released to Dynegy on the sooner of December 31, 2010, the date on which our senior unsecured debt achieves an
investment grade rating from Standard & Poors or Moodys Investor Services, Inc. or the occurrence of specified events relating to contingent environmental liabilities associated with Illinois Powers former generating
facilities. During the time that funds remain in escrow, Dynegy is to receive quarterly payments equivalent to the net income and gain earned on such funds.
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



In addition, Illinois Powers $2.3 billion intercompany note receivable, which was established in connection with
Illinois Powers transfer of its generation facilities prior to Dynegys merger with Illinova in 2000, will be eliminated in conjunction with the closing of the transaction.



The consummation of the sale, which is scheduled to be completed by the end of 2004, is conditioned on, among other things,
the elimination of the intercompany note receivable and the receipt of all regulatory and other consents and approvals as specified in the purchase agreement, including approvals from the ICC, the FERC, the SEC and other governmental and regulatory
agencies. Under our financing agreements, Dynegy is required, upon the closing of the sale, to use 75% of the net cash proceeds from the sale to repay its Junior Notes and 25% of such proceeds to reduce permanently or cash collateralize the
commitments under our $1.1 billion revolving credit facility, subject to certain exceptions, to the extent the Junior Notes are repaid up to $100 million. If no Junior Notes are outstanding, Dynegy is required to use all of the net cash proceeds
from the sale, subject to certain exceptions, to reduce the commitments under our revolver.



In a related agreement that is conditioned upon the closing of the transaction, we have contracted to sell 2,800 MWs of generating capacity and up to 11.5 million MWh of energy to Illinois Power at fixed prices for
two years beginning in January 2005. 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 with an option to purchase energy at market-based prices. The capacity, which is expected to
be provided by our midwest generating facilities will be used by Illinois Power to meet its customer demand. It is anticipated that this arrangement will be in place concurrently with the termination of our existing power purchase agreement with
Illinois Power and the closing of the transaction.



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



Note 23Liquidity



For the next 12 months, assuming continuation of the current commodity pricing environment, we expect that our operating
cash flows will be insufficient to satisfy our capital expenditures, debt maturities, increased interest expenses and operating commitments. When combined with our cash on hand, proceeds from anticipated asset sales and capacity under our $1.1
billion revolving credit facility, however, we believe we have sufficient capital resources to discharge these obligations during this period. To further our deleveraging efforts, we also intend to explore other capital-raising activities with
Dynegy, including potential public or private equity issuances by Dynegy. In addition, we will seek to renew or replace our $1.1 billion revolving credit facility, which is scheduled to mature on February 15, 2005. Our liquidity position will be
materially adversely affected if we are unable to renew or replace this facility, with respect to which our ability to borrow and/or issue letters of credit could become increasingly important, on or before its scheduled maturity.



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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.                                                                                                                                                                                                                                              
|BGSL    |  | BG Storage Limited.                                                                                                                                                                                                                                                      
|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.                                                                                                                                                                                                                                    
|CRM     |  | Our customer risk management business segment.                                                                                                                                                                                                                           
|CUSA    |  | Chevron U.S.A. Inc., a wholly-owned subsidiary of ChevronTexaco.                                                                                                                                                                                                         
|DGC     |  | Dynegy Global Communications.                                                                                                                                                                                                                                            
|DMG     |  | Dynegy Midwest Generation, Inc.                                                                                                                                                                                                                                          
|DMS     |  | Dynegy Midstream Services.                                                                                                                                                                                                                                               
|DMT     |  | Dynegy Marketing and Trade.                                                                                                                                                                                                                                              
|DNE     |  | Dynegy Northeast Generation.                                                                                                                                                                                                                                             
|DPM     |  | Dynegy Power Marketing Inc.                                                                                                                                                                                                                                              
|EBIT    |  | A non-GAAP measure of Earnings Before Interest and Taxes. As an indicator of our segment operating performance, EBIT should not be considered an alternative to, or more meaningful than, net
income or cash flows from operations as determined in accordance with GAAP.
|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.                                                                                                                                                                                                                                             
|KWH     |  | Kilowatt hour.                                                                                                                                                                                                                                                           
|LNG     |  | Liquefied natural gas.                                                                                                                                                                                                                                                   
|LPG     |  | Liquefied petroleum gas.                                                                                                                                                                                                                                                 
|MBbls/d |  | Thousands of barrels per day.                                                                                                                                                                                                                                            
|Mcf     |  | Thousand cubic feet.                                                                                                                                                                                                                                                     
|MMBtu   |  | Millions of British thermal units.                                                                                                                                                                                                                                       
|MMCFD   |  | Million cubic feet per day.                                                                                                                                                                                                                                              
|MW      |  | Megawatts.                                                                                                                                                                                                                                                               



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DYNEGY HOLDINGS INC.



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS(Continued)



|      |  |                                                                                   
|----- |  | ----------------------------------------------------------------------------------
|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.                              
|NOV   |  | Notice of Violation issued by the EPA.                                            
|NYDEC |  | New York Department of Environmental Conservation.                                
|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.                   
|RTO   |  | Regional Transmission Organization.                                               
|SEC   |  | U.S. Securities and Exchange Commission.                                          
|SFAS  |  | Statement of Financial Accounting Standards.                                      
|T&D   |  | Our former transmission and distribution energy delivery business segment.        
|VaR   |  | Value at Risk.                                                                    
|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, 2003, 2002 and 2001



|                                             |  |                              |     |                             |   |     |                         |  |   |            |   |  |                          |      |   |  |   |    
|-------------------------------------------- |  | ---------------------------- | --- | --------------------------- | - | --- | ----------------------- |  | - | ---------- | - |  | ------------------------ | ---- | - |  | - | ---
|                                             |  | Balance atBeginning ofPeriod |     | Charged toCosts andExpenses |   |     | Charged toOtherAccounts |  |   | Deductions |   |  | Balance at End of Period
|                                             |  | (in millions)               
|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 (3)   |  |                              | 5   |                             |   |    |                         |  |   |           |   |  |                          |     |   |  |   | 5  
|                                             |  |                              |     |                             |  
|2002                                         |  |                              |     |                             |   |     |                         |  |   |            |   |  |                          |      |   |  |   |    
|Allowance for doubtful accounts              |  |                              | 108 |                             |   | 40  |                         |  |   | (2         | ) |  |                          | (6   | ) |  |   | 140
|Allowance for risk management assets (1)     |  |                              | 248 |                             |   | (4  | )                       |  |   |           |   |  |                          |     |   |  |   | 244
|Deferred tax asset valuation allowance       |  |                              |    |                             |   | 5   |                         |  |   |           |   |  |                          |     |   |  |   | 5  
|                                             |  |                              |     |                             |  
|2001                                         |  |                              |     |                             |   |     |                         |  |   |            |   |  |                          |      |   |  |   |    
|Allowance for doubtful accounts              |  |                              | 63  |                             |   | 93  |                         |  |   | (2         | ) |  |                          | (46  | ) |  |   | 108
|Allowance for risk management assets (1)     |  |                              | 146 |                             |   | 102 |                         |  |   |           |   |  |                          |     |   |  |   | 248

---

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

|(3) | Decrease in our deferred tax asset valuation relates to our release of a deferred tax capital gains valuation allowance.
|--- | ------------------------------------------------------------------------------------------------------------------------



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West Coast Power LLC Consolidated Financial Statements

Index

December 31, 2003 and 2002

---



|                                                                    |  |     
|------------------------------------------------------------------- |  | ----
|                                                                    | 
|                                                                    |  | Page
|                                                                    | 
|Report of Independent Auditors                                      |  | F-68
|                                                                    | 
|Consolidated Financial Statements                                   |  |     
|                                                                    | 
|Consolidated Balance Sheets                                         |  | F-71
|                                                                    | 
|Consolidated Statements of Operations                               |  | F-72
|                                                                    | 
|Consolidated Statements of Members Equity and Comprehensive Income |  | F-73
|                                                                    | 
|Consolidated Statements of Cash Flows                               |  | F-74
|                                                                    | 
|Notes to Consolidated Financial Statements                          |  | F-75



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##### Table of Contents

Report of Independent Auditors



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, 2003 and 2002, and the results of their operations and their cash flows for the years then ended 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 auditing standards generally accepted in the United States of America, which 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. The consolidated financial statements of the Company as of December 31, 2001 and for the year then ended,
were audited by other independent public accountants who have ceased operations. Those independent public accountants expressed an unqualified opinion on those financial statements in their report dated February 28, 2002 (except with respect to a
matter discussed in Note 9 of said financial statements, as to which the date is March 11, 2002).



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 Standard 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.





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As discussed above, the consolidated financial statements of the Company as of December 31, 2001, were audited by other
independent public accountants who have ceased operations. As described in Note 2, these consolidated financial statements have been revised to include the transitional disclosures required by Statement of Financial Accounting Standards No. 142
which was adopted by the Company as of January 1, 2002. We audited the transitional disclosures described in Note 2. In our opinion, the transitional disclosures for 2001 in Note 2 are appropriate. However, we were not engaged to audit, review or
apply any procedures to the 2001 consolidated financial statements of the Company other than with respect to such disclosures and accordingly, we do not express an opinion or any other form of assurance on the 2001 consolidated financial statements
taken as a whole.



/s/ PricewaterhouseCoopers
LLP

Houston, Texas

March 4, 2004





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Note: This is a copy of a report issued by Arthur Andersen LLP, our former independent public accountants. This report
has not been reissued by Arthur Andersen LLP in connection with West Coast Power LLCs financial statements for the year ended December 31, 2003. West Coast Power LLCs consolidated balance sheets as of December 31, 2001 and 2000, and
consolidated statements of operations, consolidated members equity and comprehensive income and consolidated cash flows for the years ended December 31, 2000 and 1999, are not required to be presented and are not included in these financial
statements. Additionally, the consolidating information for 2001 referred to below as being presented in Note 10 is not required to be presented and is not included in these financial statements.



Report of Independent Accountants



To the Member of

West Coast Power LLC



We have audited the accompanying consolidated balance sheets of West Coast Power LLC (a Delaware limited liability company) as of December 31, 2001 and 2000, and the
related consolidated statements of operations, member equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2001. 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 in accordance with auditing standards generally accepted in the 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. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.



In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of West Coast
Power LLC as of December 31, 2001 and 2000, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States.



Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The 2001 consolidating information in Note 10 is presented for purposes of additional analysis and is not a required part of the basic financial statements. This information has been subjected to the auditing
procedures applied in our audits of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.



ARTHUR ANDERSEN LLP

Houston, Texas

February 28, 2002 (except with respect to the matter discussed in Note 9,

as to which the date is March 11, 2002)



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West Coast Power LLC

Consolidated Balance Sheets

December 31, 2003 and 2002

---



|                                                                                                           |  |      |              |   |      |   |              |  
|---------------------------------------------------------------------------------------------------------- |  | ---- | ------------ | - | ---- | - | ------------ | -
|                                                                                                           |  | 2003 |              |   | 2002 |  
|Assets                                                                                                     |  |      |              |   |      |   |              |  
|Current assets                                                                                             |  |      |              |   |      |   |              |  
|Cash and cash equivalents                                                                                  |  | $    | 124,245,142  |   |      | $ | 36,083,124   |  
|Restricted cash                                                                                            |  |      |             |   |      |   | 69,362,303   |  
|Accounts receivable, net of allowance for doubtful accounts of $391,819,281 and $401,612,906, respectively |  |      | 57,843,586   |   |      |   | 60,970,908   |  
|Inventories                                                                                                |  |      | 25,626,499   |   |      |   | 31,447,329   |  
|Deposits and other                                                                                         |  |      | 40,999,687   |   |      |   | 7,971,890    |  
|Asset from risk-management activities                                                                      |  |      | 8,739,539    |   |      |   | 49,380,506   |  
|                                                                                                           |  |      |              |   |      |   |              |  
|Total current assets                                                                                       |  |      | 257,454,453  |   |      |   | 255,216,060  |  
|                                                                                                           |  |      |              |   |      |   |              |  
|Property, plant and equipment, at cost                                                                     |  |      |              |   |      |   |              |  
|Land                                                                                                       |  |      | 56,583,322   |   |      |   | 56,583,322   |  
|Plant and equipment                                                                                        |  |      | 553,951,022  |   |      |   | 528,241,382  |  
|Less: Accumulated depreciation                                                                             |  |      | (157,016,977 | ) |      |   | (126,168,082 | )
|                                                                                                           |  |      |              |   |      |   |              |  
|Property, plant and equipment, net                                                                         |  |      | 453,517,367  |   |      |   | 458,656,622  |  
|                                                                                                           |  |      |              |   |      |   |              |  
|Asset from risk-management activities                                                                      |  |      |             |   |      |   | 34,215,765   |  
|Goodwill (Note 3)                                                                                          |  |      |             |   |      |   | 38,998,481   |  
|                                                                                                           |  |      |              |   |      |   |              |  
|Total assets                                                                                               |  | $    | 710,971,820  |   |      | $ | 787,086,928  |  
|                                                                                                           |  |      |              |   |      |   |              |  
|Liabilities and Members Equity                                                                            |  |      |              |   |      |   |              |  
|Current liabilities                                                                                        |  |      |              |   |      |   |              |  
|Accounts payable                                                                                           |  |      |              |   |      |   |              |  
|Affiliates                                                                                                 |  | $    | 19,242,345   |   |      | $ | 39,917,938   |  
|Trade                                                                                                      |  |      | 1,032,198    |   |      |   | 1,045,372    |  
|Accrued liabilities                                                                                        |  |      | 26,241,219   |   |      |   | 11,712,647   |  
|Liabilities from risk-management activities                                                                |  |      | 8,739,539    |   |      |   | 49,380,506   |  
|Current maturities of long-term debt                                                                       |  |      |             |   |      |   | 10,000,000   |  
|                                                                                                           |  |      |              |   |      |   |              |  
|Total current liabilities                                                                                  |  |      | 55,255,301   |   |      |   | 112,056,463  |  
|Asset retirement obligation                                                                                |  |      | 7,631,979    |   |      |   |             |  
|Liabilities from risk-management activities                                                                |  |      |             |   |      |   | 34,215,765   |  
|Commitments and contingencies (Note 9)                                                                     |  |      |              |   |      |   |              |  
|Members equity                                                                                            |  |      | 648,084,540  |   |      |   | 640,814,700  |  
|                                                                                                           |  |      |              |   |      |   |              |  
|Total liabilities and members equity                                                                      |  | $    | 710,971,820  |   |      | $ | 787,086,928  |  
|                                                                                                           |  |      |              |   |      |   |              |  



See the notes to the
consolidated financial statements.





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##### Table of Contents

West Coast Power LLC

Consolidated Statements of Operations

Years Ended December 31, 2003, 2002 and 2001

---



|                                                                               |  |      |              |   |      |   |              |      |  |   |                |  
|------------------------------------------------------------------------------ |  | ---- | ------------ | - | ---- | - | ------------ | ---- |  | - | -------------- | -
|                                                                               |  | 2003 |              |   | 2002 |   |              | 2001 | 
|Revenues                                                                       |  | $    | 695,964,053  |   |      | $ | 585,306,960  |      |  | $ | 1,562,062,267  |  
|Affiliate operating costs, exclusive of depreciation shown separately below    |  |      | (302,954,125 | ) |      |   | (456,526,399 | )    |  |   | (1,123,221,590 | )
|Nonaffiliate operating costs, exclusive of depreciation shown separately below |  |      | (44,765,930  | ) |      |   | (17,167,990  | )    |  |   | (49,489,040    | )
|Depreciation and amortization                                                  |  |      | (31,692,792  | ) |      |   | (27,227,164  | )    |  |   | (30,440,631    | )
|Impairment charges                                                             |  |      | (38,998,481  | ) |      |   | (13,450,866  | )    |  |   |               |  
|General and administrative expenses                                            |  |      | (46,463,917  | ) |      |   | (22,508,906  | )    |  |   | (14,280,798    | )
|                                                                               |  |      |              |   |      |   |              |      |  |   |                |  
|Income from operations                                                         |  |      | 231,088,808  |   |      |   | 48,425,635   |      |  |   | 344,630,208    |  
|Interest expense                                                               |  |      | (176,008     | ) |      |   | (15,409,800  | )    |  |   | (32,843,268    | )
|Change in fair value of electricity options                                    |  |      |             |   |      |   |             |      |  |   | 12,080,525     |  
|Interest income                                                                |  |      | 1,327,284    |   |      |   | 1,129,160    |      |  |   | 2,491,253      |  
|                                                                               |  |      |              |   |      |   |              |      |  |   |                |  
|                                                                               |  |      |              |   |      |   |              |      |  |   |                |  
|Income before cumulative effect of change in accounting principles             |  |      | 232,240,084  |   |      |   | 34,144,995   |      |  |   | 326,358,718    |  
|Cumulative effect of change in accounting principle                            |  |      | 1,029,756    |   |      |   |             |      |  |   |               |  
|                                                                               |  |      |              |   |      |   |              |      |  |   |                |  
|Net income                                                                     |  | $    | 233,269,840  |   |      | $ | 34,144,995   |      |  | $ | 326,358,718    |  
|                                                                               |  |      |              |   |      |   |              |      |  |   |                |  



See the notes to the
consolidated financial statements.





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##### Table of Contents

West Coast Power LLC

Consolidated Statements of Members Equity and Comprehensive Income

Years Ended December 31, 2003, 2002 and 2001

---



|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|--------------------------------------------------------- |  | --------------------------------------------- | ---------- | - | -------------- | - | ------------ | -------------------- |  | - | ----------- | -
|                                                          |  | Accumulated Other Comprehensive Income (Loss) |            |   | MembersEquity |   |              | Comprehensive Income | 
|Balance, December 31, 2000                                |  |                                               |            |   |                | $ | 423,465,895  |                      |  |   |             |  
|                                                          |  |                                               |           
|Contributions                                             |  |                                               |            |   |                |   | 10,095,134   |                      |  |   |             |  
|Net income                                                |  |                                               |            |   |                |   | 326,358,718  |                      |  | $ | 326,358,718 |  
|Distributions                                             |  |                                               |            |   |                |   | (102,241,088 | )                    |  |   |             |  
|Cumulative effect of change in accounting principle       |  | $                                             | (147,551   | ) |                |   |              |                      |  |   |             |  
|Change in fair value of cash flow hedges                  |  |                                               | (6,411,167 | ) |                |   |              |                      |  |   |             |  
|Amounts reclassified into income                          |  |                                               | 2,031,884  |   |                |   |              |                      |  |   |             |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|Other comprehensive income                                |  |                                               | (4,526,834 | ) |                |   | (4,526,834   | )                    |  |   | (4,526,834  | )
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|Comprehensive income for the year ended December 31, 2001 |  |                                               |            |   |                |   |              |                      |  |   | 321,831,884 |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|                                                          |  |                                               |           
|Balance, December 31, 2001                                |  |                                               | (4,526,834 | ) |                |   | 653,151,825  |                      |  |   |             |  
|                                                          |  |                                               |           
|Contributions                                             |  |                                               |            |   |                |   | 13,516,477   |                      |  |   |             |  
|Net income                                                |  |                                               |            |   |                |   | 34,144,995   |                      |  |   | 34,144,995  |  
|Distributions                                             |  |                                               |            |   |                |   | (64,525,431  | )                    |  |   |             |  
|Amounts reclassified into income                          |  |                                               | 4,526,834  |   |                |   |              |                      |  |   |             |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|Other comprehensive income                                |  |                                               | 4,526,834  |   |                |   | 4,526,834    |                      |  |   | 4,526,834   |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|Comprehensive income for the year ended December 31, 2002 |  |                                               |            |   |                |   |              |                      |  |   | 38,671,829  |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|                                                          |  |                                               |           
|Balance, December 31, 2002                                |  |                                               |           |   |                |   | 640,814,700  |                      |  |   |             |  
|                                                          |  |                                               |           
|Net income                                                |  |                                               |            |   |                |   | 233,269,840  |                      |  |   | 233,269,840 |  
|Distributions                                             |  |                                               |            |   |                |   | (226,000,000 | )                    |  |   |             |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|Comprehensive income for the year ended December 31, 2003 |  |                                               |            |   |                |   |              |                      |  | $ | 233,269,840 |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  
|                                                          |  |                                               |           
|Balance, December 31, 2003                                |  | $                                             |           |   |                | $ | 648,084,540  |                      |  |   |             |  
|                                                          |  |                                               |            |   |                |   |              |                      |  |   |             |  



See the notes to the
consolidated financial statements.





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##### Table of Contents

West Coast Power LLC

Consolidated Statements of Cash Flows

Years Ended December 31, 2003, 2002 and 2001

---



|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|------------------------------------------------------------------------------------------ |  | ---- | ------------ | - | ---- | - | ------------ | ---- |  | - | ------------ | -
|                                                                                           |  | 2003 |              |   | 2002 |   |              | 2001 | 
|Cash flows from operating activities                                                       |  |      |              |   |      |   |              |      |  |   |              |  
|Net income                                                                                 |  | $    | 233,269,840  |   |      | $ | 34,144,995   |      |  | $ | 326,358,718  |  
|Adjustments to reconcile net income to net cash provided by (used in) operating activities |  |      |              |   |      |   |              |      |  |   |              |  
|Depreciation and amortization                                                              |  |      | 31,692,792   |   |      |   | 27,227,164   |      |  |   | 30,440,631   |  
|Impairment charges                                                                         |  |      | 38,998,481   |   |      |   | 13,450,866   |      |  |   |             |  
|Cumulative effect of change in accounting policy                                           |  |      | (1,029,756   | ) |      |   |             |      |  |   |             |  
|Change in fair value of electricity options                                                |  |      |             |   |      |   |             |      |  |   | (12,080,525  | )
|Changes in assets and liabilities that provided (used) cash:                               |  |      |              |   |      |   |              |      |  |   |              |  
|Accounts receivable, net                                                                   |  |      | 3,127,322    |   |      |   | 164,277,423  |      |  |   | 21,350,894   |  
|Inventories                                                                                |  |      | 1,164,036    |   |      |   | 11,617,313   |      |  |   | (12,542,257  | )
|Deposits and other                                                                         |  |      | (30,337,866  | ) |      |   | 2,226,118    |      |  |   | (3,033,837   | )
|Accounts payable                                                                           |  |      | (20,687,562  | ) |      |   | (17,268,735  | )    |  |   | (125,087,533 | )
|Accrued liabilities                                                                        |  |      | 20,571,285   |   |      |   | 5,728,817    |      |  |   | (4,887,962   | )
|Other                                                                                      |  |      | 3,740,781    |   |      |   | 2,488,844    |      |  |   | (468,737     | )
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Net cash provided by operating activities                                                  |  |      | 280,509,353  |   |      |   | 243,892,805  |      |  |   | 220,049,392  |  
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Cash flows from investing activities                                                       |  |      |              |   |      |   |              |      |  |   |              |  
|Capital expenditures                                                                       |  |      | (25,709,638  | ) |      |   | (21,651,761  | )    |  |   | (27,403,973  | )
|Decrease (increase) in restricted cash                                                     |  |      | 69,362,303   |   |      |   | (69,362,303  | )    |  |   |             |  
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Net cash provided by (used in) investing activities                                        |  |      | 43,652,665   |   |      |   | (91,014,064  | )    |  |   | (27,403,973  | )
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Cash flows from financing activities                                                       |  |      |              |   |      |   |              |      |  |   |              |  
|Proceeds from borrowings                                                                   |  |      |             |   |      |   |             |      |  |   | 40,000,000   |  
|Repayments of borrowings                                                                   |  |      | (10,000,000  | ) |      |   | (140,056,703 | )    |  |   | (107,847,297 | )
|Contributions                                                                              |  |      |             |   |      |   | 13,516,477   |      |  |   | 10,095,134   |  
|Distributions                                                                              |  |      | (226,000,000 | ) |      |   | (64,525,431  | )    |  |   | (102,241,088 | )
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Net cash used in financing activities                                                      |  |      | (236,000,000 | ) |      |   | (191,065,657 | )    |  |   | (159,993,251 | )
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Net increase (decrease) in cash and cash equivalents                                       |  |      | 88,162,018   |   |      |   | (38,186,916  | )    |  |   | 32,652,168   |  
|Cash and cash equivalents                                                                  |  |      |              |   |      |   |              |      |  |   |              |  
|Beginning of year                                                                          |  |      | 36,083,124   |   |      |   | 74,270,040   |      |  |   | 41,617,872   |  
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|End of year                                                                                |  | $    | 124,245,142  |   |      | $ | 36,083,124   |      |  | $ | 74,270,040   |  
|                                                                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Supplemental disclosure of cash flow information                                           |  |      |              |   |      |   |              |      |  |   |              |  
|Cash paid for interest                                                                     |  | $    | 177,883      |   |      | $ | 4,336,114    |      |  | $ | 33,056,514   |  



See the notes to the
consolidated financial statements.





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##### Table of Contents

|                                                                                          
|------------------------------------------------------------------------------------------
|West Coast Power LLC Notes to Consolidated
Financial Statements December 31, 2003 and 2002
|                                                                                          



|1. | Background and Nature of Operations
|-- | -----------------------------------



Background



Prior to 1999, Dynegy Power Corp. (DPC), an indirect wholly owned subsidiary of Dynegy Holdings Inc. (Dynegy), and NRG Energy,
Inc. (NRG), a majority owned subsidiary of Northern States Power Company until its merger with New Century Energies, Inc., to form Xcel Energy, Inc., in August 2000 (collectively, the Sponsors) each held a 50% interest in two
limited liability companies: El Segundo Power, LLC (ESP), and Long Beach Generation LLC (LBG) (collectively, the Historical LLCs). In May 1999, the Sponsors acquired the assets and liabilities which make up
Cabrillo Power I LLC (Cabrillo I) and Cabrillo Power II LLC (Cabrillo II) (collectively, the New LLCs). Effective June 30, 1999, 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 the Historical LLCs and New LLCs. NRG was an indirect, wholly owned subsidiary of Xcel Energy, Inc. and NRG became an independent public company upon its emergence from bankruptcy on December 5,
2003. NRG 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 with two representatives from each Sponsor.



Nature of Operations



ESP owns a 670-megawatt (MW) plant located in El Segundo, California, consisting of two operating steam electric generating units. The
facility operates as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets.



LBG owns a 470-MW plant located in Long Beach, California, consisting of seven gas turbine generators and two steam turbine
units. The facility operates as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets.



Cabrillo I owns a 970-MW plant located in Carlsbad, California, consisting of five steam electric generating units and one
combustion turbine. The facility operates as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets.



Cabrillo II owns 17 combustion turbines of which 13 are operational with an
aggregate capacity of 202-MW located throughout San Diego County, California. The facility operates as a merchant plant, selling energy and ancillary services through the deregulated California wholesale electric market and other western markets.



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##### Table of Contents

|                                                                                          
|------------------------------------------------------------------------------------------
|West Coast Power LLC Notes to Consolidated
Financial Statements December 31, 2003 and 2002
|                                                                                          



|2. | Accounting Policies
|-- | -------------------



Principles of Consolidation



The accompanying consolidated financial statements include our accounts after eliminating intercompany accounts and transactions.



Use of Estimates in Financial Statement Preparation



The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America requires management to develop estimates and to make assumptions that affect the reported financial position and results of operations and that impact the nature and extent of disclosure,
if any, of contingent liabilities. We review significant estimates affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based
on our beliefs and assumptions derived from information at the time such estimates are made. Adjustments made with respect to these estimates often relate to information not previously available. Uncertainties with respect to such estimates and
assumptions are inherent in the preparation of the financial statements. Such estimates include, among other things, developing fair value assumptions, analyzing tangible and intangible assets for possible impairment, estimating useful lives of our
assets and determining and assessing amounts to accrue for estimated reserves for probable contingencies such as those discussed in Note 9. Actual results could differ materially from those estimates.



Cash and Cash Equivalents



Cash and cash equivalents consist of all demand deposits and funds invested
in short-term investments with an original maturity of three months or less.



Restricted Cash



Restricted cash represents cash that is unavailable for general purpose cash needs. Such amounts were restricted pursuant to our credit agreement, which was repaid during 2003.



Allowance for Doubtful Accounts



We establish provisions for losses on accounts receivable if it is reasonable to assume we will not collect all or part of
outstanding balances. We review collectibility and establish or adjust our allowance as necessary using the specific identification method. As of December 31, 2003 and 2002, we have reserved $391,819,281 and $401,612,906, respectively, as a net
allowance for doubtful accounts relating to receivables owed to us by the California ISO (the ISO) and the California Power Exchange (the PX).



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##### Table of Contents

|                                                                                          
|------------------------------------------------------------------------------------------
|West Coast Power LLC Notes to Consolidated
Financial Statements December 31, 2003 and 2002
|                                                                                          



Inventories



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 at December 31, 2003 and 2002:



|                                      |  |      |            |      |   |           
|------------------------------------- |  | ---- | ---------- | ---- | - | ----------
|                                      |  | 2003 |            | 2002
|Emissions credits (average cost)      |  | $    | 5,366,618  |      | $ | 6,257,560 
|Materials and supplies (average cost) |  |      | 6,417,638  |      |   | 10,390,591
|Fuel oil (LIFO)                       |  |      | 13,842,243 |      |   | 14,799,178
|                                      |  |      |            |      |   |           
|                                      |  | $    | 25,626,499 |      | $ | 31,447,329
|                                      |  |      |            |      |   |           





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 Environmental Costs.



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 is provided using the straight-line method over the
estimated economic service lives of the assets, ranging from 3-25 years. The estimated economic service lives of our asset groups are as follows:



|                            |  |             
|--------------------------- |  | ------------
|Power generating facilities |  | 7  25 years
|Furniture and fixtures      |  | 3  5 years 
|Other miscellaneous         |  | 5  20 years



Impairment of
Long-Lived Assets



In the event that facts and
circumstances indicate that the carrying amounts of long-lived assets could be impaired, an evaluation of recoverability is performed that compares the estimated future undiscounted cash flows associated with the asset to the assets carrying
amount to determine if a write-down is required. If this evaluation indicates that the assets will not be recoverable, the carrying value of the assets would be reduced to their estimated fair value. In August 2002, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (Statement No. 144). Statement No. 144 addresses the
accounting and reporting for the impairment or disposal of long-lived assets. Our adoption of Statement No. 144 on January 1, 2002, did not have any impact on our financial position or results of operations.



In December 2003, we tested our long-lived assets for impairment in
accordance with Statement No. 144. After performing the test, it was concluded that no impairment was necessary.



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##### Table of Contents

|                                                                                          
|------------------------------------------------------------------------------------------
|West Coast Power LLC Notes to Consolidated
Financial Statements December 31, 2003 and 2002
|                                                                                          



Asset Retirement
Obligation



In June 2001, the FASB issued SFAS No. 143,
Accounting for Asset Retirement Obligations (Statement No. 143). WCP adopted SFAS No. 143, which provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, effective January
1, 2003. Under Statement No. 143, an Asset Retirement Obligation (ARO) is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the
liability is accreted over time towards the ultimate obligation amount and the capitalized costs are depreciated over the useful life of the related asset.



Upon adoption of Statement 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 ARO and was recorded upon adoption of Statement No. 143. Since the previously accrued liabilities exceeded the fair value of the
future retirement obligations, the impact of adopting Statement No. 143 was an increase in earnings of $1,029,756 in the first quarter 2003, which is the cumulative effect of change in accounting principles in the consolidated statement of
operations.



At January 1, 2003, our ARO liabilities were
approximately $8,020,242 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 lease 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 $644,483 and $697,472, respectively, during 2003. During 2003, we settled $1,085,735 relating to our ARO. At December 31, 2003,
our ARO liabilities are $7,631,979.



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 Statement No. 143 at such time as our operations change and a liability is incurred.



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,
2001:

|                                                                           |  |                         |            |   |      |   |             |  
|-------------------------------------------------------------------------- |  | ----------------------- | ---------- | - | ---- | - | ----------- | -
|                                                                           |  | Year Ended December 31, |           
|                                                                           |  | 2002                    |            |   | 2001 |  
|                                                                           |  |                         |            |   |      |   |             |  
|Net income, as reported                                                    |  | $                       | 34,144,995 |   |      | $ | 326,358,718 |  
|Pro forma adjustments to reflect retroactive adoption of Statement No. 143 |  |                         | (1,224,171 | ) |      |   | (1,164,184  | )
|                                                                           |  |                         |            |   |      |   |             |  
|Pro forma net income                                                       |  | $                       | 32,920,824 |   |      | $ | 325,194,534 |  
|                                                                           |  |                         |            |   |      |   |             |  





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|                                                                                          
|------------------------------------------------------------------------------------------
|West Coast Power LLC Notes to Consolidated
Financial Statements December 31, 2003 and 2002
|                                                                                          



Goodwill



Prior to 2002, goodwill was amortized on a straight-line
basis over its 3 to 27 year estimated useful life. However, we adopted SFAS No. 142, Goodwill and Other Intangible Assets (Statement No. 142), effective January 1, 2002, and, accordingly discontinued amortizing goodwill. We
incurred no impairment of goodwill upon the adoption of Statement No. 142.



In accordance with Statement No. 142, we subject goodwill to a fair value-based impairment test on at least an annual basis. 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 the annual budgetary process.



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.



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 Reliability Must Run Agreement (RMR) with the
ISO are primarily derived from availability payments and amounts based on reimbursing variable costs. Revenues identified as being subject to future resolution are accounted for as discussed above at Allowance for Doubtful Accounts.



Environmental Costs



Environmental costs relating to current operations are expensed. Liabilities
are recorded when environmental assessment indicates remedial efforts are probable and the costs can be reasonably estimated.



Concentration of Credit Risk



We sell our electricity production to purchasers of electricity in California, which included the PX (prior to its Chapter 11 bankruptcy in 2001), the ISO
and, beginning in 2001, the California Department of Water Resources (CDWR) and Dynegy Power Marketing, Inc. (DYPM). We remain exposed to credit risk on our outstanding ISO and PX receivables for power delivered from November
2000 through January 2001. We established reserves against this credit risk that we consider appropriate as further discussed in above at Allowance for Doubtful Accounts.



Fair Value of Financial Instruments



Our financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, debt
instruments 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. The fair value of our debt instruments is considered to approximate the carrying amount of these instruments as their interest rates are based on the London Interbank Offering Rate (LIBOR).
Additionally, we had entered into certain interest rate swap agreements as well as fair value hedges and electricity options. The fair value of these instruments is discussed in Note 8 and Note 5, respectively.





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|West Coast Power LLC Notes to Consolidated
Financial Statements December 31, 2003 and 2002
|                                                                                          



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.



Effective January 1, 2001, hedging gains and losses are recognized in
accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities(Statement No. 133).



Under Statement 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 derivatives 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.



We adopted Statement No. 133 on January 1, 2001, and recorded an immaterial cumulative effect adjustment to other comprehensive income attributable to
certain gas and interest rate cash flow hedges. There was no impact on net income at adoption.



|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
Impairment charges on the consolidated statements of operations.



The following table shows what our net income would have been in 2001 if goodwill had not been amortized during that period, compared to the net income recorded in 2003 and 2002:



|                                |  |      |             |      |   |            |  |   |            
|------------------------------- |  | ---- | ----------- | ---- | - | ---------- |  | - | -----------
|                                |  | 2003 |             | 2002 |   | 2001      
|Reported net income             |  | $    | 233,269,840 |      | $ | 34,144,995 |  | $ | 326,358,718
|Add back: goodwill amortization |  |      |            |      |   |           |  |   | 2,835,208  
|                                |  |      |             |      |   |            |  |   |            
|Adjusted net income             |  | $    | 233,269,840 |      | $ | 34,144,995 |  | $ | 329,193,926
|                                |  |      |             |      |   |            |  |   |            



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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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|4. | Impairment of Long-Lived Assets
|-- | -------------------------------



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 turbines are located to its original condition. This reserve was reversed upon adoption of
SFAS 143 in 2003. Please read Note 2  Assets Retirement Obligation. As of December 31, 2003, these turbines had not been sold.



|5. | Derivatives and Hedging
|-- | -----------------------



During the years ended December 31, 2003, 2002 and 2001, 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. Additionally, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable.



We have 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, 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 recognized in relation to firm commitments that no longer qualified as fair value hedge items.



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. Breakage fees of approximately $5,200,000 were expensed at the time of refinancing.



The value of the fair value hedges at December 31, 2003 and 2002, was approximately $(8,739,539) and $(83,600,000) and is
included in liabilities from risk-management activities on the consolidated balance sheets. The corresponding value of the hedged risk is approximately $8,739,539 and $83,600,000 and is included in assets from risk-management activities on the
consolidated balance sheets.



|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.



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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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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 $617,370,571, $540,114,356 and $1,077,421,540 for the years ended December 31, 2003, 2002 and 2001, respectively.
Additionally, we contracted with DMT to provide all scheduling of fuel supply.



We contracted with NRG West, Inc., one of our affiliates, to manage our facilities under the operations and management services agreements (OMSA). The services provided under the OMSA consisted primarily
of overseeing the operations and maintenance efforts of Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E). SCE operated ESP and LBG until April 2000, and SDG&E operated Cabrillo I and Cabrillo II
until May 2001. We then 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. 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 the OMSAs were terminated once 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 provided under the AMA include local services not covered under the O&M
agreements, including environmental, engineering, legal and public relations services. Fees for such services are subject to executive committee approval if the amounts exceed a certain percentage of the applicable annual approved budget.



We entered into an administrative services management
agreement (the ASMA) with Dynegy Power Management Services, L.P., one of our affiliates, which 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 our 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 2003 and 2001, no interest was paid to DMT.



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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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As described above, our affiliates provide various services for us.
Charges for these services are included in our operating and general and administrative expenses and consisted of the following for the years ended December 31, 2003, 2002 and 2001:



|                                                          |  |      |             |      |   |             |  |   |              
|--------------------------------------------------------- |  | ---- | ----------- | ---- | - | ----------- |  | - | -------------
|Dynegys Related Cost                                     |  |      |             |      |   |             |  |   |              
|                                                          |  | 2003 |             | 2002 |   | 2001       
|                                                          |  |      |            
|Operating costs                                           |  |      |             |      |   |             |  |   |              
|Fuel                                                      |  | $    | 258,133,778 |      | $ | 401,650,246 |  | $ | 1,054,268,850
|EMA charges                                               |  |      | 9,141,394   |      |   | 10,345,506  |  |   | 17,016,988   
|ASMA charges                                              |  |      | 207,095     |      |   |            |  |   |             
|                                                          |  |      |             |      |   |             |  |   |              
|                                                          |  | $    | 267,482,267 |      | $ | 411,995,752 |  | $ | 1,071,285,838
|                                                          |  |      |             |      |   |             |  |   |              
|ASMA fees included in general and administrative expenses |  | $    | 1,331,007   |      | $ | 1,297,759   |  | $ | 1,374,214    
|                                                          |  |      |             |      |   |             |  |   |              
|NRGs Related Cost                                        |  |      |             |      |   |             |  |   |              
|                                                          |  | 2003 |             | 2002 |   | 2001       
|                                                          |  |      |            
|Operating costs                                           |  |      |             |      |   |             |  |   |              
|OMSA, O&M and AMA charges                                 |  | $    | 35,471,858  |      | $ | 44,530,647  |  | $ | 51,935,752   
|                                                          |  |      |             |      |   |             |  |   |              



|7. | Power Purchase Agreement
|-- | ------------------------



We entered into a long-term Power Purchase Agreement with the CDWR in March 2001. From inception through December 31, 2001, the CDWR contracted for system
contingent capacity and energy sales of an aggregate of 1,000 MW from our facilities. 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 88% and 93% of revenues net of reserves in 2003 and 2002, respectively.



Unless a new contract is signed or the contract is renegotiated prior to the expiration of the CDWR contract, our assets will operate as merchant
facilities beginning in 2005. Due to transmission constraints, power prices vary substantially across Western Electric Coordinating Council (WECC) and are generally highest in Southern California, where our facilities are located. While
we believe there is not currently an oversupply of generation in Southern California, and power prices are generally strong, it is likely that our facilities will be significantly less profitable as merchant facilities compared to profits generated
under the CDWR contract.



|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.



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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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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 the 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. At December 31, 2002, unamortized debt issuance costs approximated
$2,400,000.



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. At December 31,
2003, our deposit for collateral was $21,600,000. Of this deposit, $15,100,000 was issued in letters of credit. We incurred financing costs of $694,000 in connection with the new agreement. Such costs have been capitalized and are being amortized
over the remaining term of the new agreement and are included in prepaid expenses and other current assets. At December 31, 2003, unamortized debt issuance costs approximated $463,000.



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 $2,900,000, $15,400,000 and $18,600,000 for 2003, 2002 and 2001, respectively.



|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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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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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, Accounting for Contingencies. For environmental matters, we record liabilities when remedial efforts are probable and
the costs can be reasonably estimated. Please see Note 2 for further discussion. 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 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.





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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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California Market Litigation



Ten class action lawsuits were filed in 2000-2001 which name us and other
related and unrelated parties based on the events occurring in the California power market. The complaints allege that defendants engaged in unfair business practices, price fixing and other antitrust violations. Seven of the ten class action
lawsuits were dismissed on the grounds of federal preemption and the filed rate doctrine. Plaintiffs have appealed those rulings to Ninth Circuit U.S. Court of Appeals. The three remaining cases are still pending.



Two other actions naming WCP and the LLCs were filed in 2002 with
allegations similar to those cases referenced in the previous paragraph 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 business 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.



In 2002, the California Attorney General filed, on behalf of the People of the State of California, complaints in San Francisco Superior Court against
several owners of power generation facilities, including WCP and the LLCs. The complaint alleges unfair competition in connection with transactions in the California ISO ancillary services market. These lawsuits were subsequently removed to the U.S.
District Court for the Northern District of California. In March 2003, these lawsuits were dismissed based upon the filed rate doctrine and federal preemption principles. The California Attorney General has appealed this decision to the Ninth
Circuit Court of Appeals. The case has been fully briefed and argued and is under submission before the court.



In November 2002, a class action was filed in the California Superior Court on behalf of purchasers of natural gas and electricity in the State of
California. Plaintiffs allege damages as the result of the defendants alleged false reporting of pricing and volume information regarding natural gas transactions. The LLCs are named as defendants. In July 2003, the Court granted
defendants motions to dismiss all causes of action with leave to amend. Plaintiffs have amended their complaint and the case is still pending.



We believe that we have meritorious defenses to the claims listed above and intend to defend against them vigorously. Management believes it has recorded
adequate reserves relating to these claims; however, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.





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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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FERC Related Regulatory Investigations-Requests for Refunds



In July 2001, the FERC initiated a hearing to establish
refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2, 2000 through June 20, 2001. In particular, the FERC established a methodology to calculate mitigated market clearing prices
in the ISO and the PX markets. In December 2002, the administrative law judge issued his recommendations regarding the appropriate level of refunds or offsets. Those recommendations, however, do not fully reflect proposed refund or offset amounts
for individual companies. In October 2003, FERC issued two orders addressing various applications for rehearing, including ours, of its previous refund orders. The orders granted numerous requests by the parties, the most significant of which was
the denial of a request to change the gas pricing methodology (see subsequent paragraph) and requiring the ISO and PX to re-run settlements to calculate refund liability of market participants. We do not expect a final refund calculation until
August 2004 at the earliest.



Also in October 2003, the LLCs
and DYPM, among others, filed a Petition for Review in the United States Circuit Court of Appeals for the District of Columbia Circuit challenging numerous FERC orders relating to our refund liability and similar matters arising out of various
energy transactions in California and elsewhere in the West for the period May 2000 to June 2001. Other parties also have filed similar appeals to the DC circuit and in the Ninth Circuit. We are unable to predict when the case will be heard, when a
decision will be issued, or the effects of the decision on our financial condition, results of operations and cash flows.



In August 2002, the FERC requested comments on a proposal made by the FERC staff to change the method for determining natural gas prices for purposes of
computing the mitigated market-clearing price that it intends to utilize in calculating refunds for sales of power in California power markets during the period from October 2, 2000, to June 19, 2001. The proposal, adopted by the FERC in March 2003,
replaced the gas prices used in the computation, thus reducing the mitigated market clearing price for power and increasing calculated refunds, subject to a provision that generally would provide full recoverability of actual gas costs paid by the
generators to third parties. In April 2003, we also sought rehearing of the FERCs decision changing the gas pricing methodology. An order denying rehearing was issued in October 2003, although FERC has deferred the calculation of actual gas
costs offsets to a later order.



Management believes it has
recorded adequate reserves relating to these claims; however, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.



Trading Strategies Investigation



In June 2003, the FERC issued an order to show cause why the activities of
certain participants in the California power markets from January 1, 2000 to June 20, 2001, including us, did not constitute gaming and/or anomalous market behavior as defined in the ISO and PX tariffs.



In January 2004, we and FERC Trial Staff submitted a stipulation and
settlement agreement with the presiding administrative law judge to settle the issues raised in the above referenced Order to Show Cause. The settlement provides that WCP will pay to FERC the sum of $3,014,942, without admitting to the allegations
in the show cause order, without admitting that it violated any tariff, regulation, order, or statute, and without admitting that it adversely affected prices in any market. The full Commission must approve the settlement before it becomes final.



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West Coast Power LLC

Notes to Consolidated Financial Statements

December 31, 2003 and 2002

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Anomalous Bidding Behavior Investigation



In June 2003, the FERC issued an order requiring parties to demonstrate that
certain bids did not constitute anomalous market behavior. Specifically, the order requires the FERC Staff to investigate all parties who bid above the level of $250/MWH in the ISO and PX markets during the period from May 1, 2000 to October 2,
2000. Parties identified through this process will be required to demonstrate why this bidding behavior did not violate market protocols. The order also states that, to the extent such practices are not found to be legitimate business behavior, the
FERC will require the disgorgement of all unjust profits for that period and will consider other non-monetary remedies, such as the revocation of market-based rate authority. We believe that we have meritorious defenses against these claims and
intend to defend against them vigorously.



Management believes
it has recorded adequate reserves relating to these claims; however, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.



Other FERC and California Investigations



In addition to civil litigation and refund proceedings, we are also subject
to a number of investigations and inquiries by FERC and orders regarding our past trading practices. In 2002 and 2003, the FERC issued data requests to us and numerous other energy companies seeking information with respect to reporting whether
these companies engaged in physical withholding of power in California. We have responded timely to all such requests and intend to cooperate fully with these investigations. Nevertheless, we cannot predict with certainty how or when these
investigations will be resolved.



We are party to a number of
FERC proceedings relating to (a) the formula pricing under our Reliability Must Run Contracts with Cabrillo Power I LLC, Cabrillo Power II LLC and the ISO, (b) the FERC price mitigation plan for wholesale power transactions in spot markets in the
Western Systems Coordinating Counsel in effect from June 2001 through October 2002, and (c) our request that the ISO collect from CDWR, on our behalf, past due amounts for services we previously provided to Southern California Edison Company and
Pacific Gas and Electric Company. Because of the complexity and stage of these matters, we are unable to predict how these proceedings may affect WCP.



Western Long-Term Contract Complaints



In February 2002, the California Public Utilities Commission and the California Electricity Oversight Board filed complaints with the FERC asking that it
void or reform power supply contracts between the CDWR and, among others, WCP. The complaints allege that prices under the contracts exceed just and reasonable prices permitted under the FPA. In June 2003 the FERC ruled that long-term contracts with
the CDWR, including WCP, were valid and would be upheld. In August 2003, various California parties filed a request for a rehearing on the long-term contract issue with FERC. In November 2003, FERC denied the applications for rehearing, providing,
again, an opinion in favor of upholding the long-term contracts. The California Public Utilities Commission has also filed for Petition of Review in the Ninth Circuit appealing the denial of the application for rehearing at FERC. We are awaiting
rulings on all of these filings. Because of the complexity and state of this matter, the effect on us and whether it will lead to additional litigation cannot be predicted with certainty.



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