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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2003

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  x    No  ¨

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

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

DOCUMENTS INCORPORATED BY REFERENCE. None.

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

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DYNEGY HOLDINGS INC.

FORM 10-K

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PART I

DEFINITIONS

As used in this Form 10-K, the abbreviations contained herein have the meanings set forth in the glossary beginning on page F-64. Additionally, the terms “Dynegy Holdings,” “we,” “us” and “our” refer to Dynegy Holdings Inc. and its subsidiaries, unless the context clearly indicates otherwise. The term “Dynegy” refers to our parent company, Dynegy Inc., and its subsidiaries, including us, unless the context clearly indicates otherwise.

Item 1. Business

THE COMPANY

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

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

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

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

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

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

Our SEC filings on Forms 10-K, 10-Q and 8-K (and amendments to such filings) are available free of charge on our website, www.dynegy.com, as soon as reasonably practicable after those reports are filed with or furnished to the SEC. The contents of our website are not intended to be, and should not be considered to be, incorporated by reference into this Form 10-K.

SEGMENT DISCUSSION

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

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

Power Generation

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

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

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

Additionally, markets exist for the purchase and sale of emission credits and, from time to time, we either purchase emission credits from third parties in quantities sufficient to operate our plants within the emission

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guidelines of the various air districts or pay mitigation fees to the applicable air district as required. We may also sell emission credits that we do not need to utilize in the generation of power into the marketplace. Please read “—Regulation—Power Generation Regulation” beginning on page 16 and “—Environmental and Other Matters” beginning on page 18 for further discussion of the environmental and regulatory restrictions applicable to our business.

U.S. Generation Facilities. We own or lease electric power generation facilities with an aggregate net generating capacity of 12,713 MWs located in six regions of the United States. The following table describes our current generation facilities by name, region, location, net capacity, fuel and dispatch type.

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

(as of December 31, 2003)

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Midwest region—Mid-America Interconnected Network Reliability Council (MAIN). At December 31, 2003, we owned or leased interests in 10 generating facilities with an aggregate net generating capacity of 4,155 MWs located within MAIN. The generating capacity of our MAIN facilities represents approximately 6% of the generating capacity within the MAIN region. The MAIN market includes all of Illinois and portions of Missouri, Wisconsin, Iowa, Minnesota and Michigan.

Approximately 50% of the power generated by our MAIN facilities is sold pursuant to a power purchase agreement between DMG and Illinois Power. This agreement, which is served through Illinois Power’s former generation facilities now owned or leased by DMG, provides Illinois Power with approximately 70% of its capacity requirements through December 2004. The contract provides for fixed capacity payments based on the capacity reserved, as well as variable energy payments for each MWh of energy delivered under the contract based on DMG’s cost of generation. Under the agreement, DMG bears ultimate responsibility for serving Illinois Power’s load as the provider of last resort; it also supplies all ancillary services required by Illinois Power. This power purchase agreement provided a substantial portion of the operating income from our power generation business in 2003.

In connection with Dynegy’s agreement to sell Illinois Power to Ameren, which Dynegy is targeting for closing by the end of 2004, we also agreed, conditioned on closing of the sale, to sell 2,800 MWs of capacity and up to 11.5 million MWh of energy to Illinois Power at fixed prices for two years beginning in January 2005. We also agreed to sell 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to Illinois Power at a fixed price with an option to purchase energy at market-based prices. Under this arrangement, we would no longer be the provider of last resort to Illinois Power. If the Illinois Power sale closes before year-end, the parties would continue under the current agreement through its December 31, 2004 expiration. If Dynegy is unable to complete the sale of Illinois Power, any new agreement with Illinois Power may not be executed at the same rates as our existing agreement. Please read Note 22—Subsequent Event beginning on page F-62 for further discussion.

Approximately 5% of our capacity, incremental to the capacity committed under the Illinois Power power purchase agreement, is sold under capacity contracts, including 165 MWs related to our interest in Rocky Road through 2009. The remainder of the capacity and energy is sold primarily into wholesale markets in MAIN, the neighboring East Central Reliability Area, or ECAR, and the Pennsylvania-New Jersey-Maryland market, or PJM.

The MAIN region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERC’s estimated 2003 reserve margin of 25%, which is in excess of the MAIN region’s target minimum reserve margin of 15-17%. This overcapacity has depressed energy and capacity prices in this region and likely will continue to do so absent peak demand growth and/or plant retirements. Based on current expectations of future demand growth and retirements, we believe that reserve margins are likely to return to target levels within the next 4-6 years.

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

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

The ECAR region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERC’s estimated 2003 reserve margin of 29%. ECAR has not explicitly stated a target reserve margin range, but we believe it to be consistent with MAIN’s 15-17% target. This overcapacity has depressed energy and capacity values in this region and likely will continue to do so absent peak demand growth and/or plant retirements. Based on current expectations of future demand growth and retirements, we believe that reserve margins are likely to return to target levels within the next 4-6 years.

Northeast region – Northeast Power Coordinating Council (NPCC). We own or lease two generating facilities in New York, which we refer to as the DNE facilities, with an aggregate net generating capacity of 1,708 MWs. Our DNE facilities’ sites are adjacent and share common resources such as fuel handling, a docking terminal, personnel and systems. The generating capacity of these facilities represents approximately 5% of the generating capacity in the state of New York. We are committed to sell approximately 12% of the capacity from our DNE facilities to Central Hudson Gas & Electric Corporation, from whom we acquired the facilities, pursuant to a transitional power purchase agreement that expires in October 2004. The revenues and cash flows from this agreement are not material to this segment’s results of operations.

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

Southeast region—Southeast Electric Reliability Council (SERC). We own interests in five generating facilities with an aggregate net generating capacity of 1,962 MWs located within SERC. SERC includes all or portions of the states of Missouri, Kentucky, Arkansas, Tennessee, West Virginia, Virginia, North Carolina, South Carolina, Louisiana, Mississippi, Alabama, Georgia and Florida. The generating capacity of these facilities represents approximately 1% of the generating capacity in SERC. Of our 1,962 MWs of net generating capacity in SERC, 1,242 MWs, or 63%, is under capacity and energy contracts. A contract for the Rockingham facility’s 600 MWs of capacity expired in December 2003. A contract for the Calcasieu facility’s 320 MWs of capacity expires in December 2004. A contract for the Commonwealth facility’s 172 MWs of capacity expires in May 2017, while a contract for the Hartwell facility’s 150 MWs of capacity expires in May 2019. In January and February 2004, we signed two agreements to sell an aggregate 215 MWs of our Rockingham facility’s net generating capacity, with terms beginning in 2006 and expiring in 2010. We also signed an agreement in January 2004 covering an additional 165 MWs of our Rockingham facility’s net generating capacity, which expires in September 2004.

The SERC region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERC’s estimated 2003 reserve margin of 53%, which significantly exceeds SERC’s target reserve margin of approximately 17%. This overcapacity has depressed energy and capacity values in this region and likely will continue to do so absent peak demand growth and/or plant retirements. Overcapacity is concentrated in the Entergy and Southern sub-regions of SERC, and these regions are unlikely to see reserve margins near target levels until after 2010. Overcapacity is less severe in the VACAR sub-region of SERC, where we believe market conditions may require new capacity additions within the next 3-5 years.

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West region—Western Electricity Coordinating Council (WECC). We own interests in five generating facilities with an aggregate net generating capacity of 1,199 MWs within WECC. The WECC regional market includes the Canadian provinces of Alberta and British Columbia, parts of Mexico and all or parts of the states of Arizona, California, Oregon, Nevada, New Mexico, Colorado, Wyoming, Idaho, Montana, Nebraska, Texas, South Dakota, Utah and Washington. Our generating capacity in the WECC represents less than 1% of the overall generating capacity in this region.

Of our 1,199 MWs of net generating capacity in the WECC, 1,156 MWs consists of our 50% share of the 2,312 MWs of facilities owned by West Coast Power. All of the West Coast Power facilities are located in southern California and the generation output of the facilities is substantially covered by a contract between one of our marketing subsidiaries, as agent for the facility owners, and the CDWR, which expires in December 2004. The agreement provides for a firm commitment of 600 MWs of on-peak capacity and 200 MWs of baseload capacity, in each case at a fixed price. The agreement also contains a contingent component pursuant to which the CDWR can elect to reserve up to an additional 1,500 MWs of on-peak capacity and 1,500 MWs of off-peak capacity, subject to required minimum reservation amounts of 500 MWs and 200 MWs, respectively. We receive a fixed capacity payment for any contingent amounts reserved as well as payments for contingent energy actually sold, which energy payments are based on fuel, operating and maintenance and start-up costs.

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

For a discussion of litigation and other legal proceedings related to energy market restructuring in California, the impact of current regulations on our WECC facilities and related uncertainty associated with the California wholesale market, please read Note 16—Commitments and Contingencies—Summary of Material Legal Proceedings California Market Litigation beginning on page

F-42.

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

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

The ERCOT region currently has excess generation capacity as a result of recent development projects. This overcapacity is evidenced by the NERC’s estimated 2003 reserve margin of 36%, which is significantly in excess of the ERCOT’s target minimum reserve margin of 12.5%. This overcapacity has depressed energy and capacity values in this region and likely will continue to do so absent peak demand growth and/or plant retirements. Based on current expectations of future demand growth and retirements, we believe that reserve margins are likely to return to target levels within the next 6-9 years.

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

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Natural Gas Liquids

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

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

Upstream Business

Our upstream business includes the gathering of natural gas production from oil and gas wells and processing this raw natural gas into merchantable natural gas by extracting natural gas liquids and removing impurities. We own interests in 20 gas processing plants, including 12 plants we operate. We also operate over 9,368 miles of natural gas gathering pipeline systems associated with the 12 operated facilities and two stand-alone gas gathering pipeline systems where gas is treated and/or processed at third-party plants. Our upstream assets are located in the high-growth oil and gas exploration and production areas of North Texas and Louisiana, and the mature Permian Basin of Texas and New Mexico. During 2003, we processed an average of 1.8 Bcf/d of natural gas and produced an average of 82,000 barrels per day of natural gas liquids, in each case, net to our ownership interests. We are also party to processing agreements with five third-party plants.

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

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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 gas pipeline specifications; the investment in extensive gathering systems to bring gas to a particular plant; the term of the gas supply contracts behind a processing plant; and the prevailing competitive factors when contracts are negotiated.

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

Field Plants. Field plants connect volumes of unprocessed gas from multiple onshore producing wells. Through extensive gathering systems, these volumes are aggregated into sufficient volumes to be economically processed to extract natural gas liquids and to remove water vapor, solids and other contaminants to provide marketable natural gas, commonly referred to in the industry as “residue gas.” The following map depicts our field plant assets, including our capacity, 2003 throughput and production levels. Our field plants are in the mature and prolific Permian Basin, located in West Texas and Southeast New Mexico, and in North Texas, where we are ideally situated to benefit from the high volume growth Barnett Shale production development.

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In our field plants we process natural gas primarily under POP contracts. In 2003, approximately 85% of the volumes processed were under POP settlement terms and approximately 15% were processed primarily under KW or WHP contracts. As a result of our successful efforts to restructure certain contracts from KW to POP contracts, approximately 98% of the volumes we process in our field plants are now settled under POP contracts. This is particularly important because the natural gas processed by all of these facilities contains natural gas liquids in sufficient quantities to require that they be processed to extract enough of the natural gas liquids to meet gas pipeline and market quality specifications. Having essentially all POP contracts removes the significant price spread risk associated with KW and WHP contracts and makes the key economic driver for our field plants the absolute price of both residue gas and natural gas liquids.

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

Straddle Plants. Straddle plants generally are situated on mainline natural gas pipelines. Our straddle plants are located on pipelines transporting natural gas from the Gulf of Mexico to key Midwest and East Coast natural gas markets. The following map depicts our straddle plant assets, including our capacity, 2003 throughput and production levels.

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

When it is not economical to extract natural gas liquids (i.e., when the value of the natural gas liquids is less than the value of gas on an equivalent Btu basis), most of the volumes processed under these hybrid contracts automatically convert to a fee-based processing arrangement. This fee is generally paid in the form of cash and/or a nominal percentage of the natural gas liquids processed. However, for some of these volumes, the producer and/or the processor have contract settlement election options. The producer can elect to either process or not process, generally on a POL basis. If the producer elects to not process, we often have the option to process on a KW basis. If we elect to not process, either we can cause the gas to bypass the plant, where such capabilities exist, or the producer pays us a per-unit fee to process the gas. The following charts show a volume breakdown of 2003 contract settlements for our straddle plants and an estimate of our 2004 contract mix. With the prevailing market conditions entering 2004, we anticipate 2004 settlements to be similar to the outcome in 2003.

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The results of our straddle plant operations are heavily dependent on the absolute price of natural gas liquids. This is particularly true when processing economics are favorable, as the hybrid contracts will settle under POL terms. When processing economics are less favorable, as they were in 2003, we do have some KW exposure to the frac spread. Our view is that strong natural gas prices will continue to depress the frac spread for the foreseeable future. However, our frac spread exposure is somewhat limited because most of the hybrid contracts in this price environment settle on fee terms, which are relatively insensitive to price movements that depress the frac spread.

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

Our field plants recovered an average of 4.24 gallons of natural gas liquids per Mcf of raw gas processed in 2003. The straddle plants recovered an average of 1.10 gallons of natural gas liquids per Mcf of raw gas processed in 2003. The component split of mixed natural gas liquids produced by our field and straddle plants in 2003 was as follows:

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

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

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Both types of processing agreements with ChevronTexaco allow either party to renegotiate the commercial terms for processing previously dedicated natural gas production effective in September 2006 and on each successive 10-year anniversary thereafter, for ChevronTexaco gas processed in field plants, and five years thereafter, for gas produced from the Gulf of Mexico and processed in Louisiana straddle plants. During 2003 and 2002, respectively, ChevronTexaco gas accounted for 46% and 27% of the total volume of gas we processed.

Downstream Business

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

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:

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

We fractionate volumes for customers, from both our own upstream operations and third parties, under contracts that typically include a base fee per gallon plus other fee components that are subject to adjustment for variable costs such as energy consumed in fractionation. We have ownership interests in three stand-alone fractionation facilities that are strategically located on the Texas and Louisiana Gulf Coast. We operate two of the facilities, one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. During 2003, these facilities fractionated an aggregate average of 167,000 gross barrels per day (net to Dynegy’s ownership interests). We also have an equity investment in a third fractionator located in Mont Belvieu, which is subject to a 1996 consent decree with the FTC that prevents us from participating in commercial decisions regarding rates paid by third parties for fractionation services.

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

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

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

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

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

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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. The agreements require us to obtain, on behalf of the refineries, natural gas liquids feedstocks that each refinery requires on a daily basis. These agreements extend through August 2006. Approximately 44% and 35% of the refinery services business’ natural gas liquids purchases in 2003 and 2002, respectively, were from ChevronTexaco.

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

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.

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

In 2003 and 2002, approximately 32% and 28%, respectively, of our natural gas liquids sales were made to ChevronTexaco or one of its affiliates pursuant to the refinery agreements discussed above and pursuant to an agreement we have with Chevron Phillips Chemical Company. In the latter agreement, we supply a significant portion of Chevron Phillips Chemical’s natural gas liquids feedstock needs in the Mont Belvieu area and collect a cents-per-barrel fee for storage and product delivery.

Customer Risk Management

Our CRM segment is comprised largely of our four remaining power tolling arrangements, as well as gas transportation contracts and our remaining gas and power trading positions. Pursuant to these power tolling arrangements, we are obligated to make aggregate payments of approximately $2.3 billion to our counterparties in exchange for access to power generated by their facilities. Given our decision to exit the CRM business, we no longer consider this access to power as key to our business strategy. We are actively pursuing opportunities to terminate, assign or renegotiate the terms of our contractual obligations related to some of these agreements.

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

CRM Obligations

Regarding our legacy gas and power trading positions, we have substantially reduced the size of our mark-to-market portfolio since October 2002, when we initiated our efforts to exit the CRM business. As of December 31, 2003, we have exited approximately 85% of our physical and financial gas business. We expect to have effectively exited this business by the end of 2007, with the exception of a minimal number of physical gas transactions that expire between 2010 and 2017. Our remaining CRM power business, exclusive of our power tolling arrangements, will be effectively exited by the end of 2005; with the exception of a minimum number of positions that will remain until 2010. We will continue our efforts to exit the remaining transactions as allowed by market liquidity and credit requirements.

Corporate and Other

Our Other results include corporate governance roles and functions, which are managed on a consolidated basis, and specialized support functions such as finance, accounting, risk control, tax, corporate legal, corporate human resources, administration and technology. Corporate general and administrative expenses, income taxes and

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corporate interest expenses, which we previously allocated among our operating divisions, are included in our other reported results, as are corporate-related other income and expense items. Interest expense associated with borrowings incurred by our operating divisions, such as our power generation facility financings, will continue to be reflected in the appropriate business segment’s results.

COMPETITION

Power Generation. Demand for power may be met by generation capacity based on several competing technologies, such as gas-fired, coal-fired or nuclear generation and power generating facilities fueled by alternative energy sources, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities and other energy service companies in the development and operation of energy-producing projects. We believe that our ability to compete effectively in this business will be driven in large part by our ability to achieve and maintain a low cost of production, primarily by managing fuel costs, and to provide reliable service to our customers. We believe our primary competitors in this business consist of approximately 15 companies.

Natural Gas Liquids. Our natural gas liquids businesses face significant and varied competitors, including major integrated oil companies, major pipeline companies and their marketing affiliates and national and local gas gatherers, processors, fractionators, brokers, marketers and distributors of varying sizes and experience. The principal areas of competition include obtaining gas supplies for gathering and processing operations, obtaining supplies of raw product for fractionation, purchase and marketing of natural gas liquids, residue gas, condensate and sulfur, and transportation of natural gas and natural gas liquids and storage of natural gas liquids. Competition typically is based on location and operating efficiency of facilities, reliability of services, delivery capabilities and price. We believe our primary competitors in this business consist of approximately 22 companies.

REGULATION

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

Please read “—Environmental and Other Matters” beginning on page 18 for a discussion of environmental regulations affecting our business.

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

In certain markets where we own power generation facilities, specifically California and New York, the FERC has, from time to time, approved temporary price caps on wholesale power sales or other market mitigation measures. In New York, the FERC approved and extended indefinitely an Automated Mitigation Procedures, or AMP, that caps bid prices based on the cost characteristics of power generating facilities, such as our DNE facilities. In February 2004, the FERC accepted, subject to certain modifications, the NYISO’s proposed real-time scheduling software, which we refer to as RTS. While the RTS further entrenches the AMP in the NYISO market system, the FERC did not permit the NYISO to extend the real-time AMP to areas outside New York City where our DNE facilities are located. Consequently, our DNE facilities are not presently subject to the real-time AMP.

The California energy crisis, which arose in 2000, precipitated a number of FERC actions related to the California energy market, and the Western market generally, in addition to price caps and market mitigation measures. These actions included investigations concerning alleged manipulation of energy prices in the West, including claims of false reporting of trading data to publications that publish energy indices, and complaints requesting the FERC to reform or void various long-term power sales contracts. Please read Note 16—Commitments and Contingencies – Summary of Material Legal Proceedings – FERC and Related Regulatory Investigations – Requests for Refunds beginning on page F-43 for further discussion of our California activities and related regulatory matters.

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

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

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

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

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

Natural Gas Regulation. The transportation, storage and sale for resale of natural gas in interstate commerce is subject to regulation by the FERC under the NGA and, to a lesser extent, the NGPA. The FERC regulates the rates interstate pipelines charge for interstate transportation and storage services. The FERC also has jurisdiction over, among other things, the construction and operation of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion, acquisition, disposition, or abandonment of such facilities; maintenance of accounts and records; depreciation and amortization policies; and transactions with and conduct of interstate pipelines relating to affiliates. Venice Gathering System, in which we own a minority interest, is a regulated interstate pipeline. Like other interstate pipelines, Venice Gathering System must comply with FERC’s open-access transportation regulations. The FERC continues to review and modify its open-access regulations and some appeals are pending.

State Regulatory Reforms. Our domestic power generation business is subject to various regulations from the states in which we operate. Proposed reforms to these regulations, and in some cases, repeal of measures implementing retail competition, are proceeding in several states, including California, the results of which could affect our operations.

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Legislation. The U.S. Congress is considering passage of comprehensive energy legislation that will impact us. The legislation includes enhanced reliability measures, various transmission improvement and financing provisions, and new market reporting requirements. We cannot predict with certainty if or when the U.S. Congress will finish its work on the energy legislation and send it to the President for signature or what effect any final legislation will have.

ENVIRONMENTAL AND OTHER MATTERS

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

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

Environmental Expenditures. Our aggregate expenditures for compliance with laws and regulations related to the protection of the environment were approximately $50 million in 2003, compared to approximately $82 million in 2002 and approximately $81 million in 2001. We estimate that total environmental expenditures (both capital and operating) in 2004 will be approximately $20 million. A majority of our environmental expenditures relate to the federal Clean Air Act and comparable state laws and regulations, and the reduced amount for 2004 reflects the fact that we have already expended significant capital to comply with current regulations. Changes in environmental regulations or the outcome of litigation could result in additional requirements that could necessitate increased future spending. Please read “—Environmental and Other Matters—The Clean Air Act” below for a discussion of the litigation brought by the Environmental Protection Agency against us relating to activities at our Baldwin generating station in Illinois.

The Clean Air Act. The Clean Air Act and comparable state laws and regulations relating to air emissions impose responsibilities on owners and operators of sources of air emissions, including requirements to obtain construction and operating permits and annual compliance and reporting obligations. Although the impact of future air quality regulations cannot be predicted with certainty, these regulations are expected to become increasingly stringent, particularly for electric power generating facilities. Current Clean Air Act requirements include the following:

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

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

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

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

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

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In the wake of the September 11, 2001 terrorist attacks on the United States, the Coast Guard has developed a security guidance document for marine terminals and has issued a security circular that defines appropriate countermeasures for protecting them and explains how the Coast Guard plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the Coast Guard, we have specifically identified certain of our facilities as marine terminals and therefore potential terrorist targets. In compliance with the Coast Guard guidance, we performed vulnerability analyses on such marine terminals. We are performing further analyses that likely will result in additional security measures and procedures, which measures or procedures have the potential for increasing our costs of doing business. Regardless of the steps taken to increase security, however, we cannot be assured that our marine terminals will not become the subject of a terrorist attack. Please read “—Operational Risks and Insurance” beginning on page 21 for further discussion.

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

Subject to resolution of the complaints filed by the EPA and the DOJ against DMG, which are described in Note 16—Commitments and Contingencies—Summary of Material Legal Proceedings—Baldwin Station Litigation beginning on page F-41, management believes that it is in substantial compliance with, and is expected to continue to comply in all material respects with, applicable environmental statutes, regulations, orders and rules. Further, to management’s knowledge, other than the previously referenced complaints, there are no existing, pending or threatened actions, suits, investigations, inquiries, proceedings or clean-up obligations by any governmental authority or third-party relating to any violations of any environmental laws with respect to our assets or pertaining to any indemnification obligations with respect to properties we previously owned or operated, which could reasonably be expected to have a material adverse effect on our operations, cash flows and financial condition.

Ongoing Environmental Initiatives

Following is a description of ongoing environmental initiatives with respect to which significant capital expenditures could be incurred, depending on the outcome.

Multi-Pollutant Air Emission Initiatives. Various multi-pollutant proposals have been introduced at the federal and state level. Examples are the “Clear Skies Act of 2003” and the Interstate Air Quality rule announced in late 2003. These proposals are aimed at long-term reductions of multiple pollutants produced from electric generating facilities. Additional EPA initiatives include designation of areas as attainment, non-attainment or non-classifiable for the new particulate matter (PM) 2.5 standard. The PM 2.5 standard is aimed at the reduction of fine (smaller than 2.5 microns in diameter) particulate matter. Fossil fuel-fired power plants in the United States would be affected by the adoption of these programs or other multi-pollutant legislation currently proposed by Congress addressing similar issues. Such programs would require compliance to be achieved either by the installation of pollution controls, the purchase of emission allowances, the curtailment of operations or some combination thereof.

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

Water Issues. Our wastewater discharges are permitted under the Clean Water Act and analogous state laws. These permits are subject to review every five years. The state-issued water discharge permits associated with the DNE facilities expired in 1992. However, under New York State law, each permit remains in effect and allows for continued operation under the terms of the original permits, given that timely applications requesting renewal were

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

In November 2001, the EPA issued rules imposing additional technology-based requirements on new cooling water intake structures. The EPA issued a final rule for existing intake structures in February 2004. We believe that the requirements of this new rule are consistent with the provisions proposed in the Danskammer permit application. As noted above, the draft permit is the subject of administrative challenges by both DNE and environmental groups. We are evaluating the impact of the new rule on our other facilities; however, we cannot predict what plant modifications may be necessary to comply with this final rule.

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

Global Climate Change. The international treaty relating to global warming (commonly known as the Kyoto Protocol) would have required reductions in emissions of greenhouse gases, primarily carbon dioxide and methane, by several energy companies, including Dynegy, if adopted by the United States. The treaty has not been ratified by the Senate and is unlikely to become effective in the United States. Nevertheless, it has prompted the introduction of several federal and state legislative and regulatory proposals that would address climate change issues through voluntary emission reductions, emissions trading programs or mandatory emission reductions. If any of these proposals become law, they could affect our business by imposing substantial additional administrative or capital expenditure burdens. We are currently evaluating the impact of the various proposals on our operations.

For these ongoing matters, it is difficult to predict the form that proposed rules will ultimately take and the impact that such rules, if approved, will have on our operations. With respect to the Danskammer water permit, we similarly cannot predict the results of the related administrative proceedings or their affects on us. It is possible that the result of these ongoing initiatives, as well as the outcome of the administrative proceedings surrounding our Danskammer water permit, could require us and other similarly situated companies to incur material environmental compliance costs over a period of years, beginning as early as 2005.

OPERATIONAL RISKS AND INSURANCE

We are subject to all risks inherent in the various businesses in which we operate. These risks include, but are not limited to, explosions, fires, terrorist attacks, product spillage, weather, nature, inadequate maintenance of rights-of-way and the public, which could result in damage to or destruction of operating assets and other property, or could result in personal injury, loss of life or pollution of the environment, as well as curtailment or suspension of operations at the affected facility. We maintain general public liability, property/boiler and machinery and business interruption insurance in amounts that we consider to be appropriate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment. The costs associated with these insurance coverages have increased significantly during recent periods, and will more than likely continue to increase in the future. The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our potential inability to secure these levels and types of insurance in the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates we consider commercially reasonable.

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In our CRM segment, we also face market, price, credit and other risks relative to our exit from the CRM business. Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 60 for further discussion of these risks.

In addition to these commercial risks, we also face the risk of reputational damage and financial loss as a result of inadequate or failed internal processes and systems. A systems failure or failure to enter a transaction properly into the records and systems may result in an inability to settle a transaction in a timely manner or cause a contract breach. Our inability to implement the policies and procedures that we have developed to minimize these risks could increase our potential exposure to reputational damage in the industries in which we compete and to financial loss. Please read Item 9A. Controls and Procedures beginning on page 64 for further discussion of our internal control systems.

SIGNIFICANT CUSTOMER

For the years ended December 31, 2003, 2002 and 2001, approximately 20%, 19% and 12%, respectively, of our consolidated revenues and approximately 26%, 51% and 50%, respectively, of our consolidated cost of sales were derived from transactions with ChevronTexaco and its subsidiaries. In addition, for the years ended December 31, 2003, 2002 and 2001, approximately 11%, 9% and 14%, respectively, of our consolidated revenues were derived from transactions with West Coast Power. No other customer accounted for more than 10% of our consolidated revenues or consolidated cost of sales during 2003, 2002 or 2001.

EMPLOYEES

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

Item 2. Properties

We have included descriptions of the location and general character of our principal physical operating properties by segment in “Item 1. Business” beginning on page 3. Those descriptions are incorporated herein by this reference. Substantially all of our assets, including the physical operating properties we own, are pledged as collateral with respect to our amended credit facility. Please read Note 12—Debt beginning on page F-31 for further discussion of the amended credit facility.

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

Item 3. Legal Proceedings

For a description of our material legal proceedings, please read Note 16—Commitments and Contingencies beginning on page F-40, which is incorporated herein by reference.

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

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

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PART II

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

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

Securities Authorized for Issuance Under Equity Compensation Plans

We have no equity compensation plans pursuant to which our employees are granted stock options or other equity compensation. Our employees do, however, receive stock-based compensation pursuant to plans maintained by our parent, Dynegy. Please read Dynegy’s Annual Report on Form 10-K for the fiscal year ended December 31, 2003 for a discussion of these plans.

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Item 6. Selected Financial Data

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

Dynegy’s Selected Financial Data

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

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

OVERVIEW

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

Following is a brief discussion of each of our three business segments, including a list of key factors that have affected, and are expected to continue to affect, their respective earnings and cash flows. We also present a brief discussion of our corporate-level expenses. This “Overview” section concludes with a summary of our current liquidity position and items that could impact our liquidity position in 2004 and beyond. Please note that this “Overview” section is merely a summary and should be read together with the remainder of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, as well as the audited consolidated financial statements, including the notes thereto, and the other information included in this report.

Power Generation. Our power generation business owns or leases more than 12,700 MWs of net generating capacity located in six regions of the United States. Our power generating fleet is diversified by facility type (base load, intermediate and peaking), fuel source and geographic location. We generate earnings and cash flows in this business through sales of energy and capacity.

The primary factors impacting our power generation earnings and cash flows are the prices for power and, to a lesser extent, natural gas, which in turn are largely driven by supply and demand. Demand for power can vary regionally due to, among other things, weather and general economic conditions. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation. We also are impacted by the relationship between prices for power and natural gas, commonly referred to as the “spark spread,” and its impact on the cost of generating electricity. However, we believe that our significant coal-fired and fuel oil generating facilities partially mitigate our sensitivity to changes in the spark spread, in that coal and fuel oil prices are relatively stable and insensitive to changes in gas prices, and position us for potential increases in earnings and cash flows in an environment where both power and gas prices increase. Please read “—Liquidity and Capital Resources—Internal Liquidity Sources—Cash Flows from Operations” beginning on page 34 for a discussion of our views on the current pricing environment and its anticipated long-term recovery.

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

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

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

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

The earnings and cash flows that we generate in this business are sensitive to natural gas and natural gas liquids prices and the relationship between the two, commonly referred to as the “frac spread.” In our upstream business, we continued the restructuring of our contract portfolio in 2003. As a result, our current contract mix has reduced our exposure to frac spread risk. Please read Item 1. Business—Segment Discussion—Natural Gas Liquids—Upstream Business beginning on page 8 for a detailed discussion of our current upstream contract mix.

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

Customer Risk Management. Our customer risk management business primarily consists of our four remaining power tolling arrangements and related gas transportation contracts, as well as our legacy gas and power trading positions. We have significant, long-term fixed obligations associated with our tolling and gas transportation arrangements, which obligations substantially exceed the earnings and cash flows we expect to generate in connection with these arrangements. Our ability to mitigate partially the negative impact of these arrangements on our earnings and cash flows depends on the price of power and the spark spread in the regions where the tolling plants are located, as well as our ability to re-market the related capacity under the transportation arrangements. It also will be significantly impacted by our ability to restructure or terminate one or more of our power tolling arrangements, which we expect would require a significant cash payment.

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Regarding our legacy gas and power trading positions, we have substantially reduced the size of our portfolio relative to when we were primarily a marketing and trading company. Please read Item 1. Business— Segment Discussion—Customer Risk Management beginning on page 15 for further discussion.

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

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

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

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

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LIQUIDITY AND CAPITAL RESOURCES

Debt Maturities

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

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

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

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

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

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

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

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

Collateral Postings

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

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

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

Going forward, we expect counterparties’ collateral demands to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their view of our creditworthiness. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for at least the next 12 months. Over the longer term, we expect to achieve incremental reductions associated with the completion of our exit from the customer risk management business. Please see “—Results of Operations—2004 Outlook—CRM Outlook” beginning on page 49 for a discussion of the expected collateral roll-off from this business.

Disclosure of Contractual Obligations and Contingent Financial Commitments

We incur contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contracts, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related operating activities. Financial commitments represent contingent obligations, such as financial guarantees, that become payable only if specified events occur. Details on these obligations are set forth below.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2003. Cash obligations reflected are not discounted and do not include related interest, accretion or dividends.

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

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Additionally, we have entered into various joint ventures principally to share risk or optimize existing commercial relationships. These joint ventures maintain independent capital structures and, where necessary, have financed their operations on a non-recourse basis to us. Please read Note 9—Unconsolidated Investments beginning on page F-26 for further discussion of these joint ventures.

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

Operating Leases. Operating leases includes the minimum lease payment obligations associated with our DNE leveraged lease. For additional information, please read “—Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease” beginning on page 32. Amounts also include minimum lease payment obligations associated with office and office equipment leases.

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

In addition, capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $507 million.

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

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

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Contingent Financial Obligations

The following table provides a summary of our contingent financial obligations as of December 31, 2003 on an undiscounted basis. These obligations represent contingent obligations that may require a payment of cash upon the occurrence of specified events.

Off-Balance Sheet Arrangements

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

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

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

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As of December 31, 2003, future lease payments are $60 million for each year 2004 through 2006, with $1.3 billion in the aggregate due from 2007 through lease expiration. The Roseton lease expires on February 8, 2035 and the Danskammer lease expires on May 8, 2031. We have no option to purchase the leased facilities at the end of their respective lease terms. We have guaranteed the lessees’ payment and performance obligations under their respective leases on a senior unsecured basis. At December 31, 2003, the present value (discounted at 10%) of future lease payments was $758 million.

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

If one or more of the leases were to be terminated because of an event of loss, because it had become illegal for the applicable lessee to comply with the lease or because a change in law had made the facility economically or technologically obsolete, we would be required to make a termination payment in an amount sufficient to redeem the pass through trust certificates related to the unit or facility for which the lease was terminated at par plus accrued and unpaid interest. As of December 31, 2003, the termination payment at par would be $997 million for all of the DNE facilities, which exceeds the $920 million we received on the sale of the facilities. If a termination of this type were to occur with respect to all of the DNE facilities, it would be difficult for us to raise sufficient funds to make this termination payment. Alternatively, if one or more of the leases were to be terminated because we determine, for reasons other than as a result of a change in law, that it has become economically or technologically obsolete or that it is no longer useful to our business, we must redeem the related pass through trust certificates at par plus a make-whole premium in an amount equal to the discounted present value of the principal and interest payments still owing on the certificates being redeemed less the unpaid principal amount of such certificates at the time of redemption. For this purpose, the discounted present value would be calculated using a discount rate equal to the yield to maturity on the most comparable U.S. treasury security plus 50 basis points.

Capital Expenditures

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

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

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We expect capital expenditures for 2004 to approximate $235 million. This primarily includes maintenance capital projects, environmental projects, contributions to equity investments and limited GEN and NGL development projects. The capital budget is subject to revision as opportunities arise or circumstances change. Estimated funds budgeted for the aforementioned items by segment in 2004 are as follows (in millions):

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

As reflected in this section, the capital spending in our NGL segment includes 100% of the expenditures of our consolidated partnerships, Versado Gas Processors, LLC and Cedar Bayou Fractionators, LP. Our ownership percentages of these partnerships are 63% and 88%, respectively, and net funding equal to our ownership percentage is achieved through adjustments to partnership distributions. Adjusted for our partners’ share of capital expenditures, our expenditures would have been $45 million in 2003 and are expected to be $67 million in 2004.

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

Financing Trigger Events

Our debt instruments and other financial obligations include provisions, which, if not met, could require early payment, additional collateral support or similar actions. These trigger events include leverage ratios and other financial covenants, insolvency events, defaults on scheduled principal or interest payments, changes in law resulting in loss of tax-exempt status on certain bond issuances, acceleration of other financial obligations and change of control provisions. We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and have not executed any transactions that require us to issue equity based on credit ratings or other trigger events.

Commitments and Contingencies

Please read Note 16—Commitments and Contingencies beginning on page F-40, which is incorporated herein by reference, for a discussion of our commitments and contingencies.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our $1.1 billion revolving credit facility, which is scheduled to mature on February 15, 2005.

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

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

As described above, much of the restructuring work that we have done has extended our significant debt maturities to 2008 and beyond, positioning us to benefit from this expected long-term recovery in the U.S. power markets. Our future financial condition and results of operations will be materially adversely affected if the U.S. power markets fail to recover in accordance with our expectations or if we experience significant price deterioration in the upstream portion of the NGL segment. Please read Item 1. Business—Segment Discussion—Power Generation beginning on page 3 for a discussion of our current views on supply and demand in the regions where our power generation business operates.

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

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

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

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

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

External Liquidity Sources

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

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

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

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

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

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

Capital-Raising Transactions. As part of Dynegy’s ongoing efforts to develop a capital structure that is more closely aligned with the cash-generating potential of its asset-based businesses, Dynegy has stated that it intends to explore additional capital-raising transactions both in the near- and longer term. These transactions could include public or private equity issuances. Dynegy’s ability to issue public equity is enhanced by its effective shelf registration statement, under which it has approximately $430 million in remaining availability. However, the receptiveness of the capital markets to a public equity issuance cannot be assured and may be negatively impacted by, among other things, Dynegy’s non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond our control. Dynegy’s ability to issue private equity could be similarly affected and, if such an issuance were completed, would likely be more costly, both in terms of required rates of return and other requirements typically associated with this type of transaction. Any issuance of equity likely would have other effects as well, including dilution of the interests of Dynegy’s shareholders.

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

Conclusion

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

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

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

Our ability to generate operating cash flows from our asset-based energy businesses will be impacted by a number of factors, some of which are beyond our control, including weather, commodity prices, particularly for power and natural gas, and the success of our ongoing efforts to manage operating costs and capital expenditures. Over the longer term we believe that power prices will improve in some or all of the regions in which we operate as the supply-demand imbalance for power decreases. Much of the restructuring work that we did in 2003 has extended our significant debt maturities from 2005-2006 to 2008 and beyond, positioning us to benefit from earnings and growth opportunities associated with this expected recovery in the U.S. power markets. Conversely, although depressed frac spreads have negatively impacted our NGL segment’s downstream operations, our upstream business is currently operating in a relatively favorable pricing environment. Our future financial condition and results of operations will be materially affected if the U.S. power markets fail to recover in accordance with our expectations or if we experience significant pricing deterioration in the NGL segment.

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

RESULTS OF OPERATIONS

Overview and Discussion of Comparability of Results. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for 2003, 2002 and 2001. At the end of this section, we have included our 2004 outlook for each segment.

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

Prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business, then referred to as the WEN segment. Please read Note 20—Segment Information beginning on page F-57 for a discussion of the impact of comparing segment results period over period. Regarding our results of operations for 2003, 2002 and 2001, the impact of acquisition and disposition activity reduces the comparability of some of our historical financial and volumetric data. Lastly, recent accounting pronouncements have affected our financial results, particularly those of our CRM business, so as to further reduce the comparability of some of our historical financial data. For example, the rescission of EITF Issue 98-10, effective January 1, 2003, has reduced the number of contracts accounted for on a mark-to-market basis in the 2003 period as compared to the 2002 and 2001 periods. Please read “—Cumulative Effect of Change in Accounting Principles” beginning on page 47 for further discussion.

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

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

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

Year Ended December 31, 2003