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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: 1-15659

DYNEGY 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:

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   x    No  ¨

The aggregate market value of the voting and non-voting equity held by non-affiliates of the registrant as of June 30, 2003, computed by reference to the closing sale price of the registrant’s common stock on the New York Stock Exchange on such date, was $1,155,609,441, using the definition of beneficial ownership contained in Rule 13d-3 under the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers.

Number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Class A common stock, no par value per share, 279,871,186 shares outstanding as of February 23, 2004; Class B common stock, no par value per share, 96,891,014 shares outstanding as of February 23, 2004.

DOCUMENTS INCORPORATED BY REFERENCE. Part III (Items 10, 11, 12, 13 and 14) incorporates by reference portions of the Notice and Proxy Statement for the registrant’s 2004 Annual Meeting of Shareholders, which will be filed not later than 120 days after December 31, 2003.

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DYNEGY INC.

FORM 10-K

TABLE OF CONTENTS

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PART I

DEFINITIONS

As used in this Form 10-K, the abbreviations contained herein have the meanings set forth in the glossary beginning on page F-79. Additionally, the terms “Dynegy,” “we,” “us” and “our” refer to Dynegy Inc. and its subsidiaries, 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 three areas of the energy industry: power generation; natural gas liquids; and regulated energy delivery.

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, we entered into an agreement to sell Illinois Power Company, which currently comprises our regulated energy delivery business, to Ameren Corp. We are 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 us $400 million in cash, subject to working capital adjustments, and place $100 million into escrow, subject to full release to us on December 31, 2010 or earlier upon the occurrence of specified events. We intend to use these proceeds to pay transaction fees and expenses and to reduce our outstanding debt, including certain debt owed to ChevronTexaco. In addition to reducing our substantial leverage, the closing also would reinforce our business strategy of focusing on unregulated energy businesses.

Dynegy began operations in 1985 and became incorporated in the State of Illinois in 1999 in anticipation of our February 2000 acquisition of Illinova Corporation. 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.

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SEGMENT DISCUSSION

Beginning in 2003, we are reporting the financial results of the following four 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 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 21 and “—Environmental and Other Matters” beginning on page 24 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.

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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 our agreement to sell Illinois Power to Ameren, which we are 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 we are 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 “—Regulated Energy Delivery—Agreed Sale to Ameren” beginning on page 18 and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—2004 Outlook—REG Outlook beginning on page 65 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

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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.

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 17—Commitments and Contingencies—Summary of Material Legal Proceedings—California Market Litigation beginning on page F-53.

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-30.

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.

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International. In addition to our U.S. generating assets, as of December 31, 2003, we owned interests in three generating facilities with an aggregate net generating capacity of 81 MWs located in Costa Rica, Panama, and Jamaica. The capacity consists of wind projects, natural gas and heavy fuel oil. All of this capacity is under contract for terms ranging from one to 12 years. Our ownership interests in these international projects range from 18% to 100%. Our 18% interest in a 74 MW generation asset in Jamaica was sold in January 2004 for $5.5 million. We are continuing to pursue opportunities to sell our other interests in all remaining international projects, none of which are considered core to our power generation business.

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.

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.

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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.

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.

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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.

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.

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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.

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.

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Downstream Business

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

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

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

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We fractionate volumes for customers, from both our own upstream operations and third parties, under contracts that typically include a base fee per gallon plus other fee components that are subject to adjustment for variable costs such as energy consumed in fractionation. We have ownership interests in three stand-alone fractionation facilities that are strategically located on the Texas and Louisiana Gulf Coast. We operate two of the facilities, one at Mont Belvieu, Texas and the other at Lake Charles, Louisiana. During 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.

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

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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.

Regulated Energy Delivery

General. Our regulated energy delivery segment consists of our Illinois Power Company subsidiary, which we acquired through a merger with Illinova in February 2000. Illinois Power is a regulated public utility based in Decatur, Illinois, and is engaged in the transmission, distribution and sale of electric energy and the distribution, transportation and sale of natural gas in the state of Illinois. Illinois Power provides retail electric and natural gas service to residential, commercial and industrial consumers in substantial portions of northern, central and southern Illinois. Illinois Power also currently supplies electric transmission service to electric cooperatives, municipalities and power marketing entities in the state of Illinois.

From February 1, 2002 through July 31, 2002, this segment also included the results of Northern Natural. We acquired Northern Natural from Enron Corp. in connection with our terminated merger and subsequently sold Northern Natural to MidAmerican Energy Holdings Company in August 2002. Northern Natural is accounted for as a discontinued operation in the accompanying financial statements. Please read Note 3—Discontinued Operations, Dispositions, Contract Terminations and Acquisitions—Discontinued Operations—Northern Natural beginning on page F-18 for further discussion.

Electric Business. Illinois Power supplies electric service at retail to an estimated aggregate population of 1,372,000 in 313 incorporated municipalities, adjacent suburban and rural areas, and numerous unincorporated communities. As of year-end 2003, Illinois Power served more than 590,000 active electric customers. Illinois Power owns an electric distribution system of 37,765 circuit miles of overhead and underground lines. For the year ended December 31, 2003, Illinois Power delivered a total of 18,601 million KWH of electricity. Illinois Power also owns a 1,672-circuit-mile electric transmission system.

Regulators historically have determined Illinois Power’s rates for electric service—the ICC at the retail level and the FERC at the wholesale level. These rates are designed to recover the cost of service and to allow Illinois Power’s shareholders the opportunity to earn a reasonable rate of return. Please read “—Regulation—Illinois Power Company” beginning on page 22 for further discussion of the regulatory environment in which Illinois Power operates, including the retail electric rate freeze that extends through 2006.

Illinois Power owns no significant generation assets and obtains the majority of the electricity that it supplies to its retail customers through power purchase agreements with AmerGen and DMG. The AmerGen agreement was entered into in connection with the sale of the Clinton nuclear generation facility to AmerGen in December 1999. Illinois Power is obligated to purchase a predetermined percentage of Clinton’s electricity output through 2004 at fixed prices that exceed current and projected wholesale prices. The AmerGen agreement does not obligate AmerGen to acquire replacement power for Illinois Power in the event of a curtailment or shutdown at Clinton. Please see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Disclosure of Contractual Obligations and Contingent Financial Commitments—Contractual Obligations—Conditional Purchase Obligations beginning on page 43 for further information.

Illinois Power has a power purchase agreement with DMG that provides approximately 70% of Illinois Power’s capacity requirements through December 2004. This agreement, which is served through Illinois Power’s former generation facilities now owned by DMG, 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 power purchase agreement, DMG bears ultimate responsibility for serving the load as the provider of last resort; it also supplies all ancillary services required by Illinois Power. As a result, should Illinois Power be unable to obtain sufficient power to meet its load requirements from the DMG

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and AmerGen facilities, DMG is obligated to acquire such power for Illinois Power, likely through open market purchases at current market prices. Illinois Power is subject to market price risk with respect to any such power purchases.

In connection with our agreement to sell Illinois Power to Ameren, which we are targeting for closing by the end of 2004, we also agreed, conditioned on 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. DMG will no longer be the provider of last resort to Illinois Power under this agreement. If the Illinois Power sale closes before year-end, the parties would continue under the current agreement through its December 31, 2004 expiration. If we are 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 23—Subsequent Event beginning on page F-77 for further discussion.

Please refer to the chart below for a breakdown of Illinois Power’s energy purchases in 2003.

Sources of Illinois Power Energy Purchases in 2003

Electric Revenues by Customer Class. The following chart depicts the sources of revenue by customer class during 2003 from sales of electricity by Illinois Power.

Electric Revenues for the Year Ended December 31, 2003 (in millions)

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Gas Business. Illinois Power supplies retail natural gas service to an estimated population of more than 1 million in 258 incorporated municipalities and adjacent areas. As of year-end 2003, Illinois Power served nearly 415,000 active gas customers. Illinois Power owns 763 miles of natural gas transportation pipelines and 7,669 miles of natural gas distribution pipelines. Illinois Power purchases the gas that it sells at retail from various suppliers pursuant to contracts that generally have a duration of one to 12 months. Our customers’ gas price volatility during the typical heating season is partially mitigated through the use of forward pricing instruments and the intrinsic price hedge characteristics of natural gas storage. In addition, natural gas storage enhances the operational reliability of our gas system.

Illinois Power owns seven underground natural gas storage fields with a total capacity of approximately 11.6 billion cubic feet and a total deliverability on a peak day of approximately 339 million cubic feet. To supplement the capacity of Illinois Power’s seven underground storage fields, Illinois Power has contracted with natural gas pipelines for an additional 5.4 billion cubic feet of underground storage capacity, representing an additional total deliverability on a peak day of approximately 93 million cubic feet. The operation of these underground storage facilities permits Illinois Power to increase deliverability to its retail gas customers during peak load periods by extracting natural gas that was previously placed in storage during off-peak months.

The ICC determines rates that Illinois Power may charge for retail gas service. As with the rates that Illinois Power is allowed to charge for retail electric service, these rates are designed to recover the cost of service and to allow Illinois Power’s shareholders the opportunity to earn a reasonable rate of return. Illinois Power’s rate schedules contain provisions for passing through to its customers any increases or decreases in the cost of natural gas, subject to an annual prudency review by the ICC. For the year ended December 31, 2003, Illinois Power delivered a total of 778 million therms of natural gas.

Gas Revenues by Customer Class. The following chart depicts the sources of revenue by customer class during 2003 from sales of gas by Illinois Power.

Gas Revenues for the Year Ended December 31, 2003 (in millions)

Intercompany Note Receivable. In October 1999, Illinois Power transferred its wholly-owned fossil generating assets to Illinova in exchange for an unsecured note receivable of approximately $2.8 billion. These assets now comprise DMG’s generating fleet. The intercompany note matures in September 2009 and bears interest at an annual rate of 7.5%, payable semi-annually in April and October. At December 31, 2003, the principal outstanding under the note receivable was $2.3 billion. The intercompany note and the related interest income are eliminated in consolidation as intercompany transactions and, therefore, are not reflected in our REG segment’s results as reported herein. In connection with our agreement to sell Illinois Power to Ameren, we are

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required, as a condition to Ameren’s obligation to close the transaction, to eliminate the intercompany note. Please read Note 23—Subsequent Event beginning on page F-77 for further discussion.

Agreed Sale to Ameren. In February 2004, we entered into an agreement to sell Illinois Power and our 20% interest in the Joppa power generation facility to Ameren. We are targeting closing the transaction, which is contingent on the receipt of required regulatory approvals and other conditions, by the end of 2004. Please read Note 23—Subsequent Event beginning on page F-77 for further discussion.

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.

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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 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 Illinois Power mortgage bonds and our power generation facility financings, will continue to be reflected in the appropriate business segment’s results. Other results for the periods presented also include our discontinued global communications business.

The communications business was established during the fourth quarter 2000 and included an optically switched, mesh fiber-optic network with more than 16,000 route miles that reached 44 cities in the United States. During the first quarter 2003, we sold our European communications business, which operated a high-capacity, broadband network with access points in 32 cities throughout Western Europe. During the second quarter 2003, we sold our U.S. communications business. Since we have substantially completed our exit from the global communications business, we do not expect that this business will be included in our Other results for future periods.

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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.

Regulated Energy Delivery. Illinois Power is authorized, by statute or certificates of public convenience and necessity, to conduct operations in the territories it serves. In addition, Illinois Power operates under franchises and license agreements granted to it by the communities it serves.

Illinois Power’s electric utility business faces significant competition brought about by the implementation of a customer choice structure in the state of Illinois. Under the Electricity Customer Choice and Rate Relief Law of 1997, commonly referred to as the Customer Choice Law, residential electricity customers were given a 15% decrease in their base electric rates beginning August 1, 1998 and an additional 5% decrease in base electric rates beginning May 1, 2002. The Customer Choice Law also implemented a return on equity collar that is further described below under “—Regulation—Illinois Power Company” beginning on page 22. Additionally, the Customer Choice Law phased in a right of customers to choose their electricity suppliers, with specified non-residential customers being granted this right in October 1999, all then-remaining non-residential customers being granted this right beginning on December 31, 2000 and all residential customers being granted this right effective May 1, 2002. Customers who buy their electricity from a supplier other than the local electric utility are required to pay applicable transition charges to the utility through the year 2006. These charges are not intended to compensate the electric utilities for all revenues lost because of customers buying electricity from other suppliers.

Although no parties have requested certification from the ICC to provide residential electric service pursuant to the Customer Choice Law, this could change. Additionally, there are eight registered energy providers for non-residential service. We face competition from these other energy providers; by the end of 2003, commercial and industrial customers representing approximately 18% of Illinois Power’s eligible commercial and industrial load had switched to other energy providers, and we estimate that by the end of 2004, customers representing an additional 8% of our commercial and industrial load will also have switched to other such providers. Competition typically is based on price and service reliability.

With respect to Illinois Power’s gas distribution business, absent extraordinary circumstances, potential competitors are barred from constructing competing systems in Illinois Power’s service territories by a judicial doctrine known as the “first in the field” doctrine. In addition, the high cost of installing duplicate distribution facilities would render the construction of a competing system impractical. Additionally, competition in varying degrees exists between natural gas and other fuels or forms of energy available to consumers in Illinois Power’s service territories.

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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 24 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 17—Commitments and Contingencies—Summary of Material Legal Proceedings—FERC and Related Regulatory Investigations—Requests for Refunds beginning on page F-54 for further discussion of our California activities and related regulatory matters.

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

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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. For further discussion, please see ”—Regulation—Illinois Power Company” below.

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.

Illinois Power Company. Illinois Power is an electric utility company as defined in PUHCA. Its direct parent company, Illinova, and Dynegy are holding companies as defined in PUHCA. Although Illinova and Dynegy are generally exempt from regulation under PUHCA because of their status as intrastate holding companies, they remain subject to regulation under PUHCA with respect to the acquisition of certain voting securities of other domestic public utility companies and utility holding companies.

Illinois Power is also subject to regulation by the FERC under the FPA as to transmission rates, terms and conditions of service, the acquisition and disposition of transmission facilities and other matters. The FERC has declared Illinois Power exempt from the NGA and related FERC orders, rules and regulations. Under the FERC’s new standard of conduct rules, which are designed to ensure that transmission providers do not provide preferential access to service or information to affiliates, Illinois Power is required to implement new standards of conduct by June 2004.

Illinois Power is further subject to regulation by the State of Illinois and the ICC. The Illinois Public Utilities Act was significantly modified in December 1997 by the Customer Choice Law, but the ICC still has broad powers of supervision and regulation with respect to rates, charges and other matters. Under the Customer Choice Law, Illinois Power must continue to provide bundled retail electric services at tariff rates to all who choose to continue to take bundled service and must provide unbundled electric distribution services at tariff rates to all customers who choose this service. The Customer Choice Law also froze retail bundled rates through December 31, 2004, except for mandated reductions in residential bundled rates of 15% in 1998 and 5% in 2002, and requires the electric utility to refund a portion of its earnings to customers if its earnings exceed a specified ceiling. P.A. 92-0537, enacted in June 2002, extended the rate freeze for bundled customers and the earnings sharing provisions through December 31, 2006. In addition, pursuant to the Customer Choice Law and P.A. 92-0537, Illinois Power has eliminated its fuel adjustment clause and may not reinstate it until January 1, 2007.

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The Customer Choice Law requires Illinois Power to participate in an RTO. Ultimately, any choice that Illinois Power makes regarding which RTO to join will be subject to review and approval by the FERC. For several months prior to the execution of the purchase agreement with Ameren concerning the Illinois Power sale, Illinois Power had suspended its efforts to join an RTO in light of this possible sale. Pursuant to this purchase agreement, Illinois Power has agreed to submit, within 90 days following the purchase agreement date, an application to join the Midwest Independent Transmission System Operator, Inc., which we refer to as “MISO.” This application will be conditioned on FERC approval of the Illinois Power sale, and the timely submission of this application is a condition to the closing of the Illinois Power sale.

Illinois Power is currently participating in a FERC proceeding relating to rates charged for regional through-and-out transmission service. The FERC has ordered Illinois Power and other Midwest transmission providers to eliminate the charge for these services commencing on or after May 1, 2004 where the power transmitted is ultimately delivered to PJM, the Midwest ISO or to the other unaffiliated Midwest transmission owners. FERC’s decision in this proceeding is subject to requests for rehearing and appeal.

In October 2002, the ICC issued an order approving a petition submitted by Illinois Power to enter into an agreement with Dynegy and its affiliates that would allow for certain payments due to Dynegy (or certain Dynegy affiliates) under a Services and Facilities Agreement or certain other agreements to be netted against certain payments due to Illinois Power from Dynegy (or certain Dynegy affiliates), should Dynegy or its affiliates fail to make payments due to Illinois Power on or before their due dates. The agreement also allows Dynegy to net payments if Illinois Power fails to make certain required payments to Dynegy or certain other affiliates. Additionally, under the terms of this petition and the ICC’s approval, Illinois Power may not pay any common dividend to Dynegy or its affiliates until Illinois Power’s first mortgage bonds are rated investment grade by Moody’s Investors Service and Standard & Poor’s Rating Service and specific approval is obtained from the ICC.

Illinois Power’s retail natural gas sales and distribution services also are regulated by the ICC. Gas sales are currently priced under a purchased gas adjustment mechanism under which Illinois Power’s gas purchase costs are passed through to its customers if such costs are determined prudent, subject to an annual prudency review by the ICC. Rates for gas distribution services are set by the ICC in rate proceedings based on the underlying costs.

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.

Legislation. The U.S. Congress is considering passage of comprehensive energy legislation that will impact us. The legislation includes repeal of PUHCA, 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.

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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 $51 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 $21 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 Projection 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. Illinois Power and DMG are 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 17—Commitments and Contingencies—Summary of Material Legal Proceedings—Baldwin Station Litigation beginning on page F-52 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.

Illinois Power operated more than two dozen sites at which synthetic gas was manufactured from coal. Operation of these manufactured gas plant sites was generally discontinued in the 1950s when natural gas became available from interstate gas transmission pipelines. Many of these MGP sites were contaminated with residues from the gas manufacturing process and remediation of this historic contamination could be required under CERCLA or RCRA or analogous state laws. Illinois Power is in the process of cleaning up sites that it has identified as requiring remediation. Recovery of clean-up costs in excess of insurance proceeds from Illinois Power’s electric and gas customers is considered probable.

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

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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.

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 28 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 Illinois Power and DMG, which are described in Note 17—Commitments and Contingencies—Summary of Material Legal Proceedings—Baldwin Station Litigation beginning on page F-52, 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.

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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 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.

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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.

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 80 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 83 for further discussion of our internal control systems.

SIGNIFICANT CUSTOMER

For the years ended December 31, 2003, 2002 and 2001, approximately 16%, 15% and 10%, respectively, of our consolidated revenues and approximately 22%, 44% and 44%, respectively, of our consolidated cost of sales were derived from transactions with ChevronTexaco and its subsidiaries. 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 1,310 employees at our administrative offices and approximately 2,793 employees at our operating facilities. Approximately 1,626 employees at Dynegy-operated facilities are subject to collective bargaining agreements with various unions. We believe relations with our employees are satisfactory.

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Item 1A. Executive Officers

Set forth below are the names and positions of our executive officers as of February 27, 2004, together with their ages and years of service with us.

The executive officers named above will serve in such capacities until the next annual meeting of our Board of Directors, or until their respective successors have been duly elected and have been qualified, or until their earlier death, resignation, disqualification or removal from office.

Bruce A. Williamson has served as President, Chief Executive Officer and as a director of Dynegy since October 2002. Prior to joining Dynegy, Mr. Williamson served in various capacities with Duke Energy and its affiliates, most recently serving as President and Chief Executive Officer of Duke Energy Global Markets. In this capacity, he was responsible for all Duke Energy business units with global commodities and international business positions. Mr. Williamson joined PanEnergy Corporation in June 1995, which then merged with Duke Power in June 1997. Prior to the Duke-PanEnergy merger, he served as PanEnergy’s Vice President of Finance. Before joining PanEnergy, he held positions of increasing responsibility at Shell Oil Company, advancing over a 14-year period to Assistant Treasurer.

Alec G. Dreyer has served as Executive Vice President of our generation segment since October 2002. Mr. Dreyer joined us in February 2000 upon consummation of the Illinova acquisition and has served various functions in our corporate finance department and power generation business. Prior to joining us, Mr. Dreyer served Illinova and its affiliates for 8 years, most recently as President of Illinova Generating Company and Senior Vice President of Illinova and Illinois Power. He was responsible for developing Illinova’s spin off of its fossil-fueled generation fleet into an unregulated entity, which is now known as DMG.

Stephen A. Furbacher has served as Executive Vice President of our natural gas liquids segment since September 1996. He joined us in May 1996, just prior to our acquisition of Chevron’s midstream business. Before joining us, he served as President of Warren Petroleum Company, the natural gas liquids division of Chevron U.S.A. He began his career with Chevron in August 1973 and served in positions of increasing responsibility before being named President of Warren Petroleum Company in July 1994.

Larry F. Altenbaumer has served as Executive Vice President of our regulated energy delivery segment since November 2002. In February 2004, Mr. Altenbaumer announced his retirement, effective April 1, 2004, from his service as our Executive Vice President and President of Illinois Power. He joined us in February 2000 upon consummation of the Illinova acquisition, at which time he served as Senior Vice President, Chief Financial Officer, Treasurer and Controller of Illinova and as Senior Vice President and Chief Financial Officer of Illinois Power. He joined Illinois Power in June 1970 and previously served Illinois Power in positions of increasing responsibility, including as Senior Vice President and Chief Financial Officer from June 1992 until September 1999.

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Nick J. Caruso has served as Executive Vice President and Chief Financial Officer since December 2002. Mr. Caruso is responsible for our internal audit, risk management, tax, treasury, accounting and finance functions. He was previously employed by Shell Oil Company from June 1969 to December 2001. He most recently served as that company’s Vice President of Finance and Chief Financial Officer before retiring in December 2001. He was responsible for the controller’s organization, treasury, insurance, auditing and retirement funds, interfacing with the board of directors on internal controls, and preparation of financial statements.

Carol F. Graebner has served as Executive Vice President and General Counsel since March 2003. Prior to joining us, Ms. Graebner was employed by Duke Energy International, where she served as senior vice president and general counsel and was responsible for providing all legal, regulatory and governmental affairs services for that company’s international merchant energy business. Prior to joining Duke Energy International in November 1998, she served in various positions of increasing responsibility at Conoco Inc., advancing over a 16-year period to general counsel of Conoco Global Power, Inc.

R. Blake Young has served as Executive Vice President of Administration and Technology since October 2002. Formerly President of Global Technology, Mr. Young is responsible for strategic planning, corporate technology, corporate communications, investor relations, human resources, divestitures and corporate shared services. In addition, effective February 2004, Mr. Young became Executive Vice President and Chief Operating Officer of Illinois Power and will become President of Illinois Power on April 1, 2004. In these capacities he assumes overall responsibility for Illinois Power and the transition to Ameren during the regulatory approval process. Prior to joining us in October 1998, he worked for Campbell Soup Company where he was responsible for technology deployment across its U.S. grocery division and head of global business systems strategy. Mr. Young was previously employed by Tenneco Energy for approximately 13 years, where he served as Vice President and Chief Information Officer.

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 1. Those descriptions are incorporated herein by this reference. Substantially all of our assets, including the physical operating properties we own, but excluding the assets of Illinois Power and DGC and their respective subsidiaries, are pledged as collateral with respect to the DHI amended credit facility. Please read Note 12—Debt beginning on page F-36 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, Georgia, Illinois, Massachusetts, and Texas; and the Canadian province of Ontario.

Item 3. Legal Proceedings

For a description of our material legal proceedings, please read Note 17—Commitments and Contingencies beginning on page F-51, which is incorporated herein by reference.

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

No matter was submitted to a vote of our security holders during the fourth quarter of 2003.

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PART II

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

Our Class A common stock, no par value per share, is listed and traded on the New York Stock Exchange under the ticker symbol “DYN.” The number of stockholders of record of our Class A common stock as of February 23, 2004, based upon records of registered holders maintained by our transfer agent, was 22,308.

Our Class B common stock, no par value per share, is neither listed nor traded on any exchange. All of the shares of Class B common stock are owned by Chevron U.S.A.

The following table sets forth the high and low closing sales prices for the Class A common stock for each full quarterly period during the fiscal years ended December 31, 2003 and 2002, as reported on the New York Stock Exchange Composite Tape, and related dividends paid per share during these periods.

Summary of Dynegy’s Common Stock Price and Dividend Payments

Beginning with the third quarter 2002, our Board of Directors elected to cease payment of a common stock dividend. Payments of dividends for subsequent periods will be at the discretion of the Board of Directors, but we do not foresee reinstating the dividend in the near-term, particularly given the dividend restrictions contained in our financing agreements. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends on Preferred and Common Stock” beginning on page 47 for further discussion of our dividend policy and the impact of these restrictions.

Shareholder Agreement

In June 1999, Chevron U.S.A., now a subsidiary of ChevronTexaco, entered into a shareholder agreement with us governing certain aspects of our relationship. The agreement was executed in February 2000, upon closing of the merger with Illinova, and reflected agreements negotiated between us and Chevron relating to Chevron’s significant ownership interest in Dynegy. The agreement amended certain of the rights and obligations previously agreed between us and Chevron at the time of Chevron’s initial investment in 1996. In August 2003, we entered into an amended and restated shareholder agreement with Chevron in connection with the consummation of the Series B Exchange. The material terms of this amended and restated shareholder agreement, which we refer to in this report as the shareholder agreement, are described below.

The shareholder agreement grants Chevron preemptive rights to acquire shares of our common stock in proportion to its then-existing interest in our equity value whenever we issue any equity securities, including securities issued pursuant to employee benefit plans. Chevron agreed to waive its preemptive rights in respect of the equity securities we issued in connection with the Series B Exchange and the Refinancing and up to $250 million in equity securities we may issue in one or more future underwritten offerings.

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In addition, Chevron and its affiliates may acquire up to 40% of the total combined voting power of our outstanding voting securities without restriction in the shareholder agreement. Shares of Class B common stock issued to Chevron upon the mandatory conversion of Chevron’s Class C convertible preferred stock are not counted when calculating this 40% threshold. We have agreed not to take any action that would cause Chevron’s ownership to exceed this 40% threshold.

If Chevron or its affiliates wish to acquire more than 40% of the total combined voting power of our outstanding voting securities, the shareholder agreement requires Chevron to make an offer to acquire all of our outstanding voting securities for cash or freely tradable securities listed on a national securities exchange. Any offer by Chevron or its affiliates for all of our outstanding voting securities would be subject to the auction procedures outlined in the agreement.

Chevron’s ownership of our Class B common stock entitles it to designate up to three members of our Board of Directors. The shareholder agreement prohibits Chevron from selling or transferring shares of Class B common stock except in the following transactions:

Upon the sale or transfer to any person other than an affiliate of Chevron, the shares of Class B common stock automatically convert into shares of Class A common stock.

The shareholder agreement further provides that we may require Chevron and its affiliates to sell all of the shares of Class B common stock under specified circumstances. These rights are triggered if Chevron or its Board designees block—which they are entitled to do under our Bylaws—any of the following transactions two times in any 24-month period or three times over any period of time:

However, upon occurrence of one of these triggering events and in lieu of selling Class B common stock, Chevron may elect to retain the shares of Class B common stock but forfeit its right and the right of its Board designees to block the subject transaction. A block consists of a vote against a proposed transaction by either (a) all of Chevron’s representatives on the Board of Directors present at the meeting where the vote is taken (if the transaction would otherwise be approved by the Board of Directors) or (b) any of the Class B common stock held by Chevron and its affiliates if the transaction otherwise would be approved by at least two-thirds of all other shares entitled to vote on the transaction, excluding shares held by our management, directors or subsidiaries.

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The shareholder agreement also prohibits us from taking the following actions:

Generally, the provisions of the shareholder agreement terminate on the date Chevron and its affiliates cease to own shares representing at least 15% of our outstanding voting power. At such time all of the shares of Class B common stock held by Chevron would convert to shares of Class A common stock.

Sales of Unregistered Securities

December 2001 Equity Purchases. In December 2001, 10 members of our senior management purchased approximately 1,260,000 shares of Class A common stock from us in a private placement pursuant to Section 4(2) of the Securities Act of 1933, as amended. These officers received loans totaling approximately $25 million from us to purchase the common stock at a price of $19.75 per share, the same price as the net proceeds per share received by us from a concurrent public offering. The loans bear interest at 3.25% per annum and are full recourse to the borrowers. Such loans are accounted for as subscriptions receivable within stockholders’ equity on the consolidated balance sheets. We recognized compensation expense in 2001 of approximately $1.2 million related to the shares purchased by these officers. This amount, which was recorded as general and administrative expense, is derived from the $1.00 per share discount these officers received based on the initial public offering price of $20.75 per share. For further discussion, please see Note 13—Related Party Transactions—December 2001 Equity Purchases beginning on page F-45.

Other Unregistered Common Stock Sales. In March 2001, we sold nearly 1.2 million shares of Class B common stock to Chevron at $34.93 per share in a private transaction under Section 4(2) of the Securities Act pursuant to the exercise of its pre-emptive rights under the shareholder agreement. The proceeds from this transaction were approximately $41 million.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth certain information as of December 31, 2003 as it relates to our equity compensation 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. Earnings (loss) per share (“EPS”), shares outstanding for EPS calculation and cash dividends per common share have been adjusted for a two-for-one stock split on August 22, 2000 and, for all periods prior to February 1, 2000, the 0.69-to-one exchange ratio in the Illinova acquisition.

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 three areas of the energy industry: power generation; natural gas liquids; and regulated energy delivery. 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 four 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 47 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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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 7 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:

Regulated Energy Delivery. Our regulated energy delivery segment is currently comprised of our Illinois Power subsidiary. From February 2002 through July 2002, this segment, formerly called the Transmission and Distribution segment, also included the results of Northern Natural. Northern Natural’s results for this period are reflected in Discontinued Operations in our consolidated statements of operations.

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Illinois Power is a regulated utility that serves more than 590,000 electricity customers and nearly 415,000 natural gas customers in portions of northern, central and southern Illinois. We generate earnings and cash flows in this business through sales of electric and gas service to residential, commercial and industrial customers.

The earnings and cash flows generated by this business are primarily driven by the volumes of electricity and natural gas that we sell and deliver. In terms of costs, retail electric rates are frozen through 2006, and gas costs are passed through to customers. The primary factors impacting sales volumes include:

We recently entered into an agreement to sell Illinois Power and our 20% interest in the Joppa power generation facility to Ameren for $2.3 billion. The transaction is expected to close by the end of 2004, subject to the receipt of required regulatory approvals and other closing conditions. Please read Note 23—Subsequent Event beginning on page F -77 for further discussion.

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.

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 18 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:

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

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Liquidity. As of February 23, 2004, we had cash on hand of $397 million and available borrowing capacity of $866 million, for total liquidity of nearly $1.3 billion. During 2003, we substantially reduced our debt and other obligations while maintaining liquidity between $1.4 billion and $1.7 billion. Our ability to maintain our liquidity position in the future will depend on a number of factors, including our 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 our deleveraging efforts, we also intend 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.

LIQUIDITY AND CAPITAL RESOURCES

Debt Maturities

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

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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 the DHI 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 and conversion features of the securities issued in connection with the Series B Exchange, please read Note 11—Refinancing and Restructuring Transactions beginning on page F-34.

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:

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.

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 63. We also are subject to the more restrictive covenants that are contained

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in the related transaction agreements. Specifically, among other limitations, these covenants limit our ability to receive payments from DHI for the purpose of paying dividends on our common stock and otherwise, limit DHI’s 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 the agreed sale of Illinois Power to Ameren, we must use 75% of the net cash proceeds to repay the Junior Notes. We are 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 $704 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: