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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended December 31, 2002

For the transition period from                              to                         

Commission file number: 1-15659

DYNEGY INC.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 507-6400

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 þ No ¨

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

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

The aggregate market value of the voting and non-voting equity held by non-affiliates of the registrant as of March 26, 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 $640,834,926, 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.

The aggregate market value of the voting and non-voting equity held by non-affiliates of the registrant as of June 28, 2002, computed by reference to the closing sale price of the registrant’s common stock on the New York Stock Exchange on such date, was $1,946,041,481, 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, 275,026,449 shares outstanding as of March 24, 2003; Class B common stock, no par value per share, 96,891,014 shares outstanding as of March 24, 2003.

DOCUMENTS INCORPORATED BY REFERENCE. Part III (Items 10, 11, 12 and 13) incorporates portions of the Notice and Proxy Statement for the registrant’s 2003 Annual Meeting of Shareholders to be filed not later than 120 days after December 31, 2002.

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DYNEGY INC.

FORM 10-K

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PART I

DEFINITIONS

As used in this Form 10-K, the terms listed below are defined as follows:

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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. We own operating divisions engaged in power generation, natural gas liquids and regulated energy delivery. Through these operating divisions, we serve customers by delivering value-added solutions to meet their energy needs.

We are in the process of restructuring our company in response to events that have negatively impacted the merchant energy industry, and our company in particular, over the past year. This restructuring includes significant changes in our operations, primarily our exits from third-party risk management aspects of the marketing and trading business and the communications business. Our restructuring also includes significant financial transactions that have stabilized our liquidity position and began the process of decreasing our substantial financial leverage. Significant accomplishments include the following:

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In our new, simplified operating structure, we intend to focus on being a low-cost producer of physical products and provider of services in each of our three main operating divisions. Our results also will continue to reflect our customer risk management business until the remaining obligations associated with this business have been satisfied or restructured.

Dynegy began operations in 1985 and became incorporated in the State of Illinois in 1999 in connection with the Illinova acquisition. Our principal executive office is located at 1000 Louisiana Street, Suite 5800, Houston, Texas 77002, and our telephone number at that office is (713) 507-6400.

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

SEGMENT DISCUSSION

Beginning in 2003, we will report the financial results of the following four business segments:

Other reported results will include corporate overhead and our discontinued communications operations. Set forth below is a discussion of each of our new business segments.

We have reported our historical segment results in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 38 of this Form 10-K based on our 2002 business segments—Wholesale Energy Network, Dynegy Midstream Services, Transmission and Distribution and Dynegy Global Communications. As described below, the power generation operations previously included in the Wholesale Energy Network segment will now comprise the Power Generation segment. The Wholesale Energy Network segment’s other former operations, to the extent such operations continue, will comprise the Customer Risk Management segment. The remaining operations of our former Dynegy Global Communications segment will now be reported within the “Other” category, together with corporate general and administrative expenses, income taxes and corporate interest expenses, all of which we previously allocated among our operating divisions. The natural gas liquids operations that previously comprised our Dynegy Midstream Services segment and the Illinois Power utility operations previously included within our Transmission and Distribution segment will continue to be reported as their own respective segments.

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Power Generation

We own or lease electric power generation facilities with an aggregate net generating capacity of 13,167 MW located in six regions of the United States, including one facility nearing completion of construction with approximately 800 MW of net generating capacity. The following table describes our current generation facilities by name, region, location, net capacity, fuel and dispatch type.

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

(AS OF DECEMBER 31, 2002)

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Midwest region—Mid-America Interconnected Network Reliability Council (MAIN).    At December 31, 2002, we owned or leased interests in ten generating facilities with an aggregate net generating capacity of 4,212 MW located in Illinois within the MAIN reliability area. Eight of these facilities, which we acquired as a result of the Illinova acquisition in February 2000, are currently owned by Dynegy Midwest Generation, Inc., one of our indirect subsidiaries. DMG pledged these facilities as collateral in connection with a July 2002 amendment to our Black Thunder financing. Please read Item 8, Financial Statements and Supplementary Data, Note 10—Debt     beginning on page F-35 for further discussion of this financing. We hold one of these facilities, the Tilton facility, through an off-balance sheet lease arrangement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements” beginning on page 48 for further discussion of this arrangement. The generating capacity of the MAIN facilities is approximately 80% baseload and 20% peaking and represents approximately 6% of the generating capacity within the MAIN region. The baseload capacity is primarily fueled by coal, with some ability to fire gas, while the remainder is primarily fueled by natural gas and oil.

DMG has a power purchase agreement with IP that provides the regulated utility with approximately 70% of its capacity requirements through December 2004. The contract provides for fixed capacity payments based on the megawatt capacity reserved. DMG also receives variable energy payments for each MW-hour of energy delivered under the contract based on DMG’s cost of generation. As part of the power purchase agreement, DMG also supplies all ancillary services necessary for IP to serve its load and provide transmission services to its customers. The IP power purchase agreement provided a substantial portion of the operating income from our power generation business in 2002. DMG is not the sole supplier to IP, but bears ultimate responsibility for serving the load as the provider of last resort. The eight facilities that primarily provide the power under this agreement were formerly owned by IP and are in locations that are best suited for serving IP’s native load.

In addition to the IP contract, the Rocky Road facility’s 168 MW of peaking capacity is under long-term contract with another purchaser through May 2009. The contract is a tolling arrangement pursuant to which the facility receives fixed monthly payments and a variable fee based on the power that it actually generates.

Approximately 50% of the energy generated by our Illinois facilities is sold pursuant to the long-term contracts described above. The remainder of the power generated 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 market includes all or portions of the states of Illinois, Wisconsin and Missouri. The ECAR market includes all or portions of the states of Indiana, Ohio, Michigan, Virginia, West Virginia, Tennessee, Maryland and Pennsylvania. MAIN and ECAR, like the rest of the country, are currently in a state of regulatory transition as each transmission provider in this region seeks to join regional transmission organizations, or RTOs, that operate the transmission system on a regional basis. Additionally, the RTOs implement the rules and requirements for competitive wholesale markets as set forth by the FERC. The Midwest Independent System Operator, or MISO, has been approved by the FERC to administer a substantial portion of the transmission facilities in this region, while PJM, another FERC-approved independent system operator, has been approved to administer other portions of the region. However, because state and federal regulators must approve these transfers, the timing for transmission providers to turn over control of their high-voltage power lines to the RTOs remains uncertain. Both the MISO and PJM continue to move forward with integrating those

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transmission facilities that have been approved for transfer to the RTOs, and are developing a plan to have a common energy market across their respective control areas by late 2005 or early 2006.

PJM manages the transmission system and maintains competitive wholesale markets within its region. PJM historically covered the states of Pennsylvania, New Jersey and Maryland, but is poised to cover a larger geographic area as some midwestern companies seek to join the RTO. PJM operates the transmission grid for reliability purposes as well as managing the market for firm transmission rights, or FTRs, that determine the economics of congestion on the transmission system. Under a locational marginal pricing methodology, or LMP, PJM facilitates the competitive wholesale spot energy markets, which set the prices at which energy is bought and sold. It is also responsible for ensuring that adequate capacity is available for secure operations of the region, and it provides a capacity auction to facilitate this market. Much of the FERC’s proposed Standard Market Design rulemaking utilizes the market structure for energy, transmission and capacity that PJM has implemented over the past few years. As mentioned above, PJM and MISO are seeking common energy markets that will be based on the LMP method of establishing prices at location; additionally, they plan to use similar FTRs and capacity markets.

We currently sell power from our facilities in the MAIN region to customers under short-term and long-term agreements. Many of the longer agreements are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Our customers include municipalities, electric cooperatives, integrated utilities, transmission and distribution utilities, industrial customers and power marketers. Some states within this region have restructured their electric power markets to competitive retail markets from traditional utility monopoly markets, which allow us to sell directly to retail and commercial end-users.

Midwest region—ECAR.    We own or lease interests in six generating facilities with an aggregate net generating capacity of 2,912 MW located in the states of Kentucky, Michigan and Ohio. One of these facilities, the Rolling Hills facility, is currently under construction with commercial operation expected to begin in the second quarter 2003. The Riverside facility is leased by one of our indirect subsidiaries, Riverside Generating Company, L.L.C. In addition, the Renaissance and Rolling Hills facilities are pledged as collateral to secure a financing originated in June 2002. Please read Item 8, Financial Statements and Supplementary Data, Note 10—Debt beginning on page F-35 for further discussion of this financing. The generating capacity of the ECAR facilities is approximately 2% baseload and 98% peaking and represents approximately 2% of the generating capacity within the ECAR region. All units within the region are fueled by natural gas.

The majority of the power generated by our ECAR facilities is sold to wholesale customers in the MAIN, PJM and ECAR markets. Please read “—Midwest region—Mid-America Interconnected Network Reliability Council (MAIN)” above for a discussion of these markets. All 62 MW of baseload capacity, representing our net ownership interest in the Michigan Power facility, is under contract through December 2030.

Northeast region.    At December 31, 2002, we owned or leased two generating facilities with an aggregate net generating capacity of 1,700 MW located in Newburgh, New York, 50 miles north of New York City. These facilities, acquired from Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc. and Niagara Mohawk Power Corporation in January 2001, are referred to as the Dynegy Northeast Generation (DNE) facilities. The Danskammer facility has four generating units, two of which are owned and two of which are leased by one of our indirect subsidiaries, Dynegy Danskammer, L.L.C. The Roseton facility has two generating units, each of which is leased by another of our indirect subsidiaries, Dynegy Roseton, L.L.C. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements” beginning on page 48 for further discussion of this off-balance sheet lease arrangement.

The generating capacity of these facilities represents approximately 5% of the generating capacity in the state of New York. Two of the Danskammer units use natural gas or fuel oil, while the other two Danskammer

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units are capable of burning both coal and natural gas. The two Roseton units are capable of burning fuel oil or natural gas or both simultaneously. The facilities’ sites are adjacent and share common resources such as fuel handling, a docking terminal, personnel and systems.

We currently sell approximately 23% of the capacity from our DNE facilities to Central Hudson pursuant to a transitional power purchase agreement that expires in October 2004. We sell the remainder of the power generated by these facilities into the New York wholesale market, which is described below. We sell energy and ancillary services into both day ahead and real-time sales markets, and we sell capacity and energy forward (up to 1.5 years for capacity and 3 years for energy). Our customers include the members of the New York Independent System Operator, or NYISO, including municipalities, electric cooperatives, integrated utilities, transmission and distribution utilities, retail electric providers and power marketers. We sell energy products to wholesale, commercial and industrial customers in New York under negotiated bilateral contracts. We also export power to neighboring regions, including PJM, Ontario and New England.

The New York wholesale market operates as a centralized power pool administered by the NYISO. Although the transmission infrastructure within this market is generally well developed and independently operated, significant transmission constraints exist. In particular, there is limited transmission capability from western New York to eastern New York and into New York City. Depending on the timing and nature of transmission constraints, market prices may vary between sub-regions of the market. For example, as a result of transmission constraints into eastern New York and New York City, power prices are generally higher in these areas than in other parts of the state. An unforced capacity market, or UCAP, has been established by the NYISO designed to ensure that there is enough generation capacity to meet retail energy demand and ancillary services requirements. All power retailers are required to demonstrate commitments for capacity sufficient to meet their forecast peak load plus a reserve requirement, currently set at 18 percent.

In addition to managing the transmission system, the NYISO is responsible for maintaining competitive wholesale markets, operating the day ahead, real time, ancillary service and UCAP markets and determining the market clearing price based on bids submitted by participating generators. The NYISO matches sellers with buyers within New York that meet specified minimum credit standards. The NYISO has protocols that provide the structure, rules and pricing mechanisms for various energy products and maintains FERC-approved rates, terms and conditions for transmission service in its control area. NYISO protocols allow energy demand, commonly referred to as “load,” to respond to high prices in emergency and non-emergency situations. The lack of programs, however, to implement load response to prices has been cited as one of the primary reasons for retaining wholesale energy bid caps, which are currently set at $1,000 per megawatt hour. Lower price caps are utilized in other regions.

The New York market is subject to significant regulatory oversight and control. Our operating results may be adversely affected by changes to the current regulatory structure. For additional discussion of the impact of current regulations on the New York market, please read “—Regulation” beginning on page 22.

Southeast region—Southeast Electric Reliability Council (SERC).    At December 31, 2002, we owned interests in five generating facilities with an aggregate net generating capacity of 1,961 MW located in the states of Georgia, Louisiana, North Carolina and Virginia. This capacity’s primary fuel is natural gas, with some capability to burn fuel oil.

320 MW of the SERC capacity is under long-term contracts. A contract for the Commonwealth facility’s 170 MW of capacity expires in May 2017, while a contract for the Hartwell facility’s 150 MW of capacity expires in May 2019. The remainder of the power generated by our SERC facilities is generally sold to wholesale customers in the SERC market. This market includes all or portions of the states of Missouri, Kentucky, Arkansas, Tennessee, West Virginia, Virginia, North Carolina, South Carolina, Texas, Louisiana, Mississippi, Alabama, Georgia and Florida. There are several proposals to establish RTOs that would define the rules and requirements around which competitive wholesale markets in this region would develop. The FERC has provisionally approved proposals by SeTrans Grid Company L.L.C. and GridSouth Transco L.L.C. to administer

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a substantial portion of the transmission facilities in this region. As a result, the final market structure for this region remains uncertain. Currently, the transmission infrastructure in this market is generally owned and managed by integrated utilities, some of which are our competitors. As a result, market anomalies may exist. Transmission constraints are present in this market. Transmission infrastructure owners are subject to tariffs and protocols administered by the FERC.

We currently sell power from our facilities in this region to customers under short-term and long-term agreements. Many of the longer agreements are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Our customers include municipalities, electric cooperatives, integrated utilities, transmission and distribution utilities and power marketers. To date, there has been no significant access granted to retail customers in SERC.

West region—Western Electricity Coordinating Council (WECC).    At December 31, 2002, we owned interests in six generating facilities with an aggregate net generating capacity of 1,440 MW located in the states of California, Nevada and Washington. The generating capacity of our WECC facilities is approximately 4% baseload, 69% intermediate and 27% peaking capacity and represents less than 1% of the generating capacity in the WECC region. This capacity is largely natural gas-fired, although two of the peaking facilities located in California can also burn fuel oil.

Of our 1,440 MW of net generating capacity in the WECC, 1,385 MW consists of our 50 percent share of the 2,770 MW portfolio of facilities owned by West Coast Power, L.L.C., a joint venture between Dynegy and NRG Energy. All of West Coast Power’s 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 California Department of Water Resources, referred to as the CDWR, which expires in December 2004. The agreement provides for a firm commitment of 600 MW of on-peak capacity and 200 MW of off-peak 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 MW of on-peak capacity and 1,500 MW of off-peak capacity, subject to required minimum reservation amounts of 500 MW and 200 MW, 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. We may also market the energy, capacity and ancillary services output of these facilities through bilateral contracts or sell into the markets operated by the California Independent System Operator, or Cal ISO. Please read the discussion of the California electricity market below as well as Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies beginning on page F-49 for a discussion of the ongoing legal challenges to the CDWR contract. West Coast Power shut down two units at these facilities, representing an aggregate capacity of 209 MW, at the end of 2002 because we deemed them no longer commercially viable.

Approximately 55 MW of baseload capacity outside of California consists of our equity interests in QFs that are under long-term contracts. Of this capacity, the Ferndale facility’s 12 MW of capacity is contracted through December 2011 and the Black Mountain facility’s 43 MW of capacity is contracted through April 2023.

The WECC regional market includes all or parts of the states of Arizona, California, Oregon, Nevada, New Mexico, Colorado, Wyoming, Idaho, Montana, Texas, South Dakota, Utah and Washington. Generally, we sell the power generated by facilities that are not under long-term contracts to customers located in southern California. Our customers include power marketers, investor-owned utilities, electric cooperatives, municipal utilities and the Cal ISO, acting on behalf of load-serving entities. We sell power and ancillary services to these customers through a combination of bilateral contracts and sales made in the Cal ISO’s day-ahead and hour- ahead ancillary services markets and its real-time energy market. Many of the longer agreements we enter into are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Access to retail customers has been substantially curtailed in this region.

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Our operations in the California market are subject to numerous environmental and other regulatory restrictions. Permits issued by local air districts restrict the output of some of our generating facilities. In addition, certain air districts require us to purchase emission credits to offset nitrogen oxide emissions from our facilities.

In 1996 and 1997, the FERC issued a series of orders approving a wholesale market structure. This structure was administered by two independent non-profit corporations: the Cal ISO, responsible for operational control of the transmission system and balancing actual supply and demand in “real-time,” and the Cal PX, responsible for conducting auctions for the purchase or sale of electricity on a day-ahead or day-of basis. As part of this market restructuring, California’s distribution utilities sold essentially all of their gas-fired plants to third parties. The utilities were required to sell their remaining generation into the Cal PX markets and purchase all of their power requirements from the Cal PX markets at market-based rates approved by the FERC. The Cal PX ceased operations in January 2001 and subsequently filed for bankruptcy. The Cal ISO currently is conducting a major market redesign process that, if approved by the FERC, could change the structure of the markets operated by the Cal ISO, including changes to market monitoring and mitigation, congestion management and capacity obligations. 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 “—Regulation” beginning on page 22 and Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies beginning on page F-49.

Texas region—Electric Reliability Council of Texas (ERCOT).    At December 31, 2002, we owned or leased interests in four generating facilities with an aggregate net generating capacity of 942 MW located in Texas. The CoGen Lyondell facility is leased by one of our indirect subsidiaries, CoGen Lyondell, Inc. The generating capacity of our ERCOT facilities consists entirely of baseload facilities and represents approximately 1% of the generating capacity in the ERCOT region. All facilities are fueled by natural gas.

Approximately 305 MW of baseload capacity in this region is under long-term contracts. The Paris facility’s 37 MW of capacity is contracted through September 2005, 185 MW of the Oyster Creek facility’s capacity is contracted through October 2014 and the Frontier facility’s 83 MW of capacity is contracted through September 2020.

The ERCOT region is comprised of the majority of the state of Texas. As part of the transition to deregulation in Texas, ERCOT changed its operations from 10 control areas, managed by utilities in the state, to a single control area on July 31, 2001. ERCOT, as the independent system operator, is responsible for maintaining reliable operations of the bulk electric power supply system in the ERCOT market. It is responsible for facilitating information needed for retail customer choice. It ensures that electricity production and delivery are accurately accounted for among the generation resources and wholesale participants in the ERCOT market. Unlike independent systems operators in other regions of the country, ERCOT does not centrally dispatch resources in the region. Market participants are generally responsible for contracting for their requirements bilaterally. However, ERCOT does procure energy on behalf of market participants pursuant to relaxed Balanced Schedule Protocols implemented on November 1, 2002. ERCOT also serves as agent for procuring ancillary services for those who elect not to provide their own requirements.

Members of ERCOT include retail customers, investor and municipal owned electric utilities, rural electric cooperatives, river authorities, independent generators, power marketers and retail electric providers. The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council. Unlike other regions of the U.S., the Public Utility Commission of Texas, or PUCT, has primary jurisdictional authority over the ERCOT market, rather than the FERC. Currently, the PUCT is evaluating the need to change ERCOT’s market structure due to a variety of commercial and operational issues that have been uncovered in the first 18 months of operation. The market design rulemaking proceeding is expected to conclude during the first half of 2003. Implementation of market redesign would follow.

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We currently sell power from our facilities in this region to customers under short-term and long-term agreements. Many of the longer agreements are bilateral contracts that are generally non-standard with highly negotiated terms and conditions, while short-term sales usually occur through well-established existing commercial relationships. Our customers include municipalities and electric cooperatives, which remain primarily integrated utilities, power marketers and retail electric providers. We also sell directly to commercial and industrial end users.

International.    In addition to our U.S. generating assets, we own interests in five generating facilities with an aggregate net generating capacity of 192 MW located in Costa Rica, Panama, Jamaica, Honduras and Pakistan. All of these facilities were acquired as part of the merger with Illinova in February 2000. The capacity consists of natural gas, heavy fuel oil and wind projects. All of this capacity is under contract for terms ranging from five to 25 years. Our ownership interests in these international projects range from 16% to 100%.

Retail Supply Business.    We selectively contract 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 marketing operations are directed towards Texas, Illinois and New York. We also have four contracts with The Kroger Co. to provide it with an aggregate of 100 MW of capacity in California. These contracts, which were executed by the parties during the first half of 2001, have terms of varying lengths, the longest of which extends through December 2006. Concurrently with our execution of these contracts, we entered into other contracts to provide us with the power supply to support our obligations to The Kroger Co. Please read Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies beginning on page F-49 for discussion of The Kroger Co.’s legal challenges to these four contracts.

Power Generation Segment Marketing and Trading Strategy.    As previously announced, we are in the process of exiting third-party risk management aspects of the marketing and trading business. Please read “—Customer Risk Management Segment” beginning on page 18 for further discussion of this exit. Our power generation segment will continue to manage price risk through the optimization of fuel procurement and the marketing of power generated from its owned and controlled assets. As part of our commercial strategy to optimize these assets (including agency and energy management agreements to which we are a party) and to mitigate any associated risk, we will enter into various financial and other transactions and instruments, including entering into and unwinding forward hedges related to our generating capacity. We may also purchase capacity and energy to serve more efficiently our supply obligations under various contracts in each of the regions in which we operate.

Natural Gas Liquids

Our natural gas liquids segment primarily consists of our midstream asset operations, located principally in Texas, Louisiana and New Mexico, and our North American NGL 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 NGLs. We generate commodity and fee-based revenue in our upstream activities; we generate fee-based revenue downstream at our fractionation, storage, terminalling and distribution facilities; and we generate margin and commodity-based revenue in our NGL distribution and marketing operations.

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

Upstream business.    Our upstream business comprises our natural gas gathering and processing operations. Natural gas processing includes the operations of refining raw natural gas into merchantable pipeline-quality natural gas by extracting NGLs and removing impurities. We own interests in 20 gas processing plants, including 12 plants we operate. We also operate 9,188 miles of natural gas gathering pipeline systems associated with the 12 operated facilities and 2 stand-alone gas gathering pipeline systems where gas is treated and/or processed at third-party plants. These assets are located in key producing areas of Louisiana, New Mexico and Texas. During 2002, we processed an average of 2.1 Bcf/d of natural gas and produced an average of 92,000 gross barrels per day of NGLs. We are also party to processing agreements with four third-party plants.

Our natural gas processing services are provided in two plant categories: field plants and straddle plants. Field plants aggregate volumes of unprocessed gas from multiple onshore producing wells through gathering systems. These volumes are aggregated into economically sufficient volumes to be processed to extract NGLs and to remove water vapor, solids and other contaminants. 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 natural gas markets.

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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. The following map depicts our upstream assets in their current locations, including our capacity, throughput and production levels by region.

We process natural gas under several types of contracts. Under “percentage of liquids” contracts, the producer delivers to us a percentage of the NGLs as our fee and retains the value of all remaining NGLs and natural gas at the processing plant tailgate. Under “percentage of proceeds” contracts, a producer delivers to us a percentage of the NGLs and a percentage of the natural gas as payment for our services and retains the value of the remaining NGLs and natural gas at the tailgate of the processing plant. Under both “percentage of liquids” and “percentage of proceeds” contracts, the producer will either take their share of the NGLs and natural gas in kind or have us sell the commodities and return the sale proceeds to them.

Under “keep-whole” processing arrangements, we extract NGLs and return to the producer volumes of merchantable natural gas containing the same Btu content as the unprocessed natural gas that was delivered to us for processing. We retain the NGLs as our fee for processing and must purchase and return to the producer sufficient volumes of merchantable natural gas to replace the Btus that were removed through processing so that the producer is “kept whole.”

Under “economic election” contracts, when processing economics are unfavorable the producer generally has the election to either bypass the plant or pay us a per-unit fee to process the gas. In some of the more recent agreements, the election is automatic, depending on processing economics. In this situation, when the value of the NGLs is less than the value of gas on an equivalent Btu basis, the contract automatically converts to a fee-based processing arrangement. In both instances, this fee could be in the form of a percentage of the natural gas and/or NGLs processed or in cash. Under “wellhead purchase” contracts, we purchase unprocessed natural gas from a producer at the wellhead at a discount to the market value of the gas. This discount is our margin for gathering and processing.

In 2003, we estimate that approximately

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Pursuant to agreements we have with ChevronTexaco, we have the 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 in field processing plants owned by us or owned by third parties. The gas processed in our field plants is processed on a percentage of proceeds basis and is based on a commitment of such production by ChevronTexaco for the life of the oil, gas and/or mineral 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 plants owned by third parties. The gas produced from the Gulf of Mexico area is processed on a percentage of liquids basis when processing is economical or is processed on a fee basis if processing is uneconomical. The oil, gas and/or mineral leases committed under this agreement are committed for the life of the prospect.

Both types of processing agreements with ChevronTexaco, our field processing agreements and our Gulf of Mexico processing agreement, allow either party to renegotiate the commercial terms effective as of September 1, 2006 and on each successive ten-year period thereafter, for ChevronTexaco gas processed in field processing plants, and five years thereafter, for gas produced from the Gulf of Mexico and processed in Louisiana straddle plants. These renegotiations are to assure that commercial terms are substantially similar to those which, as of the date of the renegotiation, each party could expect to obtain in a freely negotiated processing agreement providing for a commitment of gas of similar quantity and quality for a ten-year term, with respect to the field plants, and a life-of-lease commitment, with respect to the straddle plants. During 2002 and 2001, respectively, ChevronTexaco gas accounted for 27% and 22% 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 NGLs. 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. NGL business, and West Louisiana. The following map depicts our downstream assets in their current locations, including our capacity and throughput capabilities.

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

We fractionate volumes for customers, from both our own upstream operations and third parties, pursuant to contracts that typically include a base fee per gallon and other 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 2002, these facilities fractionated an aggregate average of 215,000 gross barrels per day. We also have an equity investment in a third fractionator located in Mont Belvieu, Texas.

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Storage.    Our NGL storage facilities have extensive pipeline connections to third-party pipelines, third-party facilities and to our own fractionation and terminalling facilities. In addition, these storage facilities are connected to marine, rail and truck loading and unloading facilities that provide service and products to our customers. We generate fee-based revenue from our storage business by providing long-term and short-term storage services and throughput capability to affiliated and third-party domestic customers. 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 in the storage wells the NGLs removed from storage. When large volumes of NGLs 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 well. When reduced volumes of NGLs are stored, we utilize the brine from our brine storage ponds to displace the volumes of NGLs removed and, if necessary, can produce additional brine from wells dedicated for that purpose through a process known as brine leaching.

Transportation and Logistics.    Our NGL transportation and logistics infrastructure is made up of a wide range of transportation and distribution assets supporting the delivery requirements of our distribution and marketing business. These assets are deployed to serve our wholesale distribution terminals, fractionation facilities, underground storage facilities, pipeline injection terminals and many of the nation’s crude oil refineries. Our marine terminals, located in Texas, Florida, Mississippi and Tennessee, offer importers and wholesalers a variety of methods for transporting products to the marketplace. Our transportation assets include:

We maximize use of our transportation assets by providing fee-based transportation services to refineries and petrochemical companies in the Gulf of Mexico region and to the wholesale propane marketing business nationwide.

Distribution and Marketing Services.    Our distribution and marketing services include:

Our refinery services business consists of providing LPG balancing services, purchasing NGL products from refinery customers and selling NGL products to various customers. In our LPG balancing operations, we use our storage, transportation, distribution and marketing assets to assist refinery customers in managing their NGL product inventories. This includes both feedstocks utilized in refinery processes and excess LPGs produced by those processes. We generally earn a margin in our refinery services operations by retaining a portion of the resale price of excess NGLs or a fixed minimum fee per gallon and by charging a fee for locating and supplying feedstocks to the refinery either based on a percentage of the cost in obtaining such supply or a minimum fee per gallon. Approximately 35% and 15% of this segment’s NGL purchases in 2002 and 2001, respectively, were from ChevronTexaco. In 2002, we sold an average of 60,000 barrels per day through our refinery services business.

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We have contracts with each of ChevronTexaco’s refineries situated in El Paso, Texas, El Segundo, California, Pascagoula, Mississippi, Richmond, California, Salt Lake City, Utah and Hawaii pursuant to which we provide refinery services. All of these contracts allow us to market excess NGLs produced during the refining process. In addition, with respect to all of the refineries except Hawaii, these agreements also provide for the supply by us of NGLs to ChevronTexaco, which are utilized in its refining process. Generally, these agreements provide that we obtain on behalf of the refineries any such NGL feedstocks that they need and, in return, we are reimbursed for the cost of acquiring such feedstocks and are paid a cents-per-gallon fee for providing such services. These agreements extend through August 2006.

Our wholesale propane marketing operations include the sale of propane and related logistical services to major multi-state retailers, independent retailers and other end users. Our propane supply comes from our refinery services operations and from our other owned and/or managed distribution and marketing assets. In addition, we also have the right to purchase or market substantially all of ChevronTexaco’s NGLs (both mixed and raw) pursuant to a Master NGL Purchase Agreement that extends through August 31, 2006. We generally sell propane at a fixed or posted price at the time of delivery. In 2002, we sold an average of 40,000 barrels of propane per day. In January 2002, we purchased former Texaco’s wholesale propane marketing business and integrated it into our existing wholesale business.

We market our own NGL production and also purchase NGL products from other NGL producers and marketers for resale. In 2002, our distribution and marketing services business sold an average of 303,000 barrels per day of NGLs in North America. We generally purchase mixed NGLs from producers at a monthly pricing index less applicable fractionation, transportation and marketing fees and resell these products to petrochemical manufacturers, refineries and other marketing and retail companies. This is primarily a physical business in which we earn margins from purchasing and selling NGL products from producers under contract. We also earn margins by purchasing and reselling NGL products in the spot and forward markets.

In 2002, we marketed 96,000 barrels per day of LPG worldwide, using chartered large-hull ships. These operations consisted primarily of acquiring and marketing LPG from producing areas in the North Sea, West Africa, Algeria and the Arabian Sea, as well as from the U.S. Gulf Coast region. During the fourth quarter 2002, we decided to exit the global liquids business and sold our London-based international LPG trading and transportation business to Trammo Gas International Inc., a wholly owned subsidiary of Transammonia Inc. The transaction closed on December 13, 2002 and was effective on January 1, 2003. This sale is also consistent with our current strategy to focus our marketing activities on our North American physical assets. The sale of our international liquids business benefits liquidity by releasing significant amounts of previously posted collateral and removing lease obligations and parent guarantees related to shipping activities in the first quarter of 2003. We are in the process of finalizing a complete release of the ship lease, including the parent guarantee.

On an aggregate basis, this segment’s marketing, wholesale and global operations sold approximately 499,000 barrels per day of NGLs to approximately 740 different customers in 2002. In 2002 and 2001, approximately 28% and 23%, respectively, of our NGL sales were made to ChevronTexaco or one of its affiliates pursuant to the refinery agreements discussed above and pursuant to an agreement we have with Chevron Phillips Chemical Company. In the latter agreement, we supply most of Chevron Phillips Chemical’s NGL feedstock needs in the Mont Belvieu area and collect a cents-per-barrel fee for storage and product delivery.

Regulated Energy Delivery

General.    Our transmission and distribution segment consists of IP’s operations, which we acquired in the Illinova acquisition in February 2000. IP is a regulated public utility based in Decatur, Illinois. IP 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. IP provides retail electric and natural gas service to residential, commercial and industrial consumers in substantial portions of northern, central and southern Illinois. IP also currently supplies electric transmission service to electric cooperatives, municipalities and power marketing entities in the state of Illinois. As described below, IP has previously announced an agreement to sell its electric transmission system.

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From February 1, 2002 through July 31, 2002, this segment also included the results of Northern Natural. We acquired Northern Natural from Enron in connection with our terminated merger and 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 Item 8, Financial Statements and Supplementary Data, Note 3—Dispositions, Discontinued Operations and Acquisitions beginning on page F-17 for further discussion of Northern Natural.

Electric Business.    IP 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 January 3, 2003, based on billable meters, IP served 592,692 active electric customers. IP owns an electric distribution system of 37,907 circuit miles of overhead and underground lines. For the year ended December 31, 2002, IP delivered a total of 19,144 million kWh of electricity.

IP owns, but has contracted to sell, its 1,672-circuit mile electric transmission system to Trans-Elect Inc., an independent transmission company, for $239 million. The closing of the sale, the contract for which was executed as of October 7, 2002, was conditioned on several matters, including the receipt of required approvals from the SEC under PUHCA, the Federal Trade Commission, the ICC and the FERC. With respect to the FERC, the sale was conditioned on its approving the levelized rates application filed by Trans-Elect seeking a 13% return on equity (based on a capital structure of equal portions of debt and equity), which would result in a significant increase in transmission rates over the rates IP currently charges. On February 20, 2003, the FERC voted to defer its approval of the transaction and set a hearing to establish the allowable transmission rates for Trans-Elect. Specifically, the FERC stated that the benefits of the transaction, including independent transmission ownership, may not justify the significant increase in rates sought. The FERC also limited the period for which IP may provide operational services to Trans-Elect to one year.

IP and Trans-Elect have withdrawn the rate filing at the FERC and requested a continuance of the hearing pending an order on rehearing and a FERC ruling on a new rate application. Pending resolution of these matters by the FERC, the ICC proceedings have also been withdrawn and continued. IP is currently in discussions with Trans-Elect to determine the impact of the FERC order on the transaction and to determine the course of action the parties will take. Under the sale agreement, if the transaction does not close on or before July 7, 2003, either party can terminate the agreement. Because of the lead time required to receive the necessary regulatory approvals, it is unlikely that the transaction could be closed by July 7th.

Regulators historically have determined IP’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 IP’s shareholders the opportunity to earn a reasonable rate of return. Please read “—Regulation” beginning on page 22 for further discussion of the regulatory environment in which IP operates, including the retail electric rate freeze that will remain in effect through 2006.

IP owns no significant generation assets and obtains the majority of the electricity that it supplies to its retail customers pursuant to long-term 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. IP 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 IP in the event of a curtailment or shutdown at Clinton.

IP obtains more than two-thirds of its electricity pursuant to its power purchase agreement with DMG that runs through 2004. The DMG agreement requires that IP compensate DMG for reserved capacity regardless of the amount of electricity purchased and that IP pay for any electricity actually purchased based on a formula that includes various cost factors, primarily related to the cost of fuel, plus a market price for amounts in excess of its reserved capacity. The agreement obligates DMG to provide power up to the amount IP reserves even if DMG has units unavailable. In addition, DMG bears ultimate responsibility for serving IP’s load as the provider of last

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resort. As a result, should IP be unable to obtain sufficient power to meet its load requirements from the DMG and AmerGen facilities, DMG is obligated to acquire such power for IP, likely through open market purchases at current market prices. IP is subject to market price risk with respect to such power purchases.

Gas Business.    IP supplies retail natural gas service to an estimated population of 1,019,000 in 258 incorporated municipalities and adjacent areas. As of January 3, 2003, based on billable meters, IP served 414,333 active gas customers. IP owns 774 miles of natural gas transportation pipeline and 7,598 miles of natural gas distribution pipeline. IP purchases the gas that it sells at retail from various suppliers pursuant to contracts that generally have a duration of one to twelve months. IP attempts to manage its customers’ gas price risk by buying gas forward and injecting gas into storage at times when IP believes it is economic to do so, subject to ICC regulations and review.

The ICC determines rates that IP may charge for retail gas service. As with the rates that IP is allowed to charge for retail electric service, the rates that IP is allowed to charge for retail gas service are designed to recover the cost of service and to allow IP’s shareholders the opportunity to earn a reasonable rate of return. IP’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, 2002, IP delivered a total of 773 million therms of natural gas.

IP 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 327 million cubic feet. To supplement the capacity of IP’s seven underground storage fields, IP 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 about 96 million cubic feet. The operation of these underground storage facilities permits IP 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.

Intercompany Note Receivable.    In October 1999, IP 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 the generating fleet of DMG. 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, 2002, 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 IP’s segment results as reported herein.

Customer Risk Management

Our customer risk management, or CRM, segment consists of third-party marketing, trading and risk management activities unrelated to our generating assets. This segment provides these services to wholesale energy customers in North America, the United Kingdom and Continental Europe. In October 2002, we announced our exit from the CRM business, which has historically focused on the following activities:

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Since announcing our exit from the CRM business, we have made substantial progress in winding down our marketing and trading portfolio, particularly in the United Kingdom. Following is a list of actions we have taken related to this exit:

Also in January 2003, we announced an agreement with ChevronTexaco to end the existing natural gas purchase and sale contracts related to ChevronTexaco’s North American production and consumption, effective February 1, 2003. Our CRM segment had purchased substantially all of ChevronTexaco’s lower-48 U.S. natural gas and supplied the natural gas requirements of ChevronTexaco’s corporate facilities through agreements that were to run until August 2006. We paid ChevronTexaco approximately $13 million in connection with ending the contracts, resolving balancing and other commercial matters and the transfer to ChevronTexaco of some related third-party contracts.

We have also taken various actions in the process of winding down our trading positions in this business. For example, we have sold all of our U.S. natural gas storage inventories. In an effort to reduce the size of our marketing and trading portfolio, we also have negotiated terminations of various marketing and trading agreements, or allowed them to expire, and generally have not entered into new transactions of this type. In our U.S. natural gas marketing and trading business, we have terminated or assigned all of our long-term storage arrangements and substantially all of our third-party sales arrangements. In the United Kingdom, we have terminated or sold all of our marketing and trading contracts in the region and have closed our U.K. office. The success of these efforts to date is reflected in, among other things, a significant reduction in our collateral requirements associated with this business. Since September 30, 2002, we have reduced our collateral obligations in this business by approximately $585 million.

A significant component of our CRM segment is the eight power tolling arrangements to which we are a party. Pursuant to these eight agreements, we are obligated to make aggregate payments of approximately $3.8 billion to our counterparties in exchange for access to power generated by their facilities. Given our decision to exit from third-party risk management aspects of the marketing and trading business, we no longer consider this access to power as key to our business strategy. We are actively pursuing opportunities to assign or renegotiate the terms of our contractual obligations related to some of these agreements.

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The following table contains a listing of our power tolling arrangements, including the name and location of each related project, the plant heat rate, the plant capacity and the term over which these payments are due:

Tolling Agreements

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Wholesale Energy Network” beginning on page 64 for further discussion of the potential impact of these power tolling agreements on our future results.

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, will be included in our other reported results, as well as corporate-related other income and expense items. Interest expense associated with borrowings incurred by our operating divisions, such as IP mortgage bonds or power generation facility financings, will continue to be reflected in the appropriate business segment’s results. Other results also include our discontinued communications business.

The communications business was established during the fourth quarter of 2000 and includes an optically switched, mesh fiber-optic network that spans more than 16,000 route miles and reaches 44 cities in the United States. As previously announced, we have executed an agreement to dispose of our U.S. communications business to 360 networks. The transaction is expected to close in the second quarter 2003 and is subject to receipt of required regulatory approvals and other closing conditions.

During the first quarter 2003, we disposed of our European communications business, which operated a high-capacity, broadband network with access points in 32 cities throughout Western Europe. As a result of this sale, we eliminated approximately $150 million of our then-remaining operating commitments associated with our communications business.

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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 NGL 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 NGLs, residue gas, condensate and sulfur, and transportation and storage of natural gas and NGLs. 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 19 companies.

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

With respect to IP’s gas distribution business, absent extraordinary circumstances, potential competitors are barred from constructing competing systems in IP’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 IP’s service territories.

IP’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”. 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 several registered energy providers for non-residential service. We face intense competition from these other energy providers and estimate that by the end of 2003, commercial and industrial customers representing approximately 16% of IP’s eligible retail load will have switched to another such provider. Competition typically is based on price and service reliability. We believe IP has approximately eight primary competitors in its business.

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REGULATION

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

Power Generation Regulation.    Our power generation assets include projects that are Exempt Wholesale Generators, or EWGs, qualifying facilities, or QFs, or foreign utility companies, or FUCOs. One form of EWG is a merchant plant, which operates independently from designated power purchasers and, as a result, will generate and sell power to markets when electricity sales prices exceed the cost of production. A QF typically sells the power it generates to a single power purchaser.

The FPA grants the FERC exclusive ratemaking jurisdiction over wholesale sales of electricity in interstate commerce. Our power generation operations also are subject to regulation by the FERC under PURPA with respect to rates, the procurement and provision of certain services and operating standards. Although facilities deemed QFs under PURPA are exempt from ratemaking and other provisions of the FPA and the Public Utilities Holding Company Act of 1935, or PUHCA, non-QF independent power projects that are not otherwise exempt and certain power marketing activities are subject to the FPA and the FERC’s ratemaking jurisdiction, as well as PUHCA, and the Energy Policy Act of 1992. All of our current QF projects are qualifying facilities and, as such, under PURPA 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 ownership interests in such projects.

In certain markets where we own power generation facilities, specifically California and New York, the FERC has, from time to time, approved and subsequently extended temporary price caps on wholesale power sales, or other market mitigation measures. Due to concerns over potential short supply and high prices in the summer of 2001, the NYISO, the FERC-approved operator of electric transmission facilities and centralized electric markets in New York, filed an Automated Mitigation Procedure proposal with the FERC. The proposal caps bid prices based on the cost characteristics of power generating facilities in New York, such as our Central Hudson facilities. In an order issued on June 28, 2001, the FERC accepted the proposal for the summer of 2001. In a subsequent order issued on November 27, 2001, the FERC extended the proposal through April 30, 2002. In an order issued in May 2002, the FERC modified and extended the proposal indefinitely, until the NYISO implements the FERC’s standard market design rules.

Price volatility and other market dislocations in the California market have precipitated a number of FERC actions related to the California market, and the Western market generally, in addition to price caps and market mitigation measures. These include an investigation of gas pipeline marketing affiliate abuse in the region, focused on whether, and to what extent, price refunds are owed by Dynegy and wholesale electricity suppliers serving California, and complaints requesting the FERC to reform or void various long-term power sales contracts. As a prelude to possible initiation of a new complaint proceeding, in the Spring of 2002, the FERC began investigating whether any entity has manipulated prices for electricity or natural gas in the West, since January 1, 2000, possibly resulting in unjust and unreasonable prices under long-term power sales contracts entered into since that time. On March 26, 2003, the FERC staff issued its Final Report on Price Manipulation in Western Markets, addressing a number of issues. The FERC staff also recommended that the FERC issue orders requiring that Dynegy and 36 other market participants be required to “show cause” why their activities did not violate the Cal ISO and Cal PX tariffs. Additional matters regarding our California operations are discussed in Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies beginning on page F-49.

On November 20, 2001, the FERC issued an order that would subject the prospective sales of all entities with market-based rate tariffs to “refunds or other remedies” in the event the seller engages in “anti-competitive behavior or the exercise of market power.” The FERC has postponed the effectiveness of this refund condition pending its consideration of comments submitted by interested parties. Dynegy and other similarly-situated

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generators and power marketers have submitted comments in opposition to the proposed refund condition. It is uncertain how the FERC will act with respect to this matter. If the FERC were to establish the broad refund condition proposed, it would increase the risk inherent in electric marketing activities for all wholesale sellers of electricity, including us. Establishment of the proposed refund condition, together with a finding that we engaged in any of the specified activities, also could require us to refund some of the electricity payments we have collected.

Electricity Marketing Regulation.    Our electricity marketing operations are regulated by the Federal Power Act and the FERC with respect to rates, terms and conditions of services and various reporting requirements. Current FERC policies permit trading and marketing entities to market electricity at market-based rates. While the FERC has affirmed its desire to move toward competitive markets with market-based pricing, it is currently reviewing the specifics of implementing this policy. For further discussion, please see “—Power Generation Regulation” beginning on page 22 above.

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. Recently, the FERC proposed new rules designed to result in the adoption of generally standardized market terms and conditions governing interstate transmission and RTO operation of markets. The FERC also proposed generic standards and procedures for the interconnection of generation to the transmission grid. These proposed rules are controversial, particularly with some legislators and state regulatory bodies, and have generated significant opposition. The FERC also has directed electric industry participants to establish a single organization to assist with the development of business practices and protocols that will be needed to implement such standardized terms and conditions. It is uncertain what rules the FERC may adopt as the result of these proceedings. The impact of these RTOs on our electricity marketing operations cannot be predicted. For further discussion, please see “—Illinois Power Company” beginning on page 24 below.

Recently, the FERC announced a new policy concerning its approvals of utilities’ securities issuances, including debt, and to assume liabilities and obligations of others. Under the new policy, such approvals will be conditioned upon a requirement that any secured debt incurred follow the disposition of assets used to secure it, and if secured by public utility assets, must only be incurred for public utility purposes and if unsecured, must proportionately follow any assets financed with its proceeds if those assets are transferred.

Natural Gas Processing.    Our natural gas processing operations could become subject to FERC regulation. The FERC has traditionally maintained that a processing plant used primarily for removal of NGLs for economic purposes is not a facility for transportation or sale for resale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the NGA. However, the FERC considers a processing plant used primarily for purposes related to transportation safety and efficiency to be subject to such regulation. We believe our gas processing plants are primarily involved in removing NGLs 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 current tests used by the FERC to determine nonjurisdictional 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 regulated.

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Liquified Natural Gas (LNG) Terminals.    LNG terminals operating in interstate commerce are subject to FERC jurisdiction and regulation of rates, terms and conditions of service. The FERC recently announced a new policy applicable to new LNG terminals, such as our proposed facility, which will apply less stringent regulation to such facilities as compared to that described above concerning interstate natural gas transportation and storage. Under this new policy, such LNG facilities need not operate on an open-access basis, and may offer rates, terms and conditions of service mutually agreed to with shippers, rather than as established by FERC. We recently received preliminary FERC approval to construct such a facility in Louisiana. We have entered into an agreement to sell this facility to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction is subject to the satisfaction of certain conditions and is expected to close in the early part of the second quarter.

Illinois Power Company.    IP is an electric utility company as defined in PUHCA. Its direct parent company, Illinova, and Dynegy are holding companies as defined in PUHCA. Illinova and Dynegy 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.

IP also is 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 IP exempt from the NGA and related FERC orders, rules and regulations.

IP is further subject to regulation by the State of Illinois and the Illinois Commerce Commission. The Illinois Public Utilities Act was significantly modified in December 1997 by the Electric Service Customer Choice and Rate Relief Law of 1997, or P.A. 90-561, but the ICC still has broad powers of supervision and regulation with respect to rates and charges and various other matters. Under P.A. 90-561, IP must continue to provide bundled retail electric services to all who choose to continue to take service at tariff rates and must provide unbundled electric distribution services to all eligible customers as defined by P.A. 90-561 and bundled rates were frozen at that time through December 31, 2004. P.A. 92-0537, enacted in June 2002, extended the rate freeze for bundled customers through December 31, 2006.

P.A. 90-561, as amended by P.A. 92-12, requires IP to participate in an Independent System Operator, or RTO. IP has announced its intention to join PJM Interconnection, L.L.C. On July 31, 2002, the FERC issued an order approving IP’s proposal to join PJM, subject to certain conditions. In 2002, IP reached an agreement with Trans-Elect, Inc. pursuant to which IP agreed to sell its transmission assets. Please read “—Regulated Energy Delivery Segment” for further discussion of the proposed Trans-Elect transaction. Should the sale be consummated, Trans-Elect has announced its intention to place IP’s transmission assets in the Midwest Independent Transmission System Operator, Inc. Any RTO in which IP ultimately participates will be subject to the outcome of the FERC’s proceedings on standardized market terms and conditions.

IP’s retail natural gas sales and distribution services also are regulated by the ICC. Such sales are currently priced under a purchased gas adjustment mechanism under which IP’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.

Natural Gas Regulation.    The transportation (including storage) and sale for resale of natural gas in interstate commerce is subject to regulation by the FERC under the Natural Gas Act of 1938, as amended, and, to a lesser extent, the Natural Gas Policy Act of 1978, as amended. The rates charged by interstate pipelines for interstate transportation and storage services, and the terms and conditions for provision of such services, are regulated by the FERC, which generally also must approve any changes to these rates or terms and conditions prior to their implementation. 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. Our Venice Gathering System is a regulated interstate pipeline.

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Commencing in 1992, the FERC issued Order No. 636 and subsequent orders, which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sales of gas. These orders also require pipelines to provide open-access transportation on a basis that is equal for all shippers. The FERC intends for these orders to foster increased competition within all phases of the natural gas industry. Prior to our acquisition of the Venice Gathering System, these orders did not directly regulate any of our activities; however, like other interstate pipelines, Venice Gathering System must comply with FERC’s open-access transportation regulations. The implementation of these orders has not had a material adverse effect on our results of operations. The courts have largely affirmed the significant features of these and numerous related orders pertaining to the individual pipelines, although some appeals remain pending and the FERC continues to review and modify its open-access regulations.

In 2000, the FERC issued Order No. 637 and subsequent orders, which imposed a number of additional reforms designed to enhance competition in natural gas markets. Among other things, these orders revised the FERC pricing policy by waiving price ceilings for short-term released interstate pipeline transportation capacity for a two-year period, and effected changes in the FERC regulations relating to interstate transportation scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting. Most major aspects of these orders were upheld on judicial review, though some issues were remanded to the FERC, have been considered on remand and are pending rehearing at the FERC. It is uncertain whether and to what extent the FERC’s market reforms will survive rehearing and further judicial review and, if so, whether the FERC’s actions will achieve the goal of further increasing competition in natural gas markets.

The FERC has proposed to expand its existing rules governing the conduct of interstate pipelines and their marketing affiliates to include all energy affiliates. If adopted, the proposed rule would, among other things, preclude the exchange of transportation-related information among an interstate pipeline and any of its energy affiliates. The FERC has stated that one purpose of the proposal is to allow pipeline affiliates and non-affiliates to compete in energy markets on an even basis. It is uncertain whether or when the FERC may adopt the proposed rule, or the extent to which it may affect the cost or other aspects of our operations; however, we do not anticipate that our regulated transmission provider and its energy affiliates will be impacted any differently than other similar industry participants.

Pursuant to the NGPA and the Wellhead Decontrol Act of 1989, most sales of natural gas are no longer subject to price controls. However, the FERC retains jurisdiction over certain sales made by interstate pipelines or their affiliates. Currently, the FERC has authorized such sales to be made at unregulated prices, terms and conditions. While sales of natural gas can currently be made at market prices, and upon unregulated terms and conditions, there is no assurance that such regulatory treatment will continue indefinitely in the future. Congress or, as to sales remaining subject to its jurisdiction, the FERC, could re-enact price controls or other regulation in the future.

State Regulatory Reforms.    Our domestic natural gas and power marketing, and power generation businesses are 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.    In the last legislative session, the United States Congress considered, but ultimately did not pass, a number of bills that could have impacted regulations applied to us and our subsidiaries, including bills that would repeal the PUHCA and portions of the PURPA and that would affect the FERC’s regulatory authority over energy marketing, generation and trading. Recent market events including the California electricity crisis in late 2000 and the alleged manipulation of electricity prices by Dynegy and other wholesale electricity merchants have prompted questions about the wisdom of the PUHCA repeal and whether more stringent regulation may be needed. We cannot predict with certainty what energy legislation may be considered in the current legislative session, whether any such legislation will become law or what effect any such new legislation might 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. In addition, development of projects in international markets creates exposure to and obligations under the national, provincial and local laws of each host country, including environmental standards and requirements imposed by these governments. Environmental laws and regulations, including environmental regulators’ interpretations of these laws and regulations, are complex, change frequently and have tended to become more stringent over time. Many environmental laws require permits from governmental authorities before construction on a project may be commenced 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 and regulations governing the siting 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 $82 million in 2002, compared to approximately $81 million in 2001 and approximately $121 million in 2000. We estimate that total environmental expenditures (both capital and operating) in 2003 will be approximately $52 million. A majority of our environmental expenditures relate to the federal Clean Air Act and comparable state laws and regulations. Management does not expect capital spending on environmental matters to increase materially over the near term; however, changes in environmental regulations or the outcome of litigation could result in additional requirements that could necessitate increased spending. Please read “—The Clean Air Act” below for a discussion of the litigation brought by the Environmental Projection Agency against two Dynegy affiliates 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 air quality regulations cannot be predicted with certainty, these regulations are expected to become increasingly stringent, particularly for electric power generating facilities. Clean Air Act requirements include the following:

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Multi-Pollutant Air Emission Initiatives.    Various multi-pollutant proposals have been introduced at the federal and state level. An example is the “Clear Skies Initiative” announced by the President in 2002. The “Clear Skies” proposal is aimed at long-term reductions of multiple pollutants produced from fossil fuel-fired power plants. Reductions averaging 70% are targeted for sulfur dioxide, NOx and mercury. In addition, the President has proposed a voluntary program for reducing greenhouse gas emissions such as carbon dioxide. The implementation of this initiative, if approved by Congress, would be via a market-based program, modeled after the Acid Rain Program, beginning in 2008 and phased full compliance by 2018. Fossil fuel-fired power plants in the United States would be affected by the adoption of this program, or other multi-pollutant legislation currently proposed by Congress addressing similar issues. Such programs would require compliance to be achieved by the installation of pollution controls, the purchase of emission allowances or curtailment of operations.

MACT.    The EPA has announced its determination to regulate hazardous air pollutants including mercury, from coal-fired and oil-fired steam electric generating units under Section 112 of the Clean Air Act. The EPA plans to develop maximum achievable control technology standards for these types of units. The rulemaking for coal and oil-fired steam electric generating units is expected to be completed by December 2004. Compliance with the rules will likely be required within three or four years thereafter.

The MACT standards that will be applicable to the units cannot be predicted at this time and could have an adverse impact on our operations. As well, we cannot predict the additional impact that the MACT standard would have over and above any proposed multi-pollutant legislation. Although the impact of possible future environmental requirements cannot be predicted with any degree of certainty, any expenditures that are ultimately required are not anticipated to have a more significant effect on our operations or financial condition than on any similarly situated company that generates electricity through the burning of fossil fuels.

Baldwin Station Litigation.    IP and DMG, referred to in this section as the Defendants, are currently the subject of a Notice of Violation, or NOV, from the EPA and a complaint filed by the EPA and the Department of Justice alleging violations of the Clean Air Act and the regulations promulgated under the Clean Air Act. Similar notices and complaints have been filed against a number of other utilities. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at the Defendants’ three Baldwin Station generating units in Illinois constituted “major modifications” under the Prevention of Significant Deterioration (PSD) and/or the New Source Performance Standards (NSPS) regulations. When activities that meet the definition of “major modifications” occur and are not otherwise exempt, the Clean Air Act and related regulations generally require that generating facilities meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment. The Defendants filed an answer denying all claims and asserting various specific defenses and a trial date of June 3, 2003 has been set.

We believe that the Defendants have meritorious defenses to the EPA allegations and will vigorously defend against these claims. On February 18, 2003, the Court granted the Defendants’ motion for partial summary judgment based on the five-year statute of limitations. As a result of the Court’s ruling, the EPA will not be able to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Order also precludes monetary civil penalties for a portion of the claims under the NSPS regulations. The Company has recorded a reserve for potential penalties that could be imposed if the EPA were to prosecute its claims successfully. Please read Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies beginning on page F-49 for further discussion of this lawsuit.

On December 31, 2002, the EPA proposed several reforms to its regulations governing new source review. These reforms would clarify the routine maintenance, repair and replacement exclusion, provide more certainty in evaluating permit requirements and increase operational flexibility for affected facilities.

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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. Although the renewal process has been underway from some time, joint legal action has been taken recently by several interested third parties. The petitioners in this matter are requesting that the permit renewal process be completed in an expeditious manner. In November 2001, the EPA promulgated rules that impose additional technology-based requirements on new cooling water intake structures. Draft rules for existing intake structures have also been issued. It is not known at this time what requirements the final rules for existing intake structures will impose or whether our existing intake structures will require modification as a result of such requirements.

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. The final impact on us as a result of these initiatives is unknown at this time; however, it is reasonable to assume that we would incur additional compliance costs as a result of the increased regulation of water quality.

Remedial Laws.    We are also subject to environmental remediation requirements, including provisions of the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and the corrective action provisions of the federal Resource Conservation and Recovery Act, or 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.

IP 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. IP 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 is considered probable from IP’s electric and gas customers.

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Pipeline Safety.    In addition to environmental regulatory issues, the design, construction, operation and maintenance of some of our pipeline facilities is subject to the safety regulations established by the Secretary of the U.S. Department of Transportation pursuant to the Natural Gas Pipeline Safety Act and the Hazardous Liquid Pipeline Safety Act, or by state regulations meeting the requirements of the NGPSA and the HLPSA, or to similar statutes, rules and regulations in Canada or other jurisdictions. In December 2000, the DOT adopted new regulations requiring operators of interstate pipelines to develop and follow an integrity management program that provides for continual assessment of the integrity of all pipeline segments that could affect so-called “high consequence” environmental impact areas, through periodic internal inspection, pressure testing or other equally effective assessment means. An operator’s program to comply with the new rule must also provide for periodically evaluating the pipeline segments through comprehensive information analysis, remediating potential problems found through the required assessment and evaluation, and assuring additional protection for the high consequence segments through preventative and mitigative measures. The requirements of this new DOT rule will likely increase the costs of pipeline operations.

In the wake of the September 11, 2001 terrorist attacks on the United States, the DOT has developed a security guidance document and has issued a security circular that defines critical pipeline facilities and appropriate countermeasures for protecting them, and explains how the DOT plans to verify that operators have taken appropriate action to implement satisfactory security procedures and plans. Using the guidelines provided by the DOT, we have specifically identified certain of our facilities as DOT “critical facilities” and therefore potential terrorist targets. In compliance with the DOT guidance, we are performing vulnerability analyses on such facilities. Additional security measures and procedures may be adopted or implemented upon completion of these analyses, and any such 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 facilities will not become the subject of a terrorist attack. Please read “—Operational Risks and Insurance” beginning on page 30 for further discussion.

Health and Safety.    Our operations are subject to the requirements of the Federal Occupational Safety and Health Act (“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 IP and DMG, which are described in Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies beginning on page F-49, 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 previously owned or operated by us, which could reasonably be expected to have a material adverse effect on our operations and financial condition.

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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 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 adequate for such risks. Such insurance is subject to deductibles that we consider reasonable and not excessive given the current insurance market environment. 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. In addition, the terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to those attacks have made some types of insurance more difficult or costly to obtain. We may be unable to secure the levels and types of insurance we would otherwise have secured prior to September 11, 2001. No assurance can be given that we will be able to maintain adequate levels of insurance in the future at rates we consider reasonable.

In our CRM segment, we also face market, price, credit and other risks relative to our orderly exit from third-party risk-management aspects of the gas and power marketing and trading business. Please read Item 7A, Quantitive and Qualitative Disclosures About Market Risk, beginning on page 82 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 14, Controls and Procedures beginning on page 87 for further discussion of our internal control systems and the efforts that we are undertaking with respect to such systems.

SIGNIFICANT CUSTOMER

For the years ended December 31, 2002, 2001 and 2000, approximately 14%, 10% and 13% of our consolidated revenues and approximately 41%, 45% and 41% 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 2002, 2001 or 2000.

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EMPLOYEES

At December 31, 2002, we had approximately 1,524 employees at our administrative offices and approximately 3,102 employees at our operating facilities. Approximately 1,873 employees at Dynegy-operated facilities are subject to collective bargaining agreements with various unions. Management believes that its relations with Dynegy employees are satisfactory.

Item 1A.    Executive Officers

Set forth below are the names and positions of our executive officers as of March 31, 2003 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 is our President and Chief Executive Officer. He is also a member of our Board of Directors. He has served in each of these capacities since joining us in October 2002. Prior to joining us, Mr. Williamson served in various capacities for 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 communications and international business positions. Mr. Williamson joined the Duke family of companies in 1997 following the Duke Power and PanEnergy Corporation merger. 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 is the President and Chief Executive Officer of our Dynegy Generation segment. He has served in this position since October 2002, when we restructured our company into three operating divisions. 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 IP. 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.

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Stephen A. Furbacher is President and Chief Executive Officer of Dynegy Midstream Services, Limited Partnership. He has served in this position 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 1973 and served in positions of increasing responsibility before being named President of Warren Petroleum Company in 1994.

Larry F. Altenbaumer is President and Chief Executive Officer of IP. He has served as President of IP since September 1999 and as Chief Executive Officer since November 2002. 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 IP. He joined IP in 1970 and previously served IP in positions of increasing responsibility, including as Senior Vice President and Chief Financial Officer from 1992 until September 1999.

Nick J. Caruso is our Executive Vice President and Chief Financial Officer. He has served in this position since joining us in December 2002. Mr. Caruso is responsible for our internal audit, risk management, tax, treasury, investor relations, accounting and finance functions. He was previously employed by Shell Oil Company from 1969 to 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 is our Executive Vice President and General Counsel. She has served in this capacity 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 1998, she served as general counsel for Conoco Global Power, Inc.

R. Blake Young is our Executive Vice President of Administration and Technology. He has served in this capacity since October 2002. Formerly President of Global Technology, Mr. Young is responsible for corporate technology, corporate communications, human resources, strategic planning, divestitures and corporate shared services. Prior to joining us in 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 2. Those descriptions are incorporated herein by this reference.

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

Item 3.    Legal Proceedings

For a description of our material legal proceedings, please read Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies, beginning on page F-49, 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 2002.

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PART II

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 28, 2003, based upon records of registered holders maintained by our transfer agent, was 23,151.

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, 2002 and 2001, 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. Please read “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 56 for further discussion.

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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 material provisions of which are discussed below. The agreement was executed in February 2000 upon closing of the Illinova acquisition 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. Before the Illinova acquisition, Chevron owned 38,789,876 shares of our common stock and 7,815,363 shares of our preferred stock. In connection with the Illinova acquisition, Chevron exchanged its common stock and preferred stock and paid $200 million in return for an aggregate of 40,521,250 shares of our Class B common stock.

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. In addition, Chevron and its affiliates may acquire up to 40 percent of the total combined voting power of our outstanding voting securities without restriction in the shareholder agreement. If Chevron or its affiliates wish to acquire more than 40 percent 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 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:

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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 transaction listed above. 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.

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 percent 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.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table sets forth certain information as of December 31, 2002 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.

The historical information contained in the table below has been revised to reflect the restatement items otherwise contained in Amendment No. 2 to our 2001 Form 10-K. Please read the Explanatory Note to the accompanying financial statements beginning on page F-8 for further discussion of these restatements.

Dynegy’s Selected Financial Data

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