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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2004

For the transition period from                      to

Commission file number: 000-29311

DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)

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:

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

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE. None.

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

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DYNEGY HOLDINGS INC. FORM 10-K

INTRODUCTORY NOTE

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

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

Item 6. Selected Financial Data

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

Item 8. Financial Statements and Supplementary Data

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DYNEGY HO LDINGS INC.

FORM 10-K

TABLE OF CONTENTS

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PART I

DEFINITIONS

As used in this Form 10-K, the abbreviations contained herein have the meanings set forth in the glossary beginning on page F-71. Additionally, the terms “Dynegy Holdings,” “we,” “us” and “our” refer to Dynegy Holdings Inc. and its subsidiaries, unless the context clearly indicates otherwise. The term “Dynegy” refers to our parent company, Dynegy Inc., and its subsidiaries, including us, unless the context clearly indicates otherwise.

THE COMPANY

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

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

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

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

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

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

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

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

SEGMENT DISCUSSION

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

Power Generation

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

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

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

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

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

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

(as of December 31, 2004)

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Natural Gas Liquids

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

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

Upstream Business

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Downstream Business

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

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:

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

Customer Risk Management

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

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

CRM Obligations

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

Other

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

COMPETITION

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

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

REGULATION

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

Please read “—Environmental and Other Matters” beginning on page 21 for a discussion of environmental regulations affecting our business.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

ENVIRONMENTAL AND OTHER MATTERS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Ongoing Environmental Initiatives

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

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

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

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

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

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

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

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

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

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

OPERATIONAL RISKS AND INSURANCE

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

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

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

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

SIGNIFICANT CUSTOMER

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

EMPLOYEES

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

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

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

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

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

PART II

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

Securities Authorized for Issuance Under Equity Compensation Plans

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

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

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

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Dynegy Holding’s Selected Financial Data

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

OVERVIEW

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

LIQUIDITY AND CAPITAL RESOURCES

Overview

Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures, legal settlements and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas, coal and natural gas liquids, facility maintenance costs and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, asset sale proceeds and proceeds from capital market transactions, to the extent that we engage in these activities prospectively.

Debt Obligations

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

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

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

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

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Collateral Postings

We continue to use a significant portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. The following table summarizes our consolidated collateral postings to third parties by segment at March 11, 2005, December 31, 2004 and December 31, 2003:

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

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

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

Disclosure of Contractual Obligations and Contingent Financial Commitments

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

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

Contractual Obligations

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

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

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

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

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

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

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

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

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

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

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

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

Contingent Financial Obligations

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

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Off-Balance Sheet Arrangements

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

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

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

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

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

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

Capital Expenditures

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

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

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

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

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

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

Financing Trigger Events

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

Commitments and Contingencies

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

Internal Liquidity Sources

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

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

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

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corporate-level expenses. Please read “—Results of Operations—Year Ended 2004 Compared to Year Ended 2003—Operating Income (Loss)” beginning on page 46 and “—Cash Flow Disclosures” beginning on page 59 for further discussion of factors impacting our operating cash flows for the periods presented.

Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs, including costs for fuel and maintenance. With respect to fuel costs, in January 2004, we entered into a new rail transportation contract that reduced the fees associated with fuel procurement at our coal-fired generation facilities in the Midwest; however, these fee reductions were substantially offset by increased coal prices in the Northeast and higher costs associated with the purchase of emission credits. Our ability to achieve fuel-related and other targeted cost savings in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, will impact our future operating cash flows. Please read “—Results of Operations—2005 Outlook—GEN Outlook” beginning on page 56 for further discussion.

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

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

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

External Liquidity Sources

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

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

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