Edgar Filing: DYNEGY INC /IL/

Amendment No. 1 to Form 10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

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

For the fiscal year ended December 31, 2002

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

For the transition period from to

Commission file number: 1-15659

DYNEGY INC.

(Exact name of registrant as specified in its charter)

Illinois		74-2928353
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification Number)

1000 Louisiana, Suite 5800
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

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

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

Title of each class		Name of each exchange on which registered
Class A common stock, no par value		New York Stock Exchange

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

Title of each class		Name of each exchange on which registered
None		—

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.

DYNEGY INC. FORM 10-K/A

INTRODUCTORY NOTE

Dynegy Inc. is filing this Amendment No. 1 on Form 10-K/A (“Amendment No. 1”) to reflect the effect of the following items on our historical consolidated financial statements and related information, as reported in our Annual Report on Form 10-K for the fiscal year ended December 31, 2002, which was originally filed on April 11, 2003 (the “Original Filing”):

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reclassifications necessary to present the results of our global communications and United Kingdom customer risk management businesses as discontinued operations for the three years in the period ended December 31, 2002 in accordance with Statement of Financial Accounting Standards (“Statement”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” as a result of events that required us to begin accounting for such businesses as discontinued operations in the first quarter 2003;

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reclassifications necessary to present our segment information for the three years in the period ended December 31, 2002 consistent with our current segment reporting structure, which structure was implemented beginning January 1, 2003, in order to better reflect our ongoing asset-based business operations;

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the pro forma financial statement effect for each of the three years in the period ended December 31, 2002, as if we had adopted Statement No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2000;

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disclosures relating to the previously reported restatement of our 2000 and 2001 financial statements. These same disclosures were included in Amendment No. 2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2001, which was filed on April 11, 2003 (the “2001 Form 10-K/A”), and do not reflect additional restatements to the 2000 and 2001 financial statements as contained in the 2001 Form 10-K/A; and

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other minor revisions.

None of the aforementioned items, which are discussed in more detail in the Explanatory Note to the accompanying consolidated financial statements beginning on page F-8, affect net income for any of the three years in the period ended December 31, 2002. Our periodic SEC reports, including this Amendment No. 1, remain subject to an ongoing review by the SEC Division of Corporation Finance.

The following Items of the Original Filing are amended by this Amendment No. 1:

Item 1. Business

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

Item 6. Selected Financial Data

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

Item 8. Financial Statements and Supplementary Data

Item 13. Certain Relationships and Related Transactions

Item 14. Controls and Procedures

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

Unaffected items have not been repeated in this Amendment No. 1.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER THE DATE OF THE ORIGINAL FILING. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR QUARTERLY REPORT ON FORM 10-Q FOR THE PERIOD ENDED MARCH 31, 2003 AND THE EVENTS SUBSEQUENTLY DESCRIBED IN OUR CURRENT REPORTS ON FORM 8-K. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE APRIL 11, 2003, INCLUDING OUR QUARTERLY REPORT ON FORM 10-Q FOR THE PERIOD ENDED MARCH 31, 2003 AND OUR CURRENT REPORTS ON FORM 8-K.

DYNEGY INC.

FORM 10-K/A

TABLE OF CONTENTS

		Page
PART I
Definitions		1
Item 1.	Business	3

PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	32
Item 6.	Selected Financial Data	36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 8.	Financial Statements and Supplementary Data	82

PART III
Item 13.	Certain Relationships and Related Transactions	83

PART IV
Item 14.	Controls and Procedures	84
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	85
Signatures		90

PART I

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER APRIL 11, 2003 (THE DATE OF THE ORIGINAL FILING). SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR QUARTERLY REPORT ON FORM 10-Q FOR THE PERIOD ENDED MARCH 31, 2003 AND THE EVENTS SUBSEQUENTLY DESCRIBED IN OUR CURRENT REPORTS ON FORM 8-K. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE APRIL 11, 2003, INCLUDING OUR QUARTERLY REPORT ON FORM 10-Q FOR THE PERIOD ENDED MARCH 31, 2003 AND OUR CURRENT REPORTS ON FORM 8-K.

DEFINITIONS

As used in this Amendment No. 1, the terms listed below are defined as follows:

Amendment No. 1		Amendment No. 1 to the Dynegy Inc. Form 10-K for the year ended December 31, 2002.
AmerGen		AmerGen Energy Company, LLC
Bcf/d		Billions of cubic feet per day.
BGSL		BG Storage Limited.
Btu		British thermal unit—a measure of the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit.
Cal ISO		The California Independent System Operator.
Cal PX		The California Power Exchange.
Catlin		Catlin Associates, L.L.C.
CBF		Cedar Bayou Fractionators, L.P., an entity in which we have an 88% ownership interest.
CDWR		The California Department of Water Resources.
CERCLA or Superfund		Comprehensive Environmental Response, Compensation and Liability Act.
CRM		Our customer risk management business segment.
DGC		Dynegy Global Communications, Inc.
DHI		Dynegy Holdings Inc., a wholly owned subsidiary of Dynegy Inc.
DMG		Dynegy Midwest Generation, Inc.
DMS		Dynegy Midstream Services.
DNE		Dynegy Northeast Generation.
DOT		The U.S. Department of Transportation.
EITF		Emerging Issues Task Force.
EWGs		Exempt Wholesale Generators.
FASB		Financial Accounting Standards Board.
FERC		Federal Energy Regulatory Commission.
FPA		The Federal Power Act.
GAAP		Generally Accepted Accounting Principles.
GCF		Gulf Coast Fractionators, an entity in which we have a 23% ownership interest.
GEN		Our power generation business segment.
HLPSA		The Hazardous Liquid Pipeline Safety Act.
HP		Horsepower.
ICC		Illinois Commerce Commission.
Investor		Black Thunder Investors LLC.
IP		Illinois Power Company, a wholly owned subsidiary of Illinova.
kWh		Kilowatt hours.
LMP		Locational marginal pricing methodology.
LNG		Liquefied natural gas.
LPG		Liquefied petroleum gas.
MACT		Maximum Achievable Control Technology.
MBbls/d		Thousands of barrels per day.

MGP		Manufactured Gas Plant.
MMBtu		Millions of Btu.
MMCFD		Millions of cubic feet per day.
MW		Megawatts.
NGA		The Natural Gas Act of 1938, as amended.
NGL		Our natural gas liquids business segment.
NGLs		Natural gas liquids.
NGPA		The Natural Gas Policy Act of 1978, as amended.
NGPSA		The Natural Gas Pipeline Safety Act.
NOV		Notice of Violation.
NSPS		New Source Performance Standards.
NYISO		New York Independent System Operator.
Original Filing		Dynegy Inc.’s Form 10-K for the year ended December 31, 2002 filed on April 11, 2003.
OSHA		The Federal Occupational Safety and Health Act.
PJM		Pennsylvania-New Jersey-Maryland market.
Project Alpha		A structured natural gas transaction entered into by Dynegy in April 2001.
PUCT		Public Utility Commission of Texas.
PUHCA		The Public Utility Holding Company Act of 1935.
PURPA		The Public Utilities Regulatory Policies Act of 1978.
RCRA		The Resource Conversation and Recovery Act.
QFs		“Qualifying facilities” are power generation facilities that typically sell power to a single purchaser and are generally exempt from FERC ratemaking regulation.
REG		Our regulated energy delivery segment.
RTOs		Regional transmission organizations established by the FERC to control electric transmissions facilities within a particular region.
SEC		U.S. Securities and Exchange Commission.
SERC		Southeast Electric Reliability Council.
SFAS		Statement of Financial Accounting Standards.
T&D		Transmission and Distribution.
UCAP		Unforced capacity market.
VaR		Value at Risk.
Versado		Versado Gas Processors, L.L.C.
VESCO		Venice Energy Services Company, L.L.C.
VLGCs		Very Large Gas Carriers.
WECC		Western Electricity Coordinating Council.
WEN		Wholesale Energy Network.
West Seminole		West Seminole natural gas gathering system, a Dynegy joint venture.
WTI		West Texas Intermediate.

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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The sale of Northern Natural Gas Company;

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The sale of our U.K. natural gas storage business;

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The sale of our global liquids business;

•

Major progress towards our exit from the third-party marketing and trading, or customer risk management business, including the completion of our exit from European marketing and trading and the transition of ChevronTexaco Corporation’s natural gas marketing business back to ChevronTexaco, and the reduction in associated collateral requirements;

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The sale of our European communications business;

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The execution of an agreement to sell our U.S. communications business;

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The extension of the maturity of our two primary bank credit facilities until February 2005 and the restructuring of our communications lease financing; and

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Considerable workforce reductions, which we expect will provide substantial general and administrative cost savings.

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 Amendment No. 1.

SEGMENT DISCUSSION

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

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Power generation;

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Natural gas liquids;

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Regulated energy delivery; and

•

Customer risk management.

Other reported results 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 “Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” beginning on page 59 of this Amendment No. 1 to reflect changes that we made to our reporting segments beginning January 1, 2003. In the Original Filing, we reported our historical segment results 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 now comprise the Power Generation segment. The Wholesale Energy Network segment’s other former operations, to the extent such operations continue, comprise the Customer Risk Management segment. The remaining operations of our former Dynegy Global Communications segment are being 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 continue to be reported as their own respective segments.

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)

Region/Facility	Location	Total Net Generating Capacity (MW)	Primary Fuel Type	Dispatch Type
Midwest-MAIN
Baldwin	Baldwin, IL	1,751	Coal	Baseload
Havana:
Havana Units 1-5	Havana, IL	238	Oil	Peaking
Havana Unit 6	Havana, IL	428	Coal	Baseload
Hennepin	Hennepin, IL	289	Coal	Baseload
Oglesby	Oglesby, IL	60	Gas	Peaking
Stallings	Stallings, IL	77	Gas	Peaking
Tilton(2)	Tilton, IL	176	Gas	Peaking
Vermillion	Oakwood, IL	186	Coal	Baseload
Wood River:
Wood River Units 1-3	Alton, IL	139	Gas	Peaking
Wood River Units 4-5	Alton, IL	468	Coal	Baseload
Rocky Road(3)	East Dundee, IL	168	Gas	Peaking
Joppa(4)	Joppa, IL	232	Coal	Baseload

Combined		4,212
Midwest-ECAR
Michigan Power(3)	Ludington, MI	62	Gas	Baseload
Riverside	Louisa, KY	500	Gas	Peaking
Rolling Hills(5)	Wilkesville, OH	838	Gas	Peaking
Foothills	Louisa, KY	322	Gas	Peaking
Renaissance	Carson City, MI	690	Gas	Peaking
Bluegrass	Oldham Co., KY	500	Gas	Peaking

Combined		2,912
Northeast-NPCC
Roseton(6)	Newburgh, NY	1,200	Gas/ Oil	Intermediate
Danskammer:
Danskammer Units 1–2	Newburgh, NY	130	Gas/ Oil	Peaking
Danskammer Units 3-4(6)	Newburgh, NY	370	Coal/Gas	Baseload

Combined		1,700
Southeast-SERC
Calcasieu	Lake Arthur, LA	323	Gas	Peaking
Heard County	Heard County, GA	500	Gas	Peaking
Rockingham	Rockingham, NC	818	Gas/ Oil	Peaking
Hartwell(3)	Hartwell, GA	150	Gas	Peaking
Commonwealth(3)	Chesapeake, VA	170	Gas	Peaking

Combined		1,961
West-WECC
Ferndale(7)	Ferndale, WA	12	Gas	Baseload
Long Beach(8)	Long Beach, CA	265	Gas	Peaking
Cabrillo I—Encina(8)	Carlsbad, CA	483	Gas	Intermediate
Black Mountain(9)	Las Vegas, NV	43	Gas	Baseload
El Segundo:
El Segundo Units 1-2(8)(10)	El Segundo, CA	175	Gas	Intermediate
El Segundo Units 3-4(8)	El Segundo, CA	335	Gas	Intermediate
Cabrillo II:
Cabrillo II (4 units) (8)(10)	San Diego, CA	34	Gas	Peaking
Cabrillo II (9 units)(8)	San Diego, CA	93	Gas	Peaking

Combined		1,440
Texas-ERCOT
Paris(11)	Paris, TX	37	Gas	Baseload
Frontier(12)	Grimes Co., TX	83	Gas	Baseload
CoGen Lyondell	Houston, TX	610	Gas	Baseload
Oyster Creek(3)	Freeport, TX	212	Gas	Baseload

Combined		942

TOTAL		13,167

(1)

We own 100% of each unit listed except as otherwise indicated.

(2)

We lease this facility pursuant to an off-balance sheet lease arrangement that is further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements” beginning on page 48.

(3)

We own a 50% interest in this facility.

(4)

We own a 20% interest in this facility.

(5)

This facility is under construction, with completion expected in the second quarter 2003.

(6)

We lease the Roseton facility and units 3 and 4 of the Danskammer facility pursuant to a leveraged lease arrangement that is further described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Off-Balance Sheet Arrangements” beginning on page 48.

(7)

We own a 5% interest in this facility.

(8)

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

(9)

We own a 50% interest in this facility through a joint venture with ChevronTexaco.

(10)

We shut these units down at the end of 2002 because we deemed them no longer commercially viable.

(11)

We own a 16% interest in this facility.

(12)

We own a 10% interest in this facility.

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—DMG Secured Debt beginning on page F-53 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 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 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—Renaissance and Rolling Hills Credit Facility beginning on page F-52 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 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—Power Generation Regulation” beginning on page 23.

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 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—FERC and Related Regulatory Investigations—Western Long-Term Contract Complaints beginning on page F-68 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.

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, the quantity of oxides of nitrogen emitted into the air from our California power generation facilities is regulated by local air districts in California. The specific regulations and procedures vary by district, but the air districts generally issue emissions allocations, which we refer to as “emission credits,” that allow us to produce specified quantities of emissions through the normal operations of our power generating facilities located within the respective air districts. If the quantities produced exceed those quantities that were allocated, we could be subject to mitigation fees. However, markets exist for the purchase and sale of emission credits and, from time to time, we either purchase emission credits from third parties in quantities sufficient to operate our plants within the emission guidelines of the various air districts or pay mitigation fees to the applicable air district as required.

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—Power Generation Regulation” beginning on page 23 and Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies—California Market Litigation beginning on page F-65 and “—FERC and Related Regulatory Investigations” beginning on page F-66.

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.

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—FERC and Related Regulatory Investigations—Western Long-Term Contract Complaints beginning on page F-68 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 19 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 natural gas liquids marketing business. This segment has both upstream and downstream components. The upstream components include natural gas gathering and processing, while the downstream components include fractionating, storing, terminalling, transporting, distributing and marketing 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 natural gas liquids distribution and marketing operations.

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

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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.

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.

LOGO

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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56% of the volumes we process will be under percentage of liquids arrangements;

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19% of the volumes will be under percentage of proceeds contracts;

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15% of the volumes will be under keep-whole contracts;

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9% of the volumes will be under economic election contracts; and

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the remaining 1% will be under wellhead purchase contracts.

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.

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. natural gas liquids business, and West Louisiana. The following map depicts our downstream assets in their current locations, including our capacity and throughput capabilities.

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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:

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ethane, or a mixture of ethane and propane known as EP mix;

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propane;

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normal butane;

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isobutane; and

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natural gasoline.

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.

Storage. Our natural gas liquids storage facilities have extensive pipeline connections to third-party pipelines, third-party facilities and to our own fractionation and terminalling facilities. In addition, 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 natural gas liquids 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:

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access to up to 2,000 railcars that we manage pursuant to a services agreement with ChevronTexaco;

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87 transport tractors and 114 tank trailers;

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over 580 miles of gas liquids pipelines, primarily in the North Texas, Gulf Coast and Permian basin regions; and

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21 pressurized LPG barges.

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:

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refinery services;

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wholesale propane marketing; and

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purchasing mixed NGLs and natural gas liquids products from natural gas liquids producers and other sources and selling the natural gas liquids products to petrochemical manufacturers, refineries and other marketing and retail companies.

Our refinery services business consists of providing LPG balancing services, purchasing natural gas liquids products from refinery customers and selling natural gas liquids 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 natural gas liquids 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 natural gas liquids 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.

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 natural gas liquids 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 natural gas liquids production and also purchase natural gas liquids products from other natural gas liquids 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 natural gas liquids products from producers under contract. We also earn margins by purchasing and reselling natural gas liquids 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 natural gas liquids sales were made to ChevronTexaco or one of its affiliates pursuant to the refinery agreements discussed above and pursuant to an agreement we have with Chevron Phillips Chemical Company. In the latter agreement, we supply most of Chevron Phillips Chemical’s natural gas liquids feedstock needs in the Mont Belvieu area and collect a cents-per-barrel fee for storage and product delivery.

Regulated Energy Delivery

General. Our 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.

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—Dispositions—Discontinued Operations—Northern Natural beginning on page F-27 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 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—Illinois Power Company” beginning on page 25 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

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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Purchases and sales of natural gas and power;

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Procurement of natural gas transportation services for our customers through pipelines owned by third parties;

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Storage of natural gas inventories in leased facilities for the purpose of offering peak delivery services to our customers;

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Management of power tolling arrangements in which we pay a fee for access to power generated by facilities that are owned and operated by third parties; and

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Execution of third-party, derivative financial instruments to manage the risks associated with commodity price fluctuations on behalf of our customers.

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:

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In September and November 2002, we sold the subsidiaries that owned our U.K. natural gas storage business;

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In November 2002, we sold a portion of our Canadian natural gas marketing business;

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In December 2002, we terminated a previously existing long-term power tolling arrangement; and

•

In January 2003, we announced the sale of our Canadian retail electricity marketing business.

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.

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

Project	Location	Heat Rate	MW	Term

Dahlberg	Georgia	12,500	225	May 2005
Daniel	Mississippi	7,150	260	May 2011
Goat Rock(1)	Alabama	6,900	625	May 2030
Sithe Independence	New York	7,400	915	Nov. 2014
Sterlington/Quachita	Louisiana	6,950	835	Sept. 2017(2)
Kendall	Illinois	7,300	550	June 2012
Gregory	Texas	8,800	335	July 2005
Batesville	Mississippi	7,250	110	May 2010

(1)

Project in development; contract begins in June 2005.

(2)

Includes a five-year extension option pursuant to which either party can elect to continue the arrangement depending on the market price for power at the expiration of the initial contract term.

Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Customer Risk Management—CRM Outlook” beginning on page 73 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 global 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.

COMPETITION

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

Natural Gas Liquids. Our natural gas liquids businesses face significant and varied competitors, including major integrated oil companies, major pipeline companies and their marketing affiliates and national and local gas gatherers, processors, fractionators, brokers, marketers and distributors of varying sizes and experience. The principal areas of competition include obtaining gas supplies for gathering and processing operations, obtaining supplies of raw product for fractionation, purchase and marketing of 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—Illinois Power Company”. 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.

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—FERC and Related Regulatory Investigations—Other FERC and California Investigations beginning on page F-67.

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

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 “—Regulation—Power Generation Regulation” beginning on page 23 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 “—Regulation—Illinois Power Company” beginning on page 25.

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.

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 “—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Regulated Energy Delivery—REG Outlook” beginning on page 71 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.

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.

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 “—Environmental and Other Matters—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:

•

The Clean Air Act Amendments of 1990 required a two-phase reduction by electric utilities in emissions of sulfur dioxide and nitrogen oxide by 2000 as part of an overall plan to reduce acid rain in the eastern United States. Installation of control equipment and changes in fuel mix and operating practices have been completed at our facilities as necessary to comply with the emission reduction requirements of the acid rain provision of the Clean Air Act Amendment of 1990.

•

In October 1998, the EPA issued a final rule on regional ozone control that required 22 eastern states and the District of Columbia to revise their State Implementation Plans to significantly reduce emissions of nitrogen oxide. The current compliance deadline for implementation of these emission reductions is May 31, 2004. In January 2000, the EPA finalized another ozone-related rule under Section 126 of the Clean Air Act that has similar emission control requirements. The required capital expenditures and

installation of the necessary emission control equipment to meet these requirements has been largely completed; consequently, we expect the power generation system will meet the specified compliance deadlines for implementation. Portions of our NGL businesses are also subject to these rules. We have plans in place to satisfy these requirements and expect to incur capital expenditures of approximately $6.5 million pursuant to such plans.

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—Baldwin Station Litigation beginning on page F-64 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.

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.

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. We believe that such costs will not be material to our financial position or results of operations.

In the wake of the September 11, 2001 terrorist attacks on the United States, the 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 31 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—Baldwin Station Litigation beginning on page F-64, 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.

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 costs associated with these insurance coverages have increased significantly during recent periods, and may continue to increase into the future. The occurrence of a significant event not fully insured or indemnified against, or the failure of a party to meet its indemnification obligations, could materially and adversely affect our operations and financial condition. 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, particularly terrorism and business interruption 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. While we currently maintain levels and types of insurance that we believe to be prudent under current insurance industry market conditions, our potential inability to secure these levels and types of insurance into the future could negatively impact our business operations and financial stability, particularly if an uninsured loss were to occur. No assurance can be given that we will be able to maintain these levels of insurance in the future at rates we consider commercially reasonable.

In our CRM segment, we also face market, price, credit and other risks relative to our 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 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 84 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 15%, 10% and 13% of our consolidated revenues and approximately 42%, 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.

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.

PART II

Item

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

Our Class A common stock, no par value per share, is listed and traded on the New York Stock Exchange under the ticker symbol “DYN”. The number of stockholders of record of our Class A common stock as of February 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

	High		Low		Dividend
2002:
Fourth Quarter	$	1.35	$	0.68	$	—
Third Quarter		6.80		0.51		—
Second Quarter		30.09		6.08		0.075
First Quarter		32.00		21.25		0.075
2001:
Fourth Quarter	$	46.94	$	20.90	$	0.075
Third Quarter		48.24		31.27		0.075
Second Quarter		57.95		42.00		0.075
First Quarter		53.15		39.25		0.075

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. Please also read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Bank Restructuring” beginning on page 42 for a discussion of dividend limitations contained in our restructured credit facility.

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:

•

a widely-dispersed public offering;

•

an unsolicited sale to a third party, provided that we or our designee are given the opportunity to purchase the shares proposed to be sold by Chevron; or

•

a solicited sale to an acceptable third party, provided that if we advise Chevron that the sale to a third party is not acceptable, we must purchase all of the offered shares for cash at a purchase price equal to 105% of the third party offer.

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:

•

the issuance of new shares of stock where the aggregate consideration to be received exceeds the greater of $1 billion or one-quarter of our total market capitalization;

•

any disposition of all or substantially all of our liquids business or gas marketing business while substantial agreements between Chevron and us exist (except for a contribution of such liquids business to an entity in which we have a majority direct or indirect interest);

•

any merger, consolidation, joint venture, liquidation, dissolution, bankruptcy, acquisition of stock or assets, or issuance of common or preferred stock, any of which would result in payment or receipt of consideration having a fair market value exceeding the greater of $1 billion or one-quarter of our total market capitalization; or

•

any other material transaction or series of related transactions which would result in the payment or receipt of consideration having a fair market value exceeding the greater of $1 billion or one-quarter of our total market capitalization.

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:

•

issuing any shares of Class B common stock to any person other than Chevron and its affiliates;

•

amending any provisions in our Articles of Incorporation or Bylaws which, in each case, contain or implement the special rights of holders of Class B common stock, without the consent of the holders of the shares of Class B common stock or the three directors elected by such holders;

•

adopting a shareholder rights plan, “poison pill” or similar device that prevents Chevron from exercising its rights to acquire shares of common stock or from disposing of its shares when required by us; and

•

acquiring, owning or operating a nuclear power facility, other than being a passive investor in a publicly-traded company that owns a nuclear facility.

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.

Sales of Unregistered Securities

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

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

During 2000, we sold approximately 4.2 million shares of Class B common stock to Chevron at a weighted average price per share of $25.65 in private transactions under Section 4(2) of the Securities Act pursuant to the exercise of its preemptive rights under the shareholder agreement. Additionally, Chevron purchased approximately 8.4 million shares of Class B common stock at $23.91 per share in a private transaction under Section 4(2) of the Securities Act concurrent with the acquisition of Illinova in February 2000. Total net proceeds to us from these 2000 sales approximated $310 million.

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.

Plan Category	Number of Securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	22,452,885	$	19.38	14,694,779
Equity compensation plans not approved by security holders (1)	5,629,380	$	26.16	4,574,539

Total	28,082,265	$	20.74	19,269,318

(1)

The plans that were not approved by our security holders are as follows: Extant Plan, Dynegy 2001 Non-Executive Stock Incentive Plan and Dynegy UK Plan. Please read Item 8, Financial Statements and Supplementary Data, Note 16—Capital Stock—Stock Options beginning on page F-81 for a brief description of our equity compensation plans, including these plans which were not approved by our security holders.

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 information contained in the table below has been revised primarily to reflect the reclassification relating to discontinued operations as further described in the Introductory Note to this Amendment No. 1. Please also read the Explanatory Note to the accompanying financial statements beginning on page F-8 for a discussion of the previously reported restatement of our 1998-2001 consolidated financial statements.

Dynegy’s Selected Financial Data

	Year Ended December 31,
	2002			2001			2000			1999			1998(7)
				(Restated)			(Restated)			(Restated)			(Restated)
	($ in millions, except per share data)
Statement of Operations Data(1):
Revenues(6)	$	5,516		$	8,878		$	8,204		$	4,695		$	3,807
General and administrative expenses		325			420			312			208			175
Depreciation and amortization expense		466			456			390			115			113
Asset impairment, abandonment and other charges		190			—			—			—			10
Goodwill impairment		897			—			—			—			—
Operating income (loss)		(1,141	)		967			766			184			100
Interest expense		(297	)		(255	)		(247	)		(77	)		(75	)
Income tax provision (benefit)		(276	)		357			234			41			63
Net income (loss) from continuing operations		(1,349	)		486			409			93			57
Income (loss) on discontinued operations(3)		(1,154	)		(82	)		27			44			30
Cumulative effect of change in accounting principle		(234	)		2			—			—			—
Net income (loss)	$	(2,737	)	$	406		$	436		$	137		$	87
Net income (loss) available to common stockholders		(3,067	)		364			401			137			87
Earnings (loss) per share from continuing operations	$	(4.59	)	$	1.31		$	1.18		$	0.41		$	0.25
Net income (loss) per share		(8.38	)		1.07			1.27			0.60			0.38
Shares outstanding for diluted EPS calculation		418			340			315			230			227
Cash dividends per common share	$	0.15		$	0.30		$	0.25		$	0.04		$	0.04
Cash Flow Data:
Cash flows from operating activities	$	(25	)	$	550		$	420		$	40		$	251
Cash flows from investing activities		677			(3,828	)		(1,539	)		(391	)		(295	)
Cash flows from financing activities		(44	)		3,450			1,131			399			50
Cash dividends or distributions to partners, net		(55	)		(98	)		(112	)		(8	)		(8	)
Capital expenditures, acquisitions and investments		(981	)		(4,687	)		(2,415	)		(521	)		(478	)

	December 31,
	2002			2001			2000			1999			1998
				(Restated)			(Restated)			(Restated)			(Restated)
	($ in millions)
Balance Sheet Data (2):
Current assets	$	7,586		$	8,956		$	10,827		$	2,658		$	2,117
Current liabilities		6,748			8,538			10,286			2,467			2,026
Property and equipment, net		8,389			9,201			7,081			2,090			1,932
Total assets		20,030			25,168			22,662			6,451			5,264
Long-term debt (excluding current portion)		5,454			5,016			3,754			1,372			953
Notes payable and current portion of long-term debt		861			458			118			192			135
Non-recourse debt		—			—			—			35			94
Serial preferred securities of a subsidiary		11			46			46			—			—
Company obligated preferred securities of subsidiary trust		200			200			300			200			200
Series B convertible preferred securities(4)		1,212			882			—			—			—
Minority interest(5)		146			1,040			1,022			—			—
Capital leases not already included in long-term debt		15			29			15			—			—
Total equity		2,087			4,937			3,441			1,240			1,073

(1)

The following acquisitions were accounted for in accordance with the purchase method of accounting and the results of operations attributable to the acquired businesses are included in our financial statements and operating statistics beginning on the acquisitions’ effective date for accounting purposes:

•

Northern Natural – February 1, 2002;

•

BGSL – December 1, 2001;

•

iaxis – March 1, 2001;

•

Extant – October 1, 2000; and

•

Illinova – January 1, 2000

(2)

The Northern Natural, BGSL, iaxis, Extant and Illinova acquisitions were each accounted for under the purchase method of accounting. Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values as of the effective dates of each transaction. See note (1) above for respective effective dates.

(3)

Discontinued operations includes the results of operations from the following businesses:

•

Northern Natural (sold August 2002);

•

UK Storage—Hornsea facility (sold October 2002) and Rough facility (sold November 2002);

•

DGC Asia (sold November 2002); and

•

Global Liquids (sold December 2002).

In addition, during the first quarter 2003, we began to report the results of operations of our U.K. CRM operations and the remaining components of our global communications operations as discontinued operations in accordance with Statement No. 144. Accordingly, we have reclassified prior period amounts to reflect this accounting treatment. For further discussion, please read Item 8, Financial Statements and Supplementary Data, Note 3—Dispositions, Discontinued Operations and Acquisitions—Discontinued Operations beginning on page F-27.

(4)

The 2002 amount equals the $1.5 billion in proceeds related to the Series B convertible preferred securities less the $660 million implied dividend recognized in connection with the beneficial conversion option plus $372 million in accretion of the implied dividend through December 31, 2002. The 2001 amount equals the $1.5 billion in proceeds less the $660 million implied dividend plus $42 million in accretion of the implied dividend through December 31, 2001. Please read Item 8, Financial Statements and Supplementary Data, Note 13—Redeemable Preferred Securities—Series B Convertible Preferred Securities beginning on page F-61 for further discussion.

(5)

The 2001 and 2000 amounts include amounts relating to the Black Thunder transaction discussed in Item 8, Financial Statements and Supplementary Data, Note 10—Debt—DMG Secured Debt beginning on page F-53.

(6)

As further discussed in Item 8, Financial Statements and Supplementary Data, Note 2—Accounting Policies—Revenue Recognition beginning on page F-21, revenue amounts have been restated to reflect the adoption of the net presentation provisions in EITF 02-03.

(7)

The consolidated financial statements for the year ended December 31, 1998 were audited by other independent accountants who have ceased operations.

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

The following discussion and analysis should be read in conjunction with the consolidated financial statements of Dynegy Inc. (“Dynegy,” “we,” “us” or “our” ) and the notes thereto included herein. As discussed in the Introductory Note to this Amendment No. 1, certain financial and other information contained herein has been revised to reflect the reclassifications and other revisions described in the Explanatory Note to the accompanying consolidated financial statements. Please read the Explanatory Note for a discussion of these items as well as the previously reported restatement of our 1998-2001 consolidated financial statements.

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 begun the process of decreasing our substantial financial leverage. Significant accomplishments include the following:

•

The sale of Northern Natural;

•

The sale of our U.K. natural gas storage business;

•

The sale of our global liquids business;

•

Major progress towards our exit from the third-party marketing and trading, or customer risk management business, including the completion of our exit from European marketing and trading and the transition of ChevronTexaco’s natural gas marketing business back to ChevronTexaco, and the reduction in associated collateral requirements;

•

The sale of our European communications business;

•

The execution of an agreement to sell our U.S. communications business;

•

The extension of the maturity of our two primary bank credit facilities until February 2005 and the restructuring of our communications lease financing; and

•

Considerable workforce reductions, which we expect will provide substantial general and administrative cost savings.

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 customer risk management business, including obligations relating to the eight long-term power tolling arrangements to which we remain a party, will continue to affect our future results of operations until the related obligations have been satisfied or restructured. Our results will also be significantly affected by higher borrowing costs.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We faced significant challenges relating to our liquidity position in 2002. These challenges were caused by several factors affecting the merchant energy industry, and particularly our company, including the following:

•

The application of more stringent credit standards to Dynegy and other energy merchants;

•

Weak commodity prices, particularly for power;

•

A reduction in liquidity and the amount of open trade credit available to counterparties in the marketing and trading business;

•

The various lawsuits and governmental investigations involving our company, including matters relating to Project Alpha, our past trading practices and our activities in the California power market;

•

Downgrades in our credit ratings to well below investment grade, resulting in substantial requirements to provide counterparties with collateral support in order to transact new business or avoid the termination of existing transactions; and

•

The restatement of our 1999-2001 financial results, the related three-year re-audit and the unavailability of 2001 audited financial statements, all of which limited our ability to access the capital markets.

We also were negatively impacted by our inability to generate the expected return on the significant capital we had previously invested both in our communications business and, because of a weak pricing environment, new merchant generation facilities.

In relation to these events, we posted significantly higher amounts of collateral in the forms of cash and letters of credit than we had in the past. For example, at September 30, 2002, we had posted approximately $1.2 billion of letters of credit and cash collateral in support of our marketing and trading and asset-based businesses. This compares to the approximately $470 million in collateral that we had posted at December 31, 2001.

Since September 30, 2002, we have made marked progress in our exit from third-party risk management aspects of the marketing and trading business. The actions taken in this regard, particularly the transfer of the ChevronTexaco natural gas marketing business back to ChevronTexaco and the completion of our exit from U.K. marketing and trading, resulted in the return of approximately $250 million of collateral and the elimination of these collateral requirements going forward. However, our ongoing asset businesses will continue to manage commodity price risk and optimize commercial positions associated with their respective operations through, among other things, fuel procurement optimization and the marketing of power and NGLs. We expect to continue to post collateral to support these operations, the amount and term of which will be impacted by changes in commodity prices. At April 2, 2003, we had an aggregate of approximately $1,055 million of letters of credit and cash collateral outstanding. While the completion of our exit from third-party risk management aspects of the marketing and trading business will result in a reduction in the collateral requirements associated with that business, we expect an increase in the collateral requirements relating to fuel procurement for our asset-based businesses given our non-investment grade credit ratings and higher commodity prices.

We have also successfully completed a restructuring of our revolving credit facilities that were to expire in April and May of this year. By extending the maturity date of these obligations, which totaled approximately $1.3 billion at April 2, 2003, together with the successful execution of our other liquidity initiatives, we believe that we have provided our company with sufficient capital resources to meet our debt obligations and provide collateral support for our ongoing asset businesses and our continued exit from third-party marketing and trading through 2004. However, our success and future financial condition, including our ability to refinance our substantial debt maturities in 2005 and thereafter, will depend on our ability to successfully execute the remainder of our exit from third-party marketing and trading and to produce adequate operating cash flows from

our continuing asset-based businesses to meet our debt and commercial obligations, including substantial increases in interest expense. Please read “Uncertainty of Forward-Looking Statements and Information” beginning on page 81 for additional factors that could impact our future operating results and financial condition.

Liquidity Sources

As described above, we faced severe strains on our liquidity during 2002. These strains were most severe in the middle of the year, prior to our completion of several initiatives, the proceeds of which have allowed us to stabilize our liquidity position. The most important of these initiatives was the sale of Northern Natural in August 2002 for $879 million in cash proceeds, net of working capital adjustments. Other important initiatives included the sale of our U.K. natural gas storage assets, the disposition of our global liquids business and, more recently, the disposition of our European communications business. The net proceeds from these initiatives and the reduction in related collateral requirements have enabled us to stabilize our liquidity position and to satisfy the collateral requirements of our suppliers, customers and trading counterparties.

These liquidity initiatives originated with our $1.25 billion capital program, which we announced in December 2001. This program included a $500 million reduction to our original 2002 capital spending program and common stock sales in December 2001 and January 2002 netting aggregate proceeds of approximately $744 million. However, with increasing collateral demands and significant near-term maturities, we adopted a number of additional restructuring objectives during the latter half of 2002.

The following table lists the liquidity initiatives that we have successfully executed since June 2002 (amounts reflect gross proceeds prior to reduction for applicable fees).

Date		Initiative
June 2002		• $250 million interim financing secured by proceeds from the sale of our U.K. natural gas storage business • Refinancing of West Coast Power debt, resulting in the release of $100 million in letters of credit previously posted by us on West Coast Power’s behalf • Reduction in workforce (325 employees)

July 2002		• $200 million interim financing secured by interests in the Renaissance and Rolling Hills generating facilities

August 2002		• Sale of Northern Natural for cash proceeds of $879 million, net of working capital adjustments

September 2002		• Sale of Northern Natural senior notes for $96 million • Sale of Hornsea (portion of U.K. natural gas storage business) for $189 million, the proceeds from which were used to partially repay the $250 million related interim financing

October 2002		• Commencement of exit from third-party marketing and trading business • Implementation of organizational restructuring • Reduction in workforce (780 employees)

November 2002		• Sale of Rough (then-remaining portion of U.K. natural gas storage business) for $500 million, with $61 million of the proceeds used to repay the remaining outstanding balance under the $250 million related interim financing • Sale of portions of the Canadian marketing and trading business

December 2002		• Extension of $106 million of the original $200 million Renaissance and Rolling Hills interim financing

Date		Initiative

		• Sale of $550 million in IP mortgage bonds, $150 million of which were issued in January 2003 following ICC approval; and prepayment of $200 million of IP’s $300 million term loan

January 2003		• Disposition of European communications business resulting in significant reductions in operating commitments • Disposition of global liquids business resulting in reduced collateral requirements and other operating commitments • Termination of ChevronTexaco Gas Marketing Agreement

February 2003		• Agreement to sell Hackberry LNG Project for $20 million, with additional contingent payments based upon project development milestones and performance

March 2003		• Agreement to sell U.S. communications business, which is expected to result in reductions in operating commitments • Completion of exit from European marketing and trading business • Sale of equity interest in SouthStar Energy Services LLC for $20 million

April 2003		• Restructuring of $1.66 billion in credit facilities

In addition, we received a tax refund on March 31, 2003 of approximately $110 million for U.S. federal income taxes paid in 2001 and 2000 as a result of the carryback of tax operating losses.

Because of our non-investment grade status and our limited ability to access the capital markets, we have relied, and expect to continue to rely, on cash proceeds from these liquidity initiatives, together with cash from operations and borrowings under our revolving credit facilities, to satisfy our capital requirements. The following table summarizes our consolidated credit capacity and liquidity position at December 31, 2002 and April 2, 2003, respectively.

	December 31, 2002			April 2, 2003(2)
	($ in millions)
Total Credit Capacity	$	1,400		$	1,400
Outstanding Loans		(228	)		(940	)
Outstanding Letters of Credit		(872	)		(405	)

Unused Borrowing Capacity		300			55
Cash		757			1,665
Liquid Inventory (1)		258			2

Total Available Liquidity	$	1,315		$	1,722

(1)

Consists principally of natural gas inventories that have largely been monetized in the first quarter 2003. The values presented are based on spot market prices as of December 31, 2002 and April 2, 2003, respectively.

(2)

Reflects an approximately $500 million increase in cash collateral, and a comparable reduction in letters of credit outstanding, since December 31, 2002. This temporary change resulted from our use of cash to collateralize our obligations, as opposed to letters of credit, late in the first quarter because the near-term nature of the maturity dates on our revolving credit facilities did not permit the issuance of letters of credit. In light of the restructuring of our revolving credit facilities, we expect to return to using letters of credit as opposed to cash to collateralize these obligations in the coming months. Also reflects $153 million of debt payments in the first quarter 2003, including a $94 million payment made in January 2003 on our $200 million Renaissance and Rolling Hills financing.

Liquidity Uses

At December 31, 2002, we had posted approximately $1.2 billion of letters of credit and cash collateral relating to our marketing and trading business and our asset-based business. This compares to approximately $470 million of letters of credit and cash collateral that we had posted at December 31, 2001. Although we experienced a substantial increase in our liquidity usage for collateral requirements during 2002, the success of our restructuring efforts to date has improved our liquidity position and enabled us to generally satisfy the collateral requirements of our customers and counterparties.

The following table includes significant liquidity uses with respect to debt repayments in 2002:

	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
	(in millions)
Payments on IP transitional funding trust notes	$	22	$	22	$	22	$	22
Payments on Project Alpha financing		11		17		17		14
Payments on Black Thunder financing		—		54		19		19
Payments on DHI revolving credit facilities, net		250		—		150		75
Payments on DHI commercial paper		5		—		—		—
Payments on IP commercial paper		38		—		—		—
Repurchase of Northern Natural senior notes		—		90		—		—
Retirement of IP mortgage bonds at maturity		—		—		96		—
Retirement of DHI senior notes at maturity		—		—		200		—
Retirement of Canadian credit facility at maturity		—		—		—		40
Retirement of Illinova medium-term notes at maturity		—		—		—		20
Payments on U.K. storage interim financing		—		—		—		250
Pre-Payment on IP term loan		—		—		—		200
Retirement of Dynegy Inc. credit facility at maturity		—		—		—		83

Total	$	326	$	183	$	504	$	723

Bank Restructuring

On April 2, 2003, Dynegy’s principal financing subsidiary, DHI, entered into a $1.66 billion credit facility consisting of:

•

a $1.1 billion DHI secured revolving credit facility (the “revolving facility”) and a $200 million DHI secured term loan (“Term A facility”), each of which matures on February 15, 2005; and

•

a $360 million DHI secured term loan (“Term B facility”) that matures on December 15, 2005.

The credit facility replaces, and preserves the commitment of each lender under, DHI’s $900 million and $400 million revolving credit facilities, which had maturity dates of April 28, 2003 and May 27, 2003, respectively, and Dynegy’s $360 million Polaris communications lease, which had a maturity date of December 15, 2005. The credit facility will provide funding for general corporate purposes. The revolving facility is also available for the issuance of letters of credit. Borrowings under the credit facility will bear interest, at Dynegy’s option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. A letter of credit fee will be payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. An unused commitment fee of 0.50% will be payable on the unused portion of the revolving facility.

Subject to restrictions contained in the credit facility, amounts repaid under the revolving facility may be reborrowed. The full amounts of the borrowings under the Term A facility and the Term B facility were borrowed at the closing, and borrowings repaid under these facilities may not be reborrowed.

The credit facility contains mandatory prepayment events. The credit facility must, subject to specified exceptions, be repaid and commitments permanently reduced with:

•

100% of the net cash proceeds of all non-ordinary course asset sales;

•

50% of the net cash proceeds from the issuance of equity or subordinated debt;

•

100% of the net cash proceeds from the issuance of senior debt; and

•

50% of extraordinary receipts.

The credit facility provides for no amortization of principal amounts outstanding prior to the maturity dates except upon the occurrence of such a prepayment event.

Subject to specified exceptions, DHI’s obligations under the credit facility are guaranteed by Dynegy and substantially all of Dynegy’s direct and indirect subsidiaries, excluding (i) IP and DGC and their respective subsidiaries, (ii) most foreign subsidiaries, dormant subsidiaries and subsidiaries with de minimus value and (iii) subsidiaries that are unable to become guarantors due to existing contractual or legal restrictions.

Subject to specified exceptions and permitted liens, the lenders under the credit facility received a first priority lien in substantially all the assets of Dynegy, DHI and certain of the subsidiary guarantors to the extent practicable and permitted by existing contractual arrangements, excluding IP and DGC and their respective subsidiaries. The lenders also received a first priority lien in the ownership interests in our direct and indirect subsidiaries, excluding (i) IP and DGC and their respective subsidiaries, (ii) most foreign subsidiaries, dormant subsidiaries and subsidiaries with de minimus value and (iii) subsidiaries whose ownership interests may not be pledged due to existing contractual or legal restrictions. The lenders also received a second priority lien in all material assets of DMG, subject to the first priority lien granted to the lenders under the Black Thunder financing. Our obligations under the Project Alpha transaction and CoGen Lyondell and Riverside generating facility leases were ratably secured with the same assets pledged to the lenders under the credit facility as required by the terms of such facilities.

The credit facility contains affirmative covenants relating to, among other things, financial statements; compliance and other certificates; notices of specified events; payment of obligations; preservation of existence; maintenance of properties; maintenance of insurance; compliance with laws; maintenance of books and records; inspection rights; use of proceeds; guarantee obligations and security; compliance with environmental laws; preparation of environmental reports; further assurances; material contracts; distribution of cash proceeds and extraordinary receipts by subsidiaries; and mortgaged property. The credit facility contains negative covenants relating to, among other things, liens; investments; indebtedness; fundamental changes; dispositions; restricted payments; changes in business; transactions with affiliates and non-loan parties; burdensome agreements; use of proceeds; amendments to organizational documents; accounting changes; prepayments of indebtedness; material contracts; swap contracts and off-balance sheet arrangements; formation of subsidiaries; the CoGen Lyondell and Riverside facilities; and amendments to the Series B preferred stock held by ChevronTexaco. The credit facility also contains financial and capital expenditure-related covenants, which are described in detail below.

The credit facility generally prohibits Dynegy and its subsidiaries, subject to various customary and other exceptions, from incurring additional debt. Notwithstanding this restriction, we may issue “exchange debt,” or debt issued in exchange for outstanding DHI senior unsecured debt. Any such exchange debt may provide for guarantees that result in such debt being structurally senior to DHI’s outstanding senior unsecured debt. Any exchange debt issued would be subject to the following restrictions:

•

for exchange debt offered in respect of DHI senior unsecured debt maturing in 2005 and 2006,

•

if the maturity of the exchange debt is prior to March 15, 2007, then the aggregate principal amount of exchange debt issued generally cannot exceed 66% of the aggregate principal amount of the DHI senior unsecured debt exchanged; and

•

if the maturity of the exchange debt is on or after March 15, 2007, then the aggregate principal amount of exchange debt issued generally cannot exceed the aggregate principal amount of the DHI senior unsecured debt exchanged;

•

for exchange debt offered in respect of DHI senior unsecured debt maturing in 2011, 2012, 2018 and 2026,

•

the aggregate principal amount of exchange debt issued generally cannot exceed the aggregate principal amount of the DHI senior unsecured debt exchanged; and

•

the maturity of the exchange debt must be after December 31, 2009; and

•

the aggregate cash interest expense of any exchange debt cannot exceed the aggregate cash interest expense of the DHI senior unsecured debt exchanged.

The credit facility generally prohibits us from pre-paying, redeeming or repurchasing our outstanding debt or preferred stock. Notwithstanding this restriction, we may repurchase or redeem up to $300 million in DHI senior notes or Series B preferred stock held by ChevronTexaco subject to the following restrictions:

•

the first $100 million in repurchases of DHI senior notes requires a concurrent permanent reduction in commitments under the credit facility of $100 million, the second $100 million in repurchases requires a concurrent permanent reduction in commitments under the credit facility of $200 million, and the third $100 million in repurchases requires a concurrent permanent reduction in commitments under the credit facility of $300 million;

•

no concurrent permanent reduction in commitments under the credit facility is required if DHI senior notes are repurchased with net cash proceeds attributable to extraordinary receipts or the issuance of equity or subordinated debt; and

•

only $50 million of the $300 million may be used to repurchase DHI senior notes that mature on or after April 1, 2011; and

•

only $50 million of the $300 million may be used to redeem shares of the Series B preferred stock held by ChevronTexaco, and Dynegy must permanently reduce commitments under the credit facility concurrently by three times the amount used to redeem such shares.

Notwithstanding the foregoing, we must have $500 million of liquidity for ten days prior to and as of the date of the repurchase or redemption of DHI senior notes or the Series B preferred stock.

The financial covenants in the credit facility are described below. Dynegy and its subsidiaries, excluding IP and DGC and their respective subsidiaries, are prohibited from:

•

permitting their Secured Debt/EBITDA Ratio (as defined in the credit facility) from and after September 30, 2003 to be greater than the ratio set forth below:

Measurement Period Ending		Maximum Secured Debt/ EBITDA Ratio
September 30, 2003		7.8:1.0
December 31, 2003		7.8:1.0
March 31, 2004		7.2:1.0
June 30, 2004		6.8:1.0
September 30, 2004		6.0:1.0
December 31, 2004 and each fiscal quarter thereafter		5.6:1.0

•

the definition of EBITDA in the credit facility specifically excludes, among other items, (i) discontinued business operations (including third-party marketing and trading, communications and tolling arrangements), (ii) disclosed litigation, (iii) extraordinary gains or losses, (iv) any impairment, abandonment, restructuring or similar non-cash expenses, and (v) turbine cancellation payments up to $50 million in the aggregate;

•

permitting their liquidity to be less than $200 million for a period of more than ten consecutive business days; or

•

making capital expenditures during the four fiscal quarter period ending on the applicable dates set forth below in an amount exceeding the amount set forth opposite such fiscal quarter:

Fiscal Quarter		Amount
December 31, 2003		$232 million
March 31, 2004		$202 million
June 30, 2004		$206 million
September 30, 2004		$208 million
December 31, 2004 and each fiscal quarter thereafter		$222 million

•

making capital expenditures in connection with the completion of the Rolling Hills facility in an aggregate amount exceeding $85 million.

With respect to the quarterly restrictions on capital expenditures set forth above, we may (i) carryforward any amount not expended in the four fiscal quarter period in which it was permitted and (ii) carryback up to 50 percent of any amount permitted in a future four fiscal quarter period to any prior four fiscal quarter period and the amount related to the future four fiscal quarter period will be reduced accordingly. Further, Dynegy and its subsidiaries may make additional capital expenditures that are required to comply with applicable law.

The credit facility contains events of default relating to:

•

non-payment of principal when due, non-payment of interest or any commitment fee within three days or non-payment of any other amounts payable under applicable loan documents within five business days;

•

failure to comply with specified covenants and agreements, subject to applicable grace periods;

•

incorrect or materially misleading representations or warranties when made;

•

specified defaults under (i) any debt or guarantee obligation having an aggregate principal amount in excess of $50 million or (ii) certain swap contracts with a termination value owed to the counterparty in excess of $50 million;

•

specified insolvency proceedings that are not discharged or stayed within 60 days or the inability to pay debts as they become due;

•

the entry of a final, non-appealable judgment in excess of $50 million (net of insurance) that is not discharged or stayed within 60 days;

•

specified ERISA-related events involving in excess of $50 million; and

•

any change of control.

Upon the occurrence of any event of default, upon the request of lenders representing more than 50 percent of borrowings outstanding under the credit facility, such lenders may, among other things, declare all borrowings outstanding (including letters of credit) under the credit facility immediately due and payable.

The foregoing description of the material terms of our new credit facility and related ancillary documents is qualified in its entirety by reference to the definitive agreements governing the credit facility, which are filed as exhibits to this Amendment No. 1.

Debt Obligations. The following chart depicts our consolidated third-party debt obligations, including our DNE leveraged lease and Tilton lease obligations, relative to the primary entity under which those obligations reside as of April 2, 2003 (in millions):

LOGO

The following table lists our third-party debt obligations, including our DNE leveraged lease and Tilton lease, as of April 2, 2003, indicating whether such obligations are secured or unsecured (in millions):

DHI Revolving Credit Facility (1)	Secured	$	1,045
DHI Term A Facility	Secured		200
DHI Term B Facility	Secured		360
ABG Gas Supply Credit Facility (Project Alpha)	Secured		250
CoGen Lyondell Credit Facility	Secured		170
DNE Lease Financing (3)	Secured		763
Dynegy Midwest Generation Financing (Black Thunder)	Secured		739
Riverside Credit Facility	Secured		190
Renaissance/Rolling Hills Credit Facility	Secured		106

Total Secured DHI Debt			3,823

DHI Senior Notes	Unsecured		2,000
Trust Preferred Securities	Unsecured		200

Total Unsecured DHI Debt			2,200

Total DHI Debt			6,023

IP Mortgage Bonds and Pollution Control Bonds	Secured		1,635
Transitional Funding Trust Notes	Secured		497
IP Bank Debt	Unsecured		100
Tilton Lease Financing	Secured		81

Total IP Debt			2,313

Illinova Corp. Senior Notes	Unsecured		95

Total Dynegy Third-Party Debt		$	8,431	(2)

(1)

Includes $405 million in letters of credit outstanding.

(2)

This approximately $8.4 billion in debt obligations reconciles to the approximately $6.3 billion in Long-Term Debt, Transitional Funding Trust Notes and Notes Payable and Current Portion of Long-Term Debt included in our Consolidated Balance Sheets as follows (in millions):

(3)

Represents the present value of future lease payments using a 10% discount rate.

Notes payable and current portion of long-term debt (12/31/02)	$	861
Long-term debt and Transitional funding trust notes (12/31/02)		5,454

		6,315
DNE lease financing		763
Tilton lease financing		81
Trust Preferred Securities		200
Issuance of $150 million of IP 11.5% mortgage bonds due 2010		150
Payments of debt maturities since 12/31/02		(153	)
Letters of credit issued under restructured DHI bank credit facility		405
Additional borrowings under restructured DHI bank credit facility		840
Elimination of debt outstanding under former DHI revolving credit facilities		(128	)
Other		(42	)

Total Dynegy Third-Party Debt	$	8,431

Debt Maturities. The restructuring and extension of our bank credit facilities has substantially reduced our 2003-2004 maturities.

The following tables list our quarterly debt maturities through 2005 as of April 2, 2003 (amounts are approximated and presented in millions):

	2003 Maturities
	2nd Quarter		3rd Quarter		4th Quarter		Total
IP Transitional Funding Trust Notes (1)	$	22	$	22	$	22	$	66
Black Thunder Financing (2)		22		22		22		66
Project Alpha Financing (3)		19		19		19		57
IP Mortgage Bonds		—		190		—		190
Renaissance/Rolling Hills Financing Facilities (4)		106		—		—		106
IP Bank Facility		100		—		—		100

	$	269	$	253	$	63	$	585

	2004 Maturities
	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total
IP Transitional Funding Trust Notes (1)	$	22	$	22	$	22	$	22	$	88
Black Thunder Financing (2)		22		18		18		18		76
Project Alpha Financing (3)		20		20		20		20		80
Illinova 7.125% Senior Notes		95		—		—		—		95
IP Tilton Lease		—		—		81		—		81

	$	159	$	60	$	141	$	60	$	420

	2005 Maturities
	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter		Total
Revolving and Term A Portion of Restructured Credit Facilities (5)	$	1,245	$	—	$	—	$	—	$	1,245
IP Transitional Funding Trust Notes (1)		22		22		22		22		88
Black Thunder Financing (2)		18		2		577		—		597
Project Alpha Financing (3)		21		21		21		22		85
DH1 8.125% Senior Notes		300		—		—		—		300
DH1 6.750% Senior Notes		—		—		—		150		150
IP 6.75% Mortgage Bonds		70		—		—		—		70
CoGen Lyondell Facility		—		—		170		—		170
Term B Portion of Restructured Credit Facilities (Formerly U.S. Communications Network Debt)		—		—		—		360		360

	$	1,676	$	45	$	790	$	554	$	3,065

(1)

Reflects required quarterly payments made with cash set aside from IP customer billings.

(2)

Reflects required quarterly payments under Dynegy’s Black Thunder financing as further described in Item 8, Financial Statements and Supplementary Data, Note 10—Debt—DMG Secured Debt beginning on page F-53.

(3)

Reflects required payments associated with Project Alpha as further described in Item 8, Financial Statements and Supplementary Data, Note 10—Debt—ABG Gas Supply Credit Agreement beginning on page F-52.

(4)

We recently agreed to prepay this $106 million on April 16, 2003.

(5)

Includes $405 million of outstanding letters of credit.

Off-Balance Sheet Arrangements

As previously disclosed, in mid-2002 we restructured our Black Thunder minority interest transaction, which resulted in the reclassification of $796 million from Minority Interest to debt on our Consolidated Balance

Sheet. We also voluntarily undertook specific actions, the effect of which altered the accounting for one of our lease obligations. As a result of those actions, together with accounting restatements we recently made affecting the accounting treatment of these and other similar arrangements, we now have two remaining off-balance sheet financings.

DNE Leveraged Lease. As described in Item 1. Business—Power Generation—Northeast Region beginning on page 7, we acquired the DNE power generating facilities in January 2001 from Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc. and Niagara Mohawk Power Corporation. These facilities consist of a combination of base-load, intermediate and peaking facilities aggregating 1,700 MW and are located in Newburgh, New York, approximately 50 miles north of New York City. The aggregate purchase price for the facilities was approximately $950 million and included a transitional obligation to provide power to Central Hudson through October 2004.

In May 2001, we entered into a sale-leaseback transaction relating to these facilities in order to provide us with long-term financing for our acquisition, which established our physical presence as a generator in the Northeastern region of the United States. Pursuant to this transaction, which was structured as a sale-leaseback in order to maximize the value of the facilities and to transfer ownership to the purchaser, we sold for approximately $920 million four of the six generating units comprising these facilities to Danskammer OL LLC and Roseton OL LLC, each of which was newly formed by an unrelated third-party investor, and concurrently agreed to lease them back from these entities, which we refer to as the owner lessors. The owner lessors used $138 million in equity funding from the third-party investor to fund a portion of the purchase of the respective facilities. The remaining $800.4 million of the purchase price and the related transaction expenses was derived from proceeds obtained in a private offering of pass-through trust certificates issued by two of our subsidiaries, Dynegy Danskammer, L.L.C. and Dynegy Roseton, L.L.C., who serve as lessees of the applicable facilities. The pass-through trust certificates were sold to qualified institutional buyers in a private offering and the proceeds were used to purchase debt instruments, referred to as lessor notes, from the owner lessors. The lease payments on the facilities support the principal and interest payments on the pass through trust certificates, which are ultimately secured by a mortgage on the underlying facilities.

As of December 31, 2002, future lease payments are $60 million for each year 2003 through 2006, with $1.3 billion in the aggregate due during the period 2007 through lease expiration. The Roseton lease expires on February 8, 2035 and the Danskammer lease expires on May 8, 2031. We do not have an option to purchase the leased facilities at the end of their respective lease terms. DHI has guaranteed the lessees’ payment and performance obligations under their respective leases on a senior unsecured basis. At December 31, 2002, the present value (discounted at 10%) of future lease payments was $763 million.

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

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

If one or more of the leases were to be terminated because of an event of loss, because it had become illegal for the applicable lessee to comply with the lease or because a change in law had made the facility economically or technologically obsolete, DHI would be required to make a termination payment in an amount sufficient to redeem the pass through trust certificates related to the unit or facility for which the lease was terminated at par plus accrued and unpaid interest. The current termination payment at par would be $999 million, which is in excess of the consideration we received on the sale of the facilities. The likelihood that DHI could make this termination payment would depend on the amount of cash it had on hand at the time such payment would be required as well as its ability to access the capital markets or to otherwise obtain the necessary financing within

the confines of its recently restructured credit agreement. Alternatively, if one or more of the leases were to be terminated because we determine, for reasons other than as a result of a change in law, that it has become economically or technologically obsolete or that it is no longer useful to our business, DHI would be required to redeem the related pass through trust certificates at par plus a make-whole premium in an amount equal to the discounted present value of the principal and interest payments still owing on the certificates being redeemed less the unpaid principal amount of such certificates at the time of redemption. For this purpose, the discounted present value would be calculated using a discount rate equal to the yield to maturity on the most comparable U.S. treasury security plus 50 basis points.

Tilton Lease Arrangement. In September 1999, IP entered into an $81 million operating lease on four gas turbines located in Tilton, Illinois and a separate land lease at the Tilton site. These facilities consist of peaking units totaling 176 MW of capacity. The operating lease runs until September 2004. IP is providing a minimum residual value guarantee on the lease of approximately $70 million. At the expiration of the lease agreement IP has the option to purchase or sell the turbines to terminate the lease. If IP does not purchase the turbines it must deliver the turbines as prescribed under the lease and make a payment to the lessor to the extent the sales price is less than its residual value guaranty. If at the end of the operating lease term IP does not elect to purchase the leased assets, IP is also responsible for dismantling the facility for the benefit of the lessor. At the expiration of the land lease, we may have the obligation to restore the property to its original condition. We estimate the undiscounted costs of any such dismantling to be $8 million and the costs of any such land remediation to be $2 million and have included this amount in the cumulative effect adjustment relating to our adoption of Statement No. 143 effective January 1, 2003. In October 1999, IP sublet the turbines including all payment obligations under the lease to DMG.

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

	($ in millions)
	2002		2001
Lease Expense	$	2.7	$	4.3
Lease Payments (Cash Flows)	$	2.7	$	4.3

Interest Expense

We have recognized interest expense of $297 million, $255 million and $247 million for the years 2002, 2001 and 2000, respectively. Our interest expense in 2003 and thereafter will reflect the increased cost of borrowing in our restructured credit facility. Generally, borrowings under the restructured credit facility will bear interest, at our option, at (i) a base rate plus 3.75% per annum or (ii) LIBOR plus 4.75% per annum. Pricing on letters of credit has increased from 50 basis points under DHI’s former $400 million credit facility and 200 basis points under DHI’s former $900 million credit facility to approximately 475 basis points under the restructured credit facility. Further contributing to our anticipated increase in interest expense in 2003 is our expectation that we will issue letters of credit in support of our marketing and trading obligations, which will be outstanding for the full year, as compared to the similar requirements that we faced beginning in mid-2002. Interest expense in 2003 will also reflect higher costs from IP’s December 2002 issuance of $550 million in mortgage bonds (12% effective interest rate compared to average 2002 IP mortgage bond interest rate of 5.81%). We anticipate that we will recognize net interest expense of approximately $463 million in 2003.

Operating Cash Flows

Our net cash flows from operations for the years 2002, 2001 and 2000 were $(25) million, $550 million and $420 million, respectively. As discussed above, we posted significant amounts of collateral, particularly in the latter half of 2002, to support our marketing and trading and asset-based businesses. The amount of collateral posted increased from $470 million at the end of 2001 to $1.2 billion at the end of 2002. This increase is

reflected in the cash flow statement as a reduction in operating cash flow. Operating cash flow in 2002 was also negatively impacted during 2002 by the factors that negatively affected our results of operations, particularly low power prices and decreased liquidity in trading markets. Please read “—Results of Operations” beginning on page 59 for further discussion.

We expect that our exit from the third-party marketing and trading business will result in benefits to operating cash flow in 2003, particularly with respect to gas inventories held in storage that were sold in the first quarter. Our operating cash flows in 2003 and thereafter also will continue to reflect the expected negative cash flow associated with our eight power tolling arrangements. Please read “—Results of Operations—Customer Risk Management—CRM Outlook” beginning on page 73 for further discussion of these arrangements. The cash flow of our asset-based operations will be significantly affected by the price realized for power and the relationship of prices for power and for natural gas or other generating fuels.

Disclosure of Financial Obligations and Contingent Financial Commitments

We have incurred various financial obligations and commitments in the normal course of our operations and financing activities. Financial obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Financial commitments represent contingent obligations, which become payable only if certain pre-defined events occur, such as financial guarantees.

The following table provides a summary of our general financial obligations as of December 31, 2002. This table includes cash obligations related to outstanding debt, redeemable preferred stock and similar financing transactions. This table also includes cash obligations for minimum lease payments associated with general corporate services, such as office and equipment leases.

General Financial Obligations as of December 31, 2002

	Payments Due By Period
	($ in millions)
Cash Obligations*	Total		2003		2004		2005		2006		2007		Thereafter
Notes Payable and Current Portion of Long Term Debt (1)	$	861	$	861	$	—	$	—	$	—	$	—	$	—
Long Term Debt (1)		5,454		—		343		1,813		314		270		2,714
Series B Preferred Stock (1)		1,500		1,500		—		—		—		—		—
Other Mezzanine Preferred Securities (1)		211		—		—		—		—		—		211
Operating Leases (2)		204		38		33		31		29		27		46
Other Long Term Obligations (3)		13		6		5		1		1		—		—

Total General Financial Obligations	$	8,243	$	2,405	$	381	$	1,845	$	344	$	297	$	2,971

Cash obligations herein are not discounted and do not include related interest, accretion or dividends.

(1)

Total amounts are included in the December 31, 2002 Consolidated Balance Sheet. For additional explanation, please read Item 8, Financial Statements and Supplementary Data, Note 10—Debt beginning on page F-47.

(2)

Includes minimum lease payment obligations associated with office and office equipment leases.

(3)

Includes decommissioning costs related to IP’s sale of its Clinton nuclear facility in 1999 and decommissioning charges associated with IP’s use of a facility that enriched uranium for the Clinton Power Station.

The following table provides a summary of our contingent financial commitments as of December 31, 2002. These commitments represent contingent obligations that may require a payment of cash upon certain pre-defined events.

Contingent Financial Commitments as of December 31, 2002

	Expiration By Period
	($ in millions)
Contingent Obligations*	Total		2003		2004		2005		2006		2007		Thereafter
Letters of Credit (1)	$	897	$	897	$	—	$	—	$	—	$	—	$	—
Surety Bonds (2)		114		33		15		—		—		66		—
Guarantees (3)		245		40		83		13		13		13		83

Total Financial Commitments	$	1,256	$	970	$	98	$	13	$	13	$	79	$	83

Contingent obligations are presented on an undiscounted basis.

(1)

Amounts include outstanding letters of credit and uncommitted credit lines.

(2)

Surety bonds are generally on a rolling twelve-month basis.

(3)

Amounts include a $70 million residual value guarantee related to the Tilton lease arrangement. Based on the current estimated fair value of the underlying assets, the Company does not anticipate funding such amounts. Amounts also include two lease arrangements relating to VLGCs utilized in the NGL Segment that have been subchartered to a wholly owned subsidiary of Transammonia Inc. for the remaining lease term in connection with the sale of the global liquids business.

The table set forth below provides a summary of our commercial financial obligations, which are generally associated with revenue-producing activities. These arrangements provide us access to third-party owned assets for use in our asset-based lines of business. These obligations include certain unconditional purchase obligations associated with generation turbines and minimum lease payments associated with operating leases on assets used in our power generation and natural gas liquids businesses. The obligations also include capacity payments under power tolling arrangements and transportation, transmission and storage arrangements.

As described elsewhere in this annual report, we are in the process of exiting from third-party risk-management aspects of the marketing and trading business. Approximately $3.8 billion of the “Capacity Payments” included below represents the future value of capacity payments pursuant to the power tolling arrangements described in Item 1. Business—Customer Risk Management beginning on page 19. The discounted value of these payments (based on a LIBOR-based discount rate) totaled $2.7 billion. Based on current estimates, the discounted fair value of the capacity payments under these arrangements exceeded the market value of electricity available for sale under these arrangements at December 31, 2002 by approximately $501 million. This amount includes tolling payments that are reflected at fair value on our Consolidated Balance Sheet in “Risk-Management Assets” or “Risk-Management Liabilities” for those contracts that are accounted for using mark-to-market accounting as well as amounts relating to contracts that are accounted for on an accrual basis, each as determined by the applicable contractual terms and in accordance with generally accepted accounting principles. At December 31, 2002, approximately 60 percent of the $3.8 billion of aggregate tolling capacity payments are accounted for on an accrual basis and approximately three-fourths of the $501 million noted above is attributable to contracts accounted for under the accrual method. Upon the adoption of EITF 02-03, as more fully described in Item 8, Financial Statements and Supplementary Data, Note 2—Accounting Policies—Revenue Recognition beginning on page F-21, substantially all of our tolling arrangements will be accounted for on an accrual basis beginning January 1, 2003. We will continue our efforts to renegotiate or terminate some of these arrangements, which we will account for going forward in our CRM segment. Please read “—Results of Operations—Customer Risk Management—CRM Outlook” beginning on page 73 for further discussion of the anticipated effects of these arrangements on our future results of operations.

Commercial Financial Obligations as of December 31, 2002

	Payments Due By Period
	($ in millions)
Cash Obligations*	Total		2003		2004		2005		2006		2007		Thereafter
Operating Leases (1)	$	1,558	$	63	$	63	$	60	$	60	$	108	$	1,204
Unconditional Purchase Obligations (2)		134		66		21		4		4		3		36
Capacity Payments (3)		4,437		327		302		309		323		324		2,852
Conditional Purchase Obligations (4)		483		6		111		116		121		104		25
Other Long Term Obligations		21		3		3		3		3		3		6

Total Commercial Financial Obligations	$	6,633	$	465	$	500	$	492	$	511	$	542	$	4,123

Cash obligations are presented on an undiscounted basis.

(1)

Amounts include the minimum lease payment obligations associated with the lease arrangements relating to our DNE generation facilities and our Tilton generating facility.

(2)

Amounts include natural gas, coal, systems design, various maintenance agreements and power purchase agreements.

(3)

Capacity payments include future values of payments aggregating $3.8 billion under our power tolling arrangements. Other capacity payments totaling approximately $676 million include fixed obligations associated with transmission, transportation and storage arrangements.

(4)

Amounts include our obligations as of December 31, 2002 to purchase 14 gas-fired turbines. Commitments under the turbine purchase orders are payable consistent with the delivery schedule. The purchase orders include milestone requirements by the manufacturer and provide us with the ability to cancel each discrete purchase order commitment in exchange for a fee, which escalates over time. The amounts herein assume all 14 turbines will be purchased. However, we can cancel these arrangements at any time, subject to a termination fee. If we had terminated the turbine purchase orders at December 31, 2002, the termination fee would have been approximately $48 million, reducing our conditional purchase commitment by $435 million. During the first quarter 2003, we renegotiated these turbine commitments. Under the new arrangements, cash obligations total $6 million in 2003, zero in 2004, $147 million in 2005, $193 million in 2006, $113 million in 2007 and $24 million in 2008. The termination payment remains at approximately $48 million through the first quarter 2004 and is subject to variable escalation thereafter.

IP has entered into other generating unit-specific contracts that stipulate fixed payments for the supply of power as well as variable payments for the reimbursement of operating costs. Because the costs associated with these arrangements are currently included in IP’s revenue requirements under its rate-making process, we have not included the associated obligations in the table above.

We have entered into various joint ventures principally for the purpose of sharing risk or to optimize existing commercial relationships. These joint ventures maintain independent capital structures and have financed their operations on a non-recourse basis to us. Please read Item 8, Financial Statements and Supplementary Data, Note 8—Unconsolidated Investments, beginning on page F-42, for further discussion of these joint ventures.

ChevronTexaco Preferred Stock

In November 2001, in connection with entering into a merger agreement with Enron, we issued Series B preferred stock with a liquidation preference and redemption price of $1.5 billion to ChevronTexaco. We used the proceeds from this preferred stock issuance to purchase $1.5 billion of preferred stock in Northern Natural, which we later sold to MidAmerican in August 2002. The shares of Series B preferred stock are convertible prior to their redemption, at the holder’s option, into shares of our Class B common stock at the conversion price of $31.64. The shares of Series B preferred stock also provide for a mandatory redemption on November 13, 2003. Our Board of Directors will evaluate this redemption obligation prior to November 13, 2003. Based on our

substantial debt obligations, liquidity position, limitations under applicable state law and limitations in our restructured credit facility in respect of redemptions of equity securities, we currently do not expect to redeem the preferred shares in November 2003. Our restructured credit facility provides that we cannot redeem more than $50 million of the Series B preferred stock during the term of the facility and that we must permanently reduce borrowings under the credit facility by three times any amount repaid. Shares not redeemed will remain outstanding.

The failure to redeem the Series B preferred stock on the redemption date would not be a default under any of our bank borrowings, secured debt, senior notes or other debt obligations. The holder of the shares of Series B preferred stock are not entitled to a dividend in cash or in kind or Board representation either currently or upon a failure to make a redemption payment. We continue to engage in discussions with ChevronTexaco regarding a possible restructuring of the redemption obligations with respect to this preferred stock.

Capital Spending

The 2003 capital budget of $414 million primarily includes construction projects in progress, maintenance capital projects, environmental projects, contributions to equity investments and limited discretionary capital investment funds. The capital budget is subject to revision as opportunities arise or circumstances change. Funds budgeted for the aforementioned items by the various segments in 2003 are as follows:

2003 Budgeted Capital Expenditures

Segment or Category	($ in millions)
Power Generation	$	206
Natural Gas Liquids		55
Regulated Energy Delivery		136
Other		17

	$	414

Included within the Power Generation segment’s capital budget are $60 million of funds to complete the Rolling Hills power plant, which is under construction and expected to begin commercial operation during the second quarter 2003. This natural gas-fired facility, located in Ohio, will provide 838 MW of generation capacity.

Our capital expenditures in 2003 and beyond will be limited by negative covenants contained in our restructured credit agreements. These covenants place specific dollar limitations on our ability to incur capital expenditures except in our Regulated Energy Delivery segment. Please read “—Bank Restructuring” beginning on page 42 for further discussion.

During 2002, our actual capital expenditures were as follows:

2002 Actual Capital Expenditures

Segment or Category	($ in millions)
Power Generation	$	554
Natural Gas Liquids		94
Regulated Energy Delivery		152
Other		147

	$	947

Capital spending during 2002 for the GEN segment related primarily to our generation assets, the most significant of which were approximately as follows:

•

Rolling Hills—$195 million;

•

Wood River—$52 million;

•

Baldwin—$51 million;

•

Renaissance—$46 million;

•

Bluegrass—$33 million;

•

Foothills—$28 million; and

•

Various other generation asset-related investments aggregating $149 million.

NGL segment capital expenditures of approximately $94 million were primarily related to gas plants and liquids marketing assets, the most significant of which were $29.2 million for the expansion of the Chico gas plant, $7.8 million at the Cedar Bayou fractionator, $6.9 million at the Mont Belvieu terminal and $6.3 million for the Hackberry LNG project, which we have agreed to sell to Sempra.

REG segment capital expenditures of approximately $152 million included $141 million of spending at IP and $11 million related to Northern Natural. For IP, $80 million was spent on electric and gas distribution, $18 million was spent on electric and gas transmission, $24 million was spent on information technology and $19 million was spent on other support and infrastructure.

Other consists of $83 million in capital expenditures associated with the communications business, of which $39 million relates to the U.S. fiber optic network and $44 million primarily relates to network hardware and software spending, including $27 million in the U.S., $14 million in Europe and $3 million in Asia. The remaining $64 million primarily relates to $54 million in spending on information technology and $10 million in our CRM segment.

Credit Rating Discussion

Credit ratings impact our ability to obtain short- and long-term financing, the cost of such financing and the execution of our commercial strategies in a cost-effective manner. In determining our credit ratings, the rating agencies consider a number of factors. Quantitative factors that management believes are given significant weight include, among other things, EBITDA; operating cash flow; total debt outstanding; off balance sheet obligations and other commitments; fixed charges such as interest expense, rent or lease payments; distributions to stockholders; liquidity needs and availability and various ratios calculated from these factors. Qualitative factors appear to include, among other things, predictability of cash flows, business strategy, industry position, quality of management, equity value, litigation, regulatory investigations and other contingencies. Although these factors are among those considered by the rating agencies, each agency may calculate and weigh each factor differently.

Our credit ratings were lowered several times during 2002 by each of the major credit rating agencies. In taking these actions, including those made subsequent to the announcement of our capital plan, the rating agencies generally cited concerns over, among other things, the level of cash flows that we will be able to generate from our continuing businesses relative to our significant financial leverage, our ability to address our substantial near-term debt maturities, uncertainties surrounding our ongoing litigation and government investigations and the restatement of our 1999-2001 financial statements and the likelihood that the renewal of our revolving credit facilities would require a granting of collateral that would subordinate the unsecured bond holders. Most recently, on March 10, 2003, Fitch lowered its ratings on Dynegy and our subsidiaries, indicating that the downgrades anticipated the successful renewal and restructuring on a secured basis of our maturing

credit facilities and U.S. communications network financing. Currently, our credit ratings are at least six notches below investment grade at Standard & Poor’s, Moody’s and Fitch. Additionally, our ratings remain on negative watch for further downgrade by both Standard & Poor’s and Fitch; Moody’s rates us with a negative outlook.

As of April 2, 2003, our senior unsecured debt ratings, as assessed by the three major credit rating agencies, were as follows:

Rated Enterprises	Standard & Poor’s	Moody’s	Fitch
Senior Unsecured Debt Rating:
Dynegy Holdings Inc.(1)	CCC+	Caa2	CCC+
Dynegy Inc.(2)	CCC+	Ca	CCC+
Illinois Power(3)	Not Rated	Caa1	CCC+
Illinova Corporation(4)	CCC+	Caa2	CCC+

(1)

Dynegy Holdings Inc. is the primary debt financing entity for the enterprise. This entity is a subsidiary of Dynegy Inc. and is a holding company that includes substantially all of the operations of the GEN, NGL and CRM segments.

(2)

Dynegy Inc. is the parent holding company. This entity generally provides financing to the enterprise through issuance of capital stock.

(3)

Illinois Power is a stand-alone entity from a financial credit perspective. This entity includes our regulated transmission and distribution business in Illinois.

(4)

Illinova Corporation is the holding company for IP.

While we have substantially improved our liquidity position during the past several months and have made progress toward resolving many of the concerns cited by the rating agencies, we cannot be assured that our credit ratings will be improved. Our current, non-investment grade ratings have adversely affected our ability to access the capital markets and caused us to incur increased costs, including the granting of security, and more restrictive covenants in our recent refinancing activities. Should our ratings continue at their current levels, or should we be further downgraded, we would expect these negative effects to continue and, in the case of a downgrade, perhaps become more pronounced.

Financing Trigger Events

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

Commitments and Contingencies

Please read Item 8, Financial Statements and Supplementary Data, Note 14—Commitments and Contingencies beginning on page F-62, which is incorporated herein by reference, for a discussion of our commitments and contingencies.

Dividends on Preferred and Common Stock

Beginning with the third quarter 2002, our Board of Directors elected to cease payment of a dividend on our common stock. 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. We have, however, continued to make the

required dividend payments on our outstanding trust preferred securities. Please read “—Bank Restructuring” beginning on page 42 for a discussion of the dividend limitations contained in our restructured credit facility.

There is no cash dividend required to be paid on the Series B preferred stock issued to ChevronTexaco in November 2001. Because of ChevronTexaco’s discounted conversion option, we are required to accrete an implied preferred stock dividend over the redemption period, as required by GAAP. Please read Item 8, Financial Statements and Supplementary Data, Note 13—Redeemable Preferred Securities—Series B Convertible Preferred Securities beginning on page F-61 for further discussion of this non-cash implied dividend.

FACTORS AFFECTING FUTURE OPERATING RESULTS

Our results of operations in 2003 and beyond may be significantly affected by the following factors, among others:

•

the level of earnings and cash flows from our continuing asset-based businesses, which are subject to the effect of changes in commodity prices, particularly for power and the relationship between prices for power and for natural gas or other generating fuels, commonly referred to as the “spark spread”;

•

the negative cash flow expected from our tolling agreements and the effect that changes in power prices might have on our non-cash mark-to-market earnings associated with these arrangements;

•

our ability to complete our exit of third-party risk management aspects of the marketing and trading business;

•

our substantial level of leverage, which was reflected in approximately $7.0 billion of total debt and $405 million in letters of credit posted by us at April 2, 2003;

•

our ability to address the $1.5 billion in Series B preferred stock held by ChevronTexaco;

•

higher interest expense resulting from increased demand for collateral in our asset-based businesses and higher borrowing costs under our restructured credit facility;

•

the effects of ongoing investigations and litigation relating to, among other things, our past trading practices, our activities in the California power market, shareholder claims and claims arising out of our legacy CRM business;

•

our ability to operate our business within the confines of the increased borrowing rates and more restrictive covenants contained in our restructured bank credit facilities;

•

our ability to access the capital markets given our non-investment grade credit ratings; and

•

our ability to operate our business with a decentralized organizational structure and a reduced workforce.

Additionally, new accounting pronouncements will also impact our reported results of operations going forward. For example, during 2002, the EITF discussed Issue No. 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” and reached consensus on certain issues. EITF Issue 02-03 rescinds EITF 98-10, which required that energy trading contracts be accounted for at fair value, effective for any new contracts entered into after October 25, 2002. For energy trading contracts entered into through October 25, 2002, we continue to account for such contracts at fair value through December 31, 2002. Effective January 1, 2003, contracts that do not meet the accounting definition of derivatives are required to be accounted for under the accrual method and we will report all previously recorded unrealized income on these contracts as a cumulative effect of an accounting change. Our energy trading contracts that qualify as derivatives will continue to be accounted for at fair value under Statement No. 133. Please read Item 8, Financial Statements and Supplementary Data, Note 5—Commercial Operations, Risk Management Activities and Financial Instruments—Accounting for Derivative Instruments and Hedging Activities, beginning on page F-38 for further discussion.

In addition, we adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” effective as of January 1, 2003. Under Statement No. 143, asset retirement obligations are to be recorded at fair value in the period in which they are incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. As part of the transition adjustment in adopting Statement No. 143, existing environmental liabilities in the amount of $73 million were reversed. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the asset retirement obligation and was recorded upon adoption of Statement No. 143. As such, we expect the impact of our adoption of Statement No. 143 will be an increase to earnings, net of tax, of approximately $33 million in the first quarter 2003 to be reflected as a cumulative effect of a change in accounting principle. The annual amortization of the assets created under this standard and the accretion of the liability to its fair value is estimated to be approximately $6 million in 2003. In addition to these liabilities, we also have potential retirement obligations for the dismantlement of power generation facilities, power transmission assets, a fractionation facility and natural gas storage facilities. It is our intent to maintain these facilities in a manner such that the facilities will be operational indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. At the time we are able to estimate any new asset retirement obligations, liabilities will be recorded in accordance with Statement No. 143.

Please read “Uncertainty of Forward Looking Statements and Information” beginning on page 81 for additional factors that could impact our future operating results.

RESULTS OF OPERATIONS

In this section, we discuss our results of operations, both on a consolidated basis and by segment, for the years 2002, 2001 and 2000. We historically presented the results for the following four reportable business segments:

•

Wholesale Energy Network;

•

Dynegy Midstream Services;

•

Transmission and Distribution; and

•

Dynegy Global Communications.

As described above under Item 1. Business—Segment Discussion beginning on page 4, effective January 1, 2003, we began reporting our operations in the following segments:

•

Power generation;

•

Natural gas liquids;

•

Regulated energy delivery; and

•

Customer risk management.

Other reported results include our discontinued communications operations.

Reportable segments in this Amendment No. 1 have been reclassified to reflect the changes we made to our business reporting segments beginning January 1, 2003. As described in Note 18 to the accompanying consolidated financial statements beginning on page F-85, prior to January 1, 2003, the CRM and GEN segments were reported together in the WEN segment. In connection with our exit from the CRM business, we separated the contracts within the former WEN segment as of January 1, 2003 as being GEN contracts or CRM contracts, based on their terms and their importance to our GEN segment. The GEN and CRM businesses were operated together within the WEN segment as an asset-based third-party marketing, trading and risk-management business during all periods presented. Under this business model, the fair value of the GEN segment’s generation capacity, forward sales and related trading positions were sold to the CRM segment each month at an internally determined transfer price. The CRM segment, together with all its other third-party marketing and trading positions unrelated to the GEN segment, would record revenue from the third-party contracts associated with the GEN segment during the month of settlement. The intersegment revenues for the GEN segment reflect this internal transfer price and do not represent amounts actually received for power sold to third parties. As such, the intersegment revenues do not include the effects of intra-month market price volatility.

Regarding our results of operations for 2002, 2001 and 2000, the impact of acquisition and disposition activity during the three-year period reduces the comparability of some of our historical financial and volumetric data.

Recent accounting pronouncements have also affected our financial results, particularly those of our third-party marketing and trading business, so as to further reduce the comparability of some of our historical financial data. For example, pursuant to EITF Issue 02-03, all mark-to-market gains and losses on energy trading contracts whether realized or unrealized, are shown net in the income statement, irrespective of whether the contract is physically or financially settled. In addition, pursuant to the transition provisions in EITF Issue 02-03, we have conformed the comparative period financial information contained in this annual report to reflect this change in accounting principle. We have historically classified net unrealized gains and losses from energy trading contracts as revenue in our consolidated statement of operations. However, physical transactions that were realized and settled were previously reflected gross in revenues and costs of sales. This change in accounting classification has no impact on our operating income, net income, earnings per share or operating cash flows.

For segment reporting purposes, all general and administrative expenses incurred by us on behalf of our subsidiaries have been charged to the applicable subsidiary as incurred. We have allocated indirect general and

administrative expenses to our subsidiaries using a two-step formula that considers both payroll expense and total assets. Interest expense incurred by us on behalf of our subsidiaries has been allocated based on the subsidiaries’ capital structure. Other income (expense) items incurred by us on behalf of our subsidiaries are allocated equally among sub-components of our business segments.

The information presented below has been revised primarily to reflect the reclassifications relating to discontinued operations and segment reporting and other revisions described in the Introductory Note to this Amendment No. 1. Please also read the Explanatory Note to the accompanying financial statements beginning on page F-8 for a discussion of the previously reported restatement of our 1998-2001 financial statements. As discussed in the Explanatory Note, these previously reported restatements relate to the following items:

•

the Project Alpha structured natural gas transaction,

•

a balance sheet reconciliation project relating principally to our natural gas marketing business,

•

corrections to our previous hedge accounting for certain contracts resulting in our accounting for these contracts pursuant to the mark-to-market method under Statement No. 133; in addition, we determined that we had incorrectly accounted for certain derivative transactions prior to the adoption of Statement No. 133,

•

the valuation used in our 2000 acquisition of Extant, Inc.,

•

the restatement of our forward power curve methodology to reflect forward power and market prices more closely,

•

the recognition of additional assets, accrued liabilities and debt associated with certain lease arrangements, as well as impairment, depreciation and amortization expense for the related assets,

•

a correction to the measurement date relating to the implied dividend we previously recorded related to the in-the-money beneficial conversion option in the $1.5 billion Series B preferred stock issued to ChevronTexaco in November 2001,

•

the recognition of an other-than-temporary decline in value of a technology investment in the third quarter of 2001 rather than the second quarter of 2002,

•

corrections to our previous accounting for income taxes, and

•

other adjustments that arose during the re-audit of our 1999-2001 financial statements.

While certain of these items arose as the result of our consideration of differing interpretations of the applicable GAAP requirements between our former and current independent auditors, others, such as the restatements relating to Project Alpha, the natural gas marketing charge, hedge accounting under Statement No. 133, the valuation of the Extant acquisition, the Series B preferred stock and our previous accounting for income taxes, resulted from accounting errors. Please read Item 14. Controls and Procedures beginning on page 84 for a discussion of the measures we are taking relative to our internal control environment.

Three Years Ended December 31, 2002

The following table provides summary financial data regarding our consolidated results of operations for 2002, 2001 and 2000, respectively.

Results of Operations

	2002			2001			2000
				(Restated)			(Restated)
	($ in millions)
Operating Income (Loss)	$	(1,141	)	$	967		$	766
Equity Earnings (Loss)		(80	)		191			196
Interest Expense		(297	)		(255	)		(247	)
Other Items, Net		(107	)		(60	)		(72	)
Income Tax (Provision) Benefit		276			(357	)		(234	)

Income (Loss) from Continuing Operations		(1,349	)		486			409

Discontinued Operations
Income (Loss) from Discontinued Operations		(1,503	)		(127	)		38
Income Tax (Provision) Benefit		349			45			(11	)

Income (Loss) on Discontinued Operations		(1,154	)		(82	)		27
Cumulative Effect of Change in Accounting Principle		(234	)		2			—

Net Income (Loss)	$	(2,737	)	$	406		$	436

Net Income (Loss). We incurred a net loss of $2,737 million, or $8.38 per diluted share, in 2002. This compares with net income of $406 million, or $1.07 per diluted share, and $436 million, or $1.27 per diluted share, in 2001 and 2000, respectively. The following significant items contributed to our net loss for 2002:

•

a charge of $897 million for the impairment of goodwill associated with our GEN and CRM segments;

•

an after-tax loss of $1,154 million on our discontinued operations, primarily due to an after-tax loss of approximately $561 million on the sale of Northern Natural and an after-tax charge of approximately $413 million associated with the impairment of some of our communications assets;

•

a loss of approximately $234 million associated with the write-down of goodwill in our communications business. This write-down was recognized as a cumulative effect of change in accounting principle upon our adoption of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets”;

•

after-tax charges totaling approximately $142 million relating to our corporate restructuring and related workforce reductions, of which $28 million is included in discontinued operations;

•

an after-tax charge of approximately $94 million related to the impairment of some of our generation investments;

•

an after-tax charge of approximately $52 million related to the impairment of some of our technology investments, of which $32 million is included in discontinued operations; and

•

other charges primarily associated with asset write-offs, losses on asset sales, contract and litigation settlements and the recognition of additional reserves.

In addition to these significant items, a weak pricing environment, especially for power, and reduced market liquidity contributed to lower operating results from our GEN, CRM and NGL segments in 2002. Please read our segment discussions below for further discussion of the changes in operating income during the periods presented.

Our 2001 net income decreased to $406 million from $436 million in 2000. The following significant items impacted our 2001 results on an after-tax basis as follows:

•

approximately $84 million related to energy sales to Enron and its affiliates, which filed for bankruptcy during the fourth quarter 2001;

•

approximately $9 million associated with severance costs incurred as a result of an organizational restructuring at IP; and

•

approximately $7 million associated with costs incurred in connection with the terminated Enron merger.

These charges, together with increased interest expense, more than offset the $17 million pre-tax increase in operating income period over period.

Our 2000 net income of $436 million included aggregate gains of approximately $92 million associated with the sale of Accord and some QFs. These gains were partially offset by losses on sales of our crude oil business and our Mid-Continent gas processing assets, the impairment of a Canadian liquids asset and costs incurred in connection with our acquisition of Illinova.

The following table sets forth significant items affecting net income and diluted earnings per share for the periods presented.

	2002						2001						2000
($ in millions, except per share data)	Income (Charge)			Diluted EPS			Income (Charge)			Diluted EPS			Income (Charge)			Diluted EPS
Impairment of Goodwill	$	(897	)	$	(2.45	)	$	—		$	—		$	—		$	—
Discontinued Operations (1)		(1,154	)		(3.15	)		(82	)		(0.25	)		27			0.09
Cumulative Effect of Change in Accounting Principle		(234	)		(0.64	)		2			0.01			—			—
Restructuring Costs		(101	)		(0.27	)		—			—			—			—
Impairment of Unconsolidated Generation Investments		(94	)		(0.26	)		—			—			—			—
Impairment of Technology Investments		(20	)		(0.05	)		—			—			—			—
Generation Equity Earnings		(33	)		(0.09	)		—			—			—			—
Tolling Settlement Accrual		(16	)		(0.04	)		—			—			—			—
Enron Litigation Settlement		(14	)		(0.03	)		—			—			—			—
ChevronTexaco Contract Settlement		(15	)		(0.04	)		—			—			—			—
IP Regulatory Asset Amortization Expense		(15	)		(0.04	)		—			—			—			—
Other (2)		(44	)		(0.12	)		—			—			—			—
Enron bankruptcy exposure		—			—			(84	)		(0.25	)		—			—
Illinois Power severance costs		—			—			(9	)		(0.03	)		—			—
Terminated Enron merger related costs		—			—			(7	)		(0.02	)		—			—
Gain on Sale – Accord Energy Limited		—			—			—			—			58			0.18
Gain on Sale – QFs		—			—			—			—			34			0.11
Loss on Sale – Crude Business		—			—			—			—			(11	)		(0.03	)
Loss on Sale – Mid-continent Assets		—			—			—			—			(6	)		(0.02	)
Impairment of a Liquids Asset		—			—			—			—			(16	)		(0.05	)
Illinova Acquisition Costs		—			—			—			—			(10	)		(0.03	)
Special Dividend (3)		—			(0.90	)		—			(0.12	)		—			(0.10	)

(1)

Included within this amount is $413 million ($1.13 per diluted share) of charges related to the impairment of communication assets, $28 million ($0.08 per diluted share) of restructuring costs, $32 million ($0.09 per diluted share) of charges related to the impairment of technology assets, $2 million ($0.01 per diluted share) of charges related to the Enron litigation settlement and $11 million ($0.03 per diluted share) of other charges.

(2)

Includes various charges incurred in 2002, including the write-off of Dynegydirect, our former electronic trading platform, which resulted in an after-tax charge of approximately $16 million ($25 million pre-tax).

(3)

The special dividend in 2002 and 2001 relates to the accretion of the implied value of the beneficial conversion option in the Series B preferred stock held by ChevronTexaco. The special dividend in 2000 relates to a $32 million payment made to two of our former shareholders in the second quarter 2000 prior to the conversion of their preferred shares to Class A common stock.

Equity Earnings. Our share in the earnings (losses) of our unconsolidated investments contributed losses of approximately $80 million in 2002 and earnings of approximately $191 million and $196 million in 2001 and 2000, respectively. West Coast Power contributed approximately $17 million, $162 million and $122 million to equity earnings in 2002, 2001 and 2000, respectively. The decrease in earnings from West Coast Power in 2002 is due in part to a reduction in contingent capacity and energy sales under the CDWR contract. Please read Item 1, Business—Segment Discussion—Power Generation—West Region—Western Electricity Coordinating Council (WECC) beginning on page 9 for further discussion of this contract. Equity earnings from West Coast Power also include a pre-tax charge of $50 million ($33 million after-tax) related to our share of a reserve taken by West Coast Power to increase its allowance for doubtful accounts. The overall decrease in equity earnings in 2002 was primarily due to significant impairments of generation and technology investments recognized during 2002.

Cash distributions received from all unconsolidated investments in 2002, 2001 and 2000 approximated $91 million, $100 million and $118 million, respectively.

Interest Expense. Interest expense totaled $297 million for 2002, compared with $255 million and $247 million for 2001 and 2000, respectively. The increase in interest expense in 2002 was due primarily to increased principal borrowed to support our liquidity needs in 2002. Specifically, these additional principal amounts primarily relate to cash borrowings and letters of credit under our revolving credit facilities used to satisfy counterparty collateral demands. The effect of the increased interest expense relating to these additional principal amounts was partially offset by lower variable rates than in 2001. The increase in interest expense in 2001 from 2000 was due primarily to increased principal, partially offset by lower variable rates than in 2000.

Other Items. Net other income and expenses, net reduced 2002, 2001 and 2000 operating results by $107 million, $60 million and $72 million, respectively. The 2002 results were negatively impacted by the following:

•

a charge of $14 million ($21 million pre-tax) associated with the settlement of the Enron litigation. The other $2 million ($4 million pre-tax) of the settlement is included in discontinued operations;

•

a charge of $15 million ($22 million pre-tax) relating to the cancellation of our natural gas purchases and sales contract with ChevronTexaco;

•

a charge of $4 million ($6 million pre-tax) associated with fees related to a voluntary action that we took that altered the accounting for some of our lease obligations;

•

a charge of $4 million related to our settlement with the CFTC. The other $1 million of the $5 million settlement is included in discontinued operations; and

•

a charge of $3 million related to our settlement with the SEC.

The remaining net amounts for all three years include the financial effects of minority shareholder investments in some of our operations, including interest and dividend income, foreign currency gains and losses, insurance proceeds and other similar items.

Income Tax (Provision) Benefit. We reported an income tax benefit of $276 million in 2002, compared to income tax provisions of $357 million and $234 million in 2001 and 2000, respectively. These amounts reflect effective rates of 17 percent, 42 percent and 36 percent, respectively. In general, differences between these effective rates and the statutory rate of 35 percent result primarily from permanent differences attributable to book-tax basis differences and certain liabilities; and the effect of certain foreign and state income taxes. In addition, the 2002 effective rate was impacted significantly by the $897 million goodwill impairment relating to the CRM and GEN segments. As there was no tax basis in the asset, there was no tax benefit associated with the

charge. See Item 8, Financial Statements and Supplementary Data, Note 12—Income Taxes beginning on page F-58, which is incorporated herein by reference, for further discussion of our income taxes.

Discontinued Operations. Discontinued operations primarily include Northern Natural, our global liquids business, our U.K. natural gas storage assets, our U.K. CRM business and our global communications business. On August 16, 2002, we sold Northern Natural to MidAmerican for $879 million in cash, after adjustment for working capital changes. MidAmerican acquired all of the common and preferred stock of Northern Natural and assumed all of its $950 million of debt. We incurred a loss of approximately $561 million ($599 million pre-tax) associated with the sale, including the final adjustment for working capital changes. As noted above, during 2002, the global communications business recorded charges of $413 million for the impairment of communications assets. During 2002, we also recognized an after-tax charge of approximately $12 million associated with the impairment of an LPG investment in the global liquids business.

Cumulative Effect of Change in Accounting Principle. Effective January 1, 2002, we adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.” In connection with the adoption, we realized a cumulative effect loss of approximately $234 million associated with a write-down of goodwill in our global communications business.

Segment Results of Operations

Non-GAAP Financial Measures. Management uses Earnings Before Interest and Taxes, or “EBIT,” as one measure of financial performance of our business segments. EBIT is a non-GAAP financial measure and consists of operating income, earnings from unconsolidated investments, other income and expenses, net, minority interest income (expense), accumulated distributions associated with trust preferred securities, discontinued operations and the cumulative effect of a change in accounting principle. EBIT does not include interest expense and income taxes, each of which is evaluated on a consolidated level. Because we do not allocate interest expense and income taxes by segment, we believe that EBIT is a useful measurement of our segment performance for investors. EBIT should not be considered an alternative to, or more meaningful than, net income or cash flows from operations as determined in accordance with GAAP. Our segment EBIT may not be comparable to similarly titled measures used by other companies.

Power Generation

	Year Ended December 31,
	2002			2001			2000
				(Restated)			(Restated)
	(in millions, except operating statistics)
Total Operating Income (Loss)	$	(401	)	$	390		$	337
Earnings (Losses) of Unconsolidated Investments		(71	)		202			169
Other Items, net		(20	)		(5	)		(21	)

Earnings (Losses) Before Interest and Taxes	$	(492	)	$	587		$	485

Operating Cash Flow:
Operating Cash Flows Before Changes in Working Capital	$	349		$	431		$	257
Changes in Working Capital		(91	)		71			(180	)

Net Cash Provided By (Used In) Operating Activities	$	258		$	502		$	77


Operating Statistics:
Million Megawatt Hours Generated—Gross		43.5			40.3			36.8
Million Megawatt Hours Generated—Net		39.4			34.5			30.3
Average Natural Gas Price—Henry Hub ($/MMbtu)	$	3.22			4.26		$	3.89
Average On-Peak Market Power Prices ($/MW hour)
Cinergy	$	27.21		$	35.19		$	36.43
TVA		27.56			34.87			39.73
PJM		36.00			40.76			39.96
New York—Zone G		46.78			51.75			55.60
Platts SP15		34.64			121.04			113.51

GEN reported EBIT of $(492) million for 2002 compared to $587 million for 2001 and $485 million for 2000. EBIT consists of the following amounts reported by GEN for the periods presented: operating income (loss) of $(401) million, $390 million and $337 million, respectively; earnings (losses) of unconsolidated investments of $(71) million, $202 million and $169 million, respectively; and other items, net of $(20) million, $(5) million and $(21) million, respectively.

Results of operations during the three-year period were influenced either positively or negatively by the following:

•

decreased equity earnings from West Coast Power from 2001 to 2002 as a result of lower volumes sold, an impairment of our investment and an increase in the allowance for West Coast Power’s doubtful accounts;

•

charges relating to our impairment of goodwill and generation equity investments in 2002;

•

a weak pricing environment, particularly for power, causing reduced earnings from our generation facilities in 2002;

•

increased earnings resulting from additional power generating capacity acquired or placed in service in 2002, 2001 and 2000;

•

increased equity earnings from West Coast Power from 2000 to 2001, partially attributable to higher price realization for power purchased from West Coast Power; and

•

aggregate after-tax gains of approximately $34 million on the sales of some of our QFs, offset by an allocated portion of Illinova acquisition costs, in 2000.

The new generating capacity in 2002 included the Renaissance, Bluegrass and Foothills facilities aggregating 1,512 MW. The new generating capacity in 2001 included the DNE power generating facilities in New York and development projects in Georgia, Kentucky and Louisiana aggregating 2,865 MW. The new capacity in 2000 included the generation assets from the Illinova acquisition and development projects in Illinois, Louisiana and North Carolina aggregating 8,091 MW.

Operating cash flows increased from 2000 to 2001 as a result of higher operating income from our asset businesses, reflecting added generation capacity and favorable power prices.

Total megawatt hours generated during 2002 aggregated 43.5 million compared to 40.3 million and 36.8 million during 2001 and 2000, respectively. Volumes for each period reflect the impact of additional generating capacity.

GEN Outlook

We expect that future financial results of our power generation business will continue to reflect a sensitivity to weather, power and natural gas prices, including the spark spread, and terms of contracts for contracted generation. We believe that our generation fleet’s fuel diversity will help mitigate the extent to which this segment’s future results are affected by changes in natural gas prices. We also expect that this business will continue its efforts to manage its price risk through the optimization of fuel procurement and the marketing of power generated from its assets. As part of our strategy of commercially optimizing our assets, including agency and energy management agreements to which we are a party, we enter into financial and other transactions, including forward hedges relating to our generating capacity. This segment’s sensitivity to prices and our ability to manage this sensitivity is subject to a number of factors, including general market liquidity, our ability to provide necessary collateral support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings. Other factors that could affect the prices at which transactions can be consummated and this segment’s results of operations include transmission constraints, or the lack thereof, and governmental actions or excess generation capacity in the markets we serve.

Any events that negatively impact our significant long-term power sales agreements could likewise affect this segment’s future results of operations. For example, equity earnings from West Coast Power are primarily derived from West Coast Power’s long-term power sales contract with the CDWR. That contract, which runs through December 31, 2004, is the subject of various legal challenges as further described in Note 14— Commitments and Contingencies—FERC and Related Regulatory Investigations—Western Long-Term Contract Complaints beginning on page F-68. The success of any such challenges would negatively impact this segment’s equity earnings from West Coast Power and, accordingly, its results of operations for the periods affected.

Natural Gas Liquids

	Year ended December 31,
	2002			2001			2000
				(Restated)			(Restated)
	($ in millions, except operating statistics)
Operating Income:
Upstream	$	18		$	82		$	45
Downstream		59			51			35

Total Operating Income		77			133			80
Earnings of Unconsolidated Investments		14			13			24
Other Items, Net		(34	)		(3	)		(40	)
Income (Loss) on Discontinued Operations		(37	)		(2	)		5

Earnings Before Interest and Taxes	$	20		$	141		$	69

Operating Cash Flows:
Operating Cash Flows Before Changes in Working Capital	$	73		$	147		$	128
Changes in Working Capital		(49	)		12			(54	)

Net Cash Provided By Operating Activities	$	24		$	159		$	74

Operating Statistics:
Natural Gas Processing Volumes (MBbls/d):
Field Plants		56.0			56.1			61.2
Straddle Plants		35.9			27.7			35.6

Total Natural Gas Processing Volumes		91.9			83.8			96.8

Fractionation Volumes (MBbls/d)		215.2			226.2			224.3
Natural Gas Liquids Sold (MBbls/d)		498.8			557.4			564.6
Average Commodity Prices:
Crude Oil – WTI ($/Bbl)	$	25.75		$	26.39		$	28.97
Natural Gas Liquids ($/Gal)		0.40			0.45			0.55
Fractionation Spread ($/MMBtu)		1.26			0.89			2.40

NGL reported EBIT of $20 million for 2002, compared with EBIT of $141 million and $69 million in 2001 and 2000, respectively. EBIT consists of the following amounts reported by NGL for the periods presented: operating income of $77 million, $133 million and $80 million, respectively; earnings of unconsolidated investments of $14 million, $13 million and $24 million, respectively; other items, net of $(34) million, $(3) million and $(40) million, respectively; and income (loss) on discontinued operations of $(37) million, $(2) million and $5 million, respectively. The following influenced this segment’s results of operations from 2002 compared to 2001:

•

a decline in processing plant margins caused by lower natural gas and realized natural gas liquids prices in 2002;

•

decreased profitability of our straddle plants in 2002 due to the negative effect of lower natural gas liquids prices and increased settlement costs related to volumes processed in 2002 that were processed on a slightly more profitable fee basis in 2001;

•

reduced domestic and foreign marketing volumes and margins in 2002 as a result of slow economic recovery, high industry-wide inventory levels, reduced market liquidity and Dynegy-specific credit limitations;

•

$12 million of after-tax charges allocated to this segment during 2002 associated with our restructuring;

•

$7 million of after-tax charges allocated to this segment during 2002 relating to technology investment impairments, the Enron settlement and other items; and

•

the results of our discontinued operations in 2002, including a $12 million impairment of an LPG investment in India.

Results of operations from 2000 to 2001 were influenced either positively or negatively by:

•

Higher price realization in 2001, as compared to 2000, resulting from an active forward sales program and contract restructuring activities, despite a depressed pricing environment resulting from larger industry wide inventories;

•

Substantial focus on lowering costs throughout the two-year period;

•

Fluctuating world-wide demand for NGLs, particularly in Europe and Asia, enhanced 2000 revenues from global marketing operations;

•

Results for 2001 include approximately $2 million exposure to Enron (net of tax) as a result of that company’s bankruptcy filing and an allocation of transaction costs associated with the terminated proposed merger with Enron; and

•

Results for 2000 include losses of approximately $17 million (net of tax) on sales of the Crude Oil Marketing and Trade business (which was sold in April 2000 and contributed approximately $9 million after tax in 1999) and Mid-Continent gas processing assets, an impairment of approximately $16 million (net of tax) relating to Canadian gas processing assets and an allocation of costs related to the Illinova acquisition.

NGL reported operating cash inflows of $24 million for 2002, compared with cash flows of $159 million and $74 million in 2001 and 2000, respectively. The following influenced operating cash flows period-to-period:

•

reduced 2002 EBIT as discussed above;

•

in 2002 prepayments were required to continue business with several customers and suppliers, which was a use of working capital of $57 million, as the result of Dynegy-specific credit limitations;

•

also in 2002, other movements in working capital items related to lower prices, which partially offset the increase in prepayments;

•

2001 cash flow exceeded 2000 cash flow due to increased earnings stemming from higher price realization in 2001 as discussed above; and

•

working capital provided $12 million in cash flow in 2001 primarily due to reducing the volume of natural gas liquids in inventory and a steep decline in inventory prices compared to the end of the year 2000.

Aggregate domestic NGLs fractionation volumes totaled 92 thousand gross barrels per day in 2002 compared to an average 84 thousand gross barrels per day and 97 thousand gross barrels per day in 2001 and 2000, respectively. Higher volumes processed in 2002 reflect volume growth from the Louisiana straddle plants and are the direct result of an increasing need to process Gulf of Mexico natural gas production to meet third-party downstream pipeline gas merchantability standards. In some cases, this has resulted in new contract terms that allow us to provide, on a temporary basis, processing services on a fee basis, thereby reducing our exposure to keep-whole processing margin risk. This is a trend that should continue as the volume of gas produced in the deep-water Gulf of Mexico increases. An increase in the volumes dedicated for processing by ChevronTexaco also contributed to the growth in Louisiana processing volumes during 2002. The reduction in volumes processed in 2001 compared to 2000 is due to the volume impacts from the sale of the Mid-Continent gas processing assets in 2000.

The average fractionation spread was $1.26 for 2002 compared to $0.89 and $2.40 in 2001 and 2000, respectively. Despite a slight increase in this spread in 2002, traditional keep-whole processing is still uneconomic at this level. Historically, the Louisiana straddle plants have not operated in this pricing environment.

NGL Outlook

We expect that the general industry-wide contraction in trade credit in the wholesale energy markets, including limitations relating to our own credit issues, will continue in 2003. This contraction is evidenced by the fact that open or unsecured credit lines are generally no longer available, and our customers are more stringent in requiring credit support in the form of cash in advance, letters of credit or guarantees as a condition to transacting business above open credit limits. Beginning in the second quarter 2002, and as a result of the general contraction of trade credit as well as downgrades in our credit ratings, NGL has been required to provide letters of credit and cash prepayments to collateralize our net exposure to various counterparties in its distribution and marketing business. During 2002, our marketing volumes were negatively affected by the general uncertainty in the energy and capital markets. We expect this market uncertainty to continue during the foreseeable future. Counterparty credit concerns and the resulting industry-wide contraction in trade credit have increased the cost of transacting business in the wholesale energy markets. As a result of this increase, we have generally refrained from entering into lower volume, lower margin transactions. We anticipate that this contraction in credit will continue to affect our marketing volumes, the number of transactions we enter into and the number of counterparties with whom we transact business.

Due to the turmoil in the Middle East and Venezuela, crude prices, liquids prices and natural gas prices are well above 2002 prices. If these price levels continue, we would expect this segment to generate higher profits than in 2002, all other factors being equal. Even at higher liquids prices, we are experiencing a weak fractionation spread environment. The correlation of prices for propane relative to prices for oil has returned to historical levels, improving expected revenues for this segment in the current pricing environment over 2002 when the correlation was lower than historical levels. Drilling activity by independent producers has been increasing in the past several months in the producing regions NGL serves due to higher commodity prices. Major producers are responding with more drilling activity in these regions, albeit more slowly, as their drilling programs are normally determined several years in advance.

Regulated Energy Delivery

	Year Ended December 31,
	2002			2001			2000
				(Restated)			(Restated)
	($ in millions, except operating statistics)
Total Operating Income	$	157		$	180		$	206
Losses of Unconsolidated Investments		(2	)		—			—
Other Items, Net		(4	)		2			(10	)
Loss on Discontinued Operations		(561	)		—			—

Earnings (Losses) Before Interest and Taxes	$	(410	)	$	182		$	196

Operating Cash Flows:
Operating Cash Flows Before Changes in Working Capital	$	371		$	269		$	252
Changes in Working Capital		(109	)		(160	)		50

Net Cash Provided By Operating Activities	$	262		$	109		$	302

Operating Statistics:
Electric Sales in kWh (Millions):
Residential		5,548			5,202			5,046
Commercial		4,415			4,337			4,256
Industrial		6,306			6,353			8,324
Transportation of Customer-Owned Electricity		2,505			2,645			963
Other		370			373			412

Total Electricity Delivered		19,144			18,910			19,001

Gas Sales in Therms (Millions):
Residential		323			315			337
Commercial		137			136			141
Industrial		80			88			96
Transportation of Customer-Owned Gas		233			246			259

Total Gas Delivered		773			785			833

Heating Degree Days		5,118			4,749			5,233
Cooling Degree Days		1,467			1,302			1,173

The REG segment includes the operations of IP, a regulated electric and gas energy delivery company serving customers across a 15,000-square-mile area of Illinois. As a result of our sale of Northern Natural in the third quarter 2002, Northern Natural is included in discontinued operations, as further discussed in Item 8, Financial Statements and Supplementary Data, Note 3—Dispositions, Discontinued Operations and Acquisitions—Dispositions—Discontinued Operations—Northern Natural beginning on page F-27.

EBIT for the REG segment was $(410) million in 2002 compared with EBIT of $182 million and $196 million for 2001 and 2000, respectively. EBIT consists of the following amounts reported by REG for the periods presented: operating income of $157 million, $180 million and $206 million, respectively; losses of unconsolidated investments of $2 million, zero and zero, respectively; other items, net of $(4) million, $2 million and $(10) million, respectively; and loss on discontinued operations of $561 million, zero and zero, respectively. Reported 2002 EBIT for this segment included after-tax charges of $24 million, including restructuring and reorganization costs and additional regulatory asset amortization. Results were positively impacted in 2002 by weather-related increases in electric and gas residential and commercial sales volumes, offset by lower economic driven industrial sales and a 5% electric residential rate reduction effective May 1, 2002. In addition, electric revenue was positively affected by the resolution of a contingent liability for a bulk power billing dispute. Operating expenses were lower in 2002 due to reduced bad debt expense, a favorable resolution of a sales tax audit and a municipal utility tax adjustment. Discontinued operations included a pre-tax loss of $599 million related to the sale of Northern Natural in the third quarter.

Segment results in 2001 include approximately $9 million of after-tax severance and early retirement charges related to a restructuring at IP, offset by an approximate $10 million after-tax credit related to IP’s exit from a nuclear mutual insurance company. The 2000 results include an approximate $2 million after-tax merger cost charge related to the Illinova acquisition. In addition to the severance and early retirement charges, operating income decreased in 2001 as a result of decreased industrial electricity revenues resulting from increased competition and an economic downturn, offset by weather-driven sales from electric residential and commercial customers. Additionally, operating expenses were slightly higher due to fees paid in connection with an independent system operator and bad debt expense, offset by lower general and administrative expenses.

REG reported operating cash flow was $262 million for the year ended December 31, 2002, compared to $109 million and $302 million for the respective periods in 2001 and 2000. During 2002, non-cash losses increased from 2001 and 2000, primarily due to the $561 million after-tax loss on the sale of Northern Natural and corporate allocated severance and information technology asset impairment charges to IP. Over the three-year period, other non-cash items, such as depreciation, remained relatively flat, with the exception of additional regulatory asset amortization recorded during these periods.

Reported changes in working capital relating to Transmission and Distribution were a net use of $109 million in 2002, compared to a net use of $160 million in 2001 and a net source of $50 million in 2000, respectively. Fluctuations in working capital primarily relate to the timing of payments, such as the IP tax payment, or recognition of liabilities.

Working capital changes in 2001 exceeded those in 2002 primarily due to a payment during 2001 to DMG which was accrued at year end 2000. Conversely, working capital changes increased for the year ended December 31, 2000 primarily due to favorable IP power purchase agreements and an overall increase in trade accruals.

REG Outlook

Future results of operations for IP may be affected, either positively or negatively, by regulatory actions, general economic conditions, weather, overall economic growth, the demand for power and natural gas in IP’s service area and interest rates. IP’s future results also will be affected by its ability to consummate the previously announced sale of its transmission system to Trans-Elect. 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 FERC, and requested a continuance of the hearing pending an order on rehearing and a ruling by FERC on the new rate application. Pending resolution of the FERC issues, the ICC proceeding has also been withdrawn and continued. IP is 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. If we are unable to consummate the Trans-Elect transaction, IP will continue to recognize the revenues and expenses associated with its transmission assets. However, as described below, IP’s liquidity position and future financial condition is not dependent on the receipt of proceeds associated with the pending transaction. If the Trans-Elect transaction cannot be consummated, we will explore other alternatives for IP’s transmission assets, including potentially keeping those assets.

IP has a significant amount of leverage, with near-term maturities including a $100 million payment on its one-year term loan due in May 2003, $190 million in aggregate mortgage bond maturities due in August and

September 2003 and quarterly payments of approximately $22 million due on its transitional funding trust notes. Please read Item 8, Financial Statements and Supplementary Information, Note 10—Debt—Illinois Power Transitional Funding Trust Notes beginning on page F-54 for a discussion of the transitional funding trust notes. IP is required to make these quarterly payments on its transitional funding trust notes through 2008 and has a payment of up to $81 million due on its Tilton lease financing in the third quarter 2004. Because IP has no revolving credit facility and no access to the commercial paper markets, IP relies on cash on hand, cash from asset sales or other capital-raising transactions and cash flows from operations, including interest payments under its $2.3 billion intercompany note receivable from Illinova, to satisfy its debt obligations and to otherwise operate its business. In December 2002, IP sold $550 million of mortgage bonds, $150 million of which were issued in January 2003 following ICC approval. A portion of the proceeds were used to repay $200 million of IP’s $300 million term loan and to refinance a $96 million mortgage bond maturity. The remaining proceeds from this offering are to be used to fund a significant portion of IP’s remaining 2003 maturities. However, IP remains reliant on its ability to execute one or more other liquidity initiatives in order to satisfy its future debt and commercial obligations, including the remaining portion of its third quarter 2003 mortgage bond maturities. We expect these initiatives would include new bank borrowings or mortgage bond issuances or another type of initiative, including support from Dynegy, subject to availability and receipt of any required regulatory approval. Although Dynegy’s recently restructured credit agreement prohibits prepayments of principal on our intercompany note receivable in excess of $200 million, it does not limit Dynegy’s ability to prepay interest under our intercompany note receivable.

Customer Risk Management

	Year Ended December 31,
	2002			2001			2000
				(Restated)			(Restated)
	(in millions, except operating statistics)
Operating Income (Loss)	$	(974	)	$	264		$	143
Earnings (Losses) of Unconsolidated Investments		(21	)		(24	)		3
Other Items, Net		(49	)		(54	)		(1	)
Gain (Loss) on Discontinued Operations		(51	)		(25	)		52
Cumulative Effect of Change in Accounting Principle		—			3			—

Earnings (Loss) Before Interest and Taxes	$	(1,095	)	$	164		$	197

Operating Cash Flows:
Operating Cash Flows Before Changes in Working Capital	$	200		$	180		$	30
Changes in Working Capital		(518	)		(476	)		(50	)

Net Cash Provided By (Used In) Operating Activities	$	(318	)	$	(296	)	$	(20	)


Operating Statistics:
Domestic Gas Marketing Volumes (Bcf/d)		7.4			8.2			7.5
Canadian Gas Marketing Volumes (Bcf/d)		2.3			3.0			2.2
European Gas Marketing Volumes (Bcf/d)		2.2			1.3			1.2

Total Gas Marketing Volumes		11.9			12.5			10.9

Coal Marketing Volumes (Millions of Tons)		38.2			43.0			10.4

CRM reported EBIT of $(1,095) million for 2002 compared to $164 million for 2001 and $197 million for 2000. EBIT consists of the following amounts reported by CRM for the periods presented: operating income (loss) of $(974) million, $264 million and $143 million, respectively; earnings (losses) of unconsolidated investments of $(21) million, $(24) million and $3 million, respectively; other items, net, of $(49) million, $(54) million and $(1) million; gain (loss) on discontinued operations of $(51) million, $(25) million and $52 million, respectively; and cumulative effect of change in accounting principle of zero, $3 million and zero.

Results of operations during the three-year period were influenced either positively or negatively by the following:

•

reduced gas marketing volumes during 2002 as a result of reduced market liquidity and our lower credit ratings;

•

an increase in customer and risk-management activities in 2001, as compared to 2000, as a result of a long-term power agreement that contributed approximately $35 million of non-cash earnings in 2001;

•

an increase in European and Canadian marketing operations due to increased customer origination and service demand during 2000 and 2001;

•

an approximate $82 million after-tax charge relating to exposure to Enron as a result of that company’s bankruptcy filing and an allocation of transaction costs associated with the terminated merger with Enron and the execution of Project Alpha in 2001; and

•

aggregate after-tax gains of approximately $58 million on the sale of Accord, offset by an allocated portion of Illinova acquisition costs, in 2000.

Total natural gas volumes sold decreased to 11.9 billion cubic feet per day in 2002 from 12.5 billion cubic feet per day in 2001 and 10.9 billion cubic feet per day in 2000. The 2001 increase in natural gas volumes sold reflects greater market origination, including sales to commercial and industrial customers, sales volumes on Dynegydirect and increased gas marketing in Canada. The decrease in volumes in 2002 reflects market liquidity and credit concerns.

As a result of our declining credit ratings in 2002, we were required to post significant additional amounts of collateral under the terms of our commercial contracts. This use of working capital resulted in negative operating cash flows in 2002.

CRM Outlook

Our CRM business’ future results of operations will be significantly impacted by our ability to execute on our exit strategy. We are actively pursuing opportunities to assign or renegotiate the terms of our contractual obligations related to this business, particularly some of our power tolling arrangements. While we expect to complete a significant portion of our exit activities during the first half of 2003, some contracts, particularly our power tolling contracts, do not expire for up to 30 years and credit and market liquidity constraints could impact our ability to complete our exit plan and the timing thereof. If we are unsuccessful in our efforts to renegotiate or terminate some of the eight power tolling arrangements to which we remain a party, we would be required to pay an aggregate of approximately $3.8 billion in capacity payments under the related agreements through 2030, including $226 million in 2003 and $229 million in 2004. After applying a LIBOR-based discount rate, these capacity payments approximate $2.7 billion. The discounted fair value of the capacity payments under these arrangements exceeded the market value of electricity available for sale under these arrangements at December 31, 2002 by approximately $501 million. Even if we were successful in our efforts to renegotiate or terminate some of these arrangements, we could incur significant expenses relating to any such renegotiation or termination.

In addition, we have posted collateral to support a substantial portion of our obligations in this business, including approximately $121 million at April 2, 2003 posted in connection with some of our power tolling arrangements. While we have been working with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral. Although we are current on all contract payments to these counterparties, we have received a notice of default from each such counterparty with regard to collateral. We are continuing to negotiate with both parties. Our annual net payments under these two arrangements approximate $67 million and $57 million, respectively, and the contracts extend through 2014 and 2012, respectively. If these counterparties were successful in pursuit of claims that we

defaulted on these contracts, they could declare a termination of these contracts, which provide for termination payments based on the mark-to-market value of the contracts.

We have generally been successful in satisfying customer collateral requirements and have had few terminations or disputes relating to contracts in this segment. However, we are involved in litigation with some of our former counterparties relating to contract terminations with respect to which we were unable to agree on mutually acceptable collateral or other adequate assurance. There is a risk that we may be unable to agree with other counterparties on mutually acceptable forms and amounts of adequate assurance or other collateral, resulting in additional litigation and related expenses. Our ability to address these and other issues relating to collateral posted for ongoing CRM contracts could affect this business’ future results of operations.

We intend to manage actively our exit from the CRM business with the objective of maximizing the ultimate cash proceeds received and completing our exit plan in a timely and cost-effective manner. However, our failure to manage this exit successfully would negatively impact the CRM segment’s results of operations.

SEASONALITY

Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of natural gas, electricity and NGLs. Power marketing operations and electricity generating facilities have higher volatility and demand, respectively, in the summer cooling months, while the transmission and distribution business has higher seasonal gas sales in the winter and higher seasonal electricity sales in the summer. These trends may change over time as demand for natural gas increases in the summer months as a result of increased gas-fired electricity generation. Our liquids businesses are also subject to seasonal factors; however, such factors typically have a greater impact on sales prices than on sales volumes.

CRITICAL ACCOUNTING POLICIES

Our Controller’s Department is responsible for the development and application of accounting policy and control procedures for the organization’s financial and operational accounting functions. This department conducts our activities independent of any active management of our risk exposures, is independent of revenue-producing units and reports to the Chief Financial Officer.

The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We have identified the following six critical accounting policies that require a significant amount of judgment and are considered to be the most important to the portrayal of our financial position and results of operations:

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Revenue Recognition;

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Valuation of Tangible and Intangible Assets;

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Estimated Useful Lives;

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Accounting for Contingencies;

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Accounting for Income Taxes; and

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Valuation of Pension Assets and Liabilities.

Revenue Recognition

We utilize two comprehensive accounting models in reporting our consolidated financial position and results of operations as required by GAAP – an accrual model and a fair value model. We determine the appropriate model for our operations based on guidance provided in applicable accounting standards and

positions adopted by the FASB or the SEC. We have applied these accounting policies on a consistent basis during the three years in the period ended December 31, 2002, except as required by Financial Accounting Standard No. 133 (“FAS No. 133”), which was effective January 1, 2001, and the adoption of EITF 02-03, which rescinded EITF 98-10, “Accounting for Contracts Involved in Energy Trading and risk Management Activities.”

The accrual model has historically been used to account for substantially all of the operations conducted in our GEN, NGL and REG segments. These businesses consist largely of the ownership and operation of physical assets that we use in various generation, processing and delivery operations. These processes include the generation of electricity, the separation of natural gas liquids into their component parts from a stream of natural gas and the transportation or transmission of commodities through pipelines or over transmission lines. End sales from these businesses result in physical delivery of commodities to our wholesale, commercial and industrial and retail customers.

The fair value model has historically been used to account for forward physical and financial transactions in the CRM, GEN and NGL segments, which meet criteria defined by the FASB or the EITF. The criteria are complex but generally require these contracts to relate to future periods, to contain fixed price and volume components and to have terms that require or permit net settlement of the contract in cash or the equivalent. The FASB determined that the fair value model is the most appropriate method for accounting for these types of contracts. In part, this conclusion is based on the cash settlement provisions in these agreements, as well as the volatility in commodity prices, interest rates and, if applicable, foreign exchange rates, which impact the valuation of these contracts. Since these transactions may be settled in cash, the value of the assets and liabilities associated with these transactions is reported at estimated settlement value based on current prices and rates as of each balance sheet date.

We estimate the fair value of our marketing portfolio using a liquidation value approach assuming that the ability to transact business in the market remains at historical levels. The estimated fair value of the portfolio is computed by multiplying all existing positions in the portfolio by estimated prices, reduced by a LIBOR-based time value of money adjustment and deduction of reserves for credit, price and market liquidity risks.

A key aspect of our operations and business strategy is our ability to provide customers with competitively priced bundled products and services that address their specific needs. Many of these customized products and services are not exchange-traded. In addition, the availability of reliable market quotations in certain regions and for certain commodities is limited as a result of liquidity and other factors. Consequently, we use a combination of market quotations, derivatives of market quotations and proprietary models to periodically value our portfolio as required by GAAP. Market quotations are validated against broker quotes, regulated exchanges or third-party information. Derivatives of market quotations use validated market quotes, such as actively traded power prices, as key inputs in determining market valuations.

In certain markets or for certain products, market quotes or derivatives of market quotes are not available or are not considered appropriate valuation techniques as a result of the newness of markets or products, a lack of liquidity in such markets or products or other factors. However, under GAAP, estimating the value of these types of contracts is required. Consequently, prior to the third quarter 2001, we used models principally derived from market research to estimate forward price curves for valuing positions in these markets. Our models generated pricing estimates primarily for regional power markets in the United States and Europe. Price curves were derived by incorporating a number of factors, including broker quotes, near-term market indicators and a proprietar