Edgar Filing: DYNEGY INC /IL/

Amendment No.2 to Form 10-K for Year Ended December 31, 2003

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 2

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

For the fiscal year ended December 31, 2003

¨	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 incorporation or organization)

(I.R.S. Employer

Identification No.)

1000 Louisiana, Suite 5800

Houston, Texas 77002

(Address of principal executive offices)

(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

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


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 x No ¨

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

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

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

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

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

DYNEGY INC. FORM 10-K/A

INTRODUCTORY NOTE

Dynegy Inc. is filing this Amendment No. 2 on Form 10-K/A (“Amendment No. 2”) 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, 2003, which was originally filed on February 27, 2004 (the “Original Filing”):

•

An increase of $139 million to the $242 million goodwill impairment charge originally recorded in the fourth quarter 2003 and a previously unrecorded after-tax asset impairment charge of $120 million, in the fourth quarter 2003, each associated with the sale of Illinois Power and

•

A $154 million decrease to our deferred tax liability at December 31, 2003 resulting from our tax basis balance sheet review.

The aforementioned items are discussed in more detail in the Explanatory Note to the accompanying consolidated financial statements beginning on page F-8. The following Items of the Original Filing are amended by this Amendment No. 2:

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 9A. 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. 2.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 2, 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 REPORTS ON FORM 10-Q FOR THE PERIODS ENDED MARCH 31, 2004, JUNE 30, 2004 AND SEPTEMBER 30, 2004 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 FEBRUARY 27, 2004, INCLUDING OUR QUARTERLY REPORTS ON FORM 10-Q FOR THE PERIODS ENDED MARCH 31, 2004, JUNE 30, 2004 AND SEPTEMBER 30, 2004, OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

DYNEGY INC.

FORM 10-K/A

TABLE OF CONTENTS


		Page
PART I
Definitions		1

PART II
Item 6.	Selected Financial Data	2
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	4
Item 8.	Financial Statements and Supplementary Data	49
Item 9A.	Controls and Procedures	49

PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	51
Signatures		58

Index to Consolidated Financial Statements		F-1
Explanatory Note—Restatements		F-8

PART I

DEFINITIONS

As used in this Amendment No. 2, the abbreviations contained herein have the meanings set forth in the glossary beginning on page F-88. Additionally, the terms “Dynegy,” “we,” “us” and “our” refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.

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.

As discussed in the Explanatory Note to the accompanying Consolidated Financial Statements, the accompanying Consolidated Financial Statements have been restated since the date of the Original Filing. Please read the Explanatory Note to the accompanying Consolidated Financial Statements for additional information about these restatements. The selected financial data that follows has been adjusted to reflect these restatements.

Dynegy’s Selected Financial Data


	Year Ended December 31,
	2003			2002			2001			2000			1999
	(in millions, except per share data)
	(Restated)
Statement of Operations Data (1):
Revenues	$	5,787		$	5,326		$	9,124		$	9,715		$	4,821
General and administrative expenses		(366	)		(325	)		(420	)		(312	)		(208	)
Depreciation and amortization expense		(454	)		(466	)		(452	)		(386	)		(114	)
Asset impairment, abandonment and other charges		(200	)		(190	)		—			—			—
Goodwill impairment		(311	)		(814	)		—			—			—
Operating income (loss)		(569	)		(1,058	)		971			770			185
Interest expense		(509	)		(297	)		(255	)		(247	)		(77	)
Income tax expense (benefit)		(246	)		(352	)		368			230			45
Net income (loss) from continuing operations		(688	)		(1,190	)		479			417			90
Income (loss) on discontinued operations (3)		(19	)		(1,154	)		(82	)		27			44
Cumulative effect of change in accounting principles		40			(234	)		2			—			—
Net income (loss)	$	(667	)	$	(2,578	)	$	399		$	444		$	134
Net income (loss) available to common stockholders		346			(2,908	)		357			409			134
Earnings (loss) per share from continuing operations	$	0.79		$	(4.16	)	$	1.29		$	1.20		$	0.39
Net income (loss) per share		0.84			(7.95	)		1.05			1.29			0.58
Shares outstanding for diluted EPS calculation		423			370			340			315			230
Cash dividends per common share	$	—		$	0.15		$	0.30		$	0.25		$	0.04
Cash Flow Data:
Cash flows from operating activities	$	876		$	(25	)	$	550		$	420		$	40
Cash flows from investing activities		(266	)		677			(3,828	)		(1,539	)		(391	)
Cash flows from financing activities		(900	)		(44	)		3,450			1,131			399
Cash dividends or distributions to partners, net		—			(55	)		(98	)		(112	)		(8	)
Capital expenditures, acquisitions and investments		(338	)		(981	)		(4,687	)		(2,415	)		(521	)



	December 31,
	2003		2002		2001		2000		1999
	(in millions)
	(Restated)
Balance Sheet Data (2):
Current assets	$	3,030	$	7,586	$	8,956	$	10,827	$	2,658
Current liabilities		2,576		6,748		8,538		10,286		2,467
Property, plant and equipment, net		8,203		8,458		9,269		7,148		2,155
Total assets		12,961		20,029		25,083		22,572		6,491
Long-term debt (excluding current portion)		5,893		5,454		5,016		3,754		1,372
Notes payable and current portion of long-term debt		331		861		458		118		192
Non-recourse debt		—		—		—		—		35
Serial preferred securities of a subsidiary		11		11		46		46		—
Subordinated debentures		—		200		200		300		200
Series B Preferred Stock (4)		—		1,212		882		—		—
Series C convertible preferred stock		400		—		—		—		—
Minority interest (5)		121		146		1,040		1,022		—
Capital leases not already included in long-term debt		—		15		29		15		—
Total equity		1,947		2,203		4,894		3,405		1,196

(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 third quarter 2002);

•

U.K. Storage—Hornsea facility (sold fourth quarter 2002) and Rough facility (sold fourth quarter 2002);

•

DGC (portions sold in fourth quarter 2002 and first and second quarters 2003);

•

Global Liquids (sold fourth quarter 2002); and

•

U.K. CRM (substantially liquidated in first quarter 2003).

(4)

The 2002 amount equals the $1.5 billion in proceeds related to the Series B Preferred Stock 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 Note 15—Redeemable Preferred Securities—Series B Preferred Stock beginning on page F-54 for further discussion.

(5)	The 2001 and 2000 amounts include amounts relating to the Black Thunder transaction discussed in Note 12—Debt—Black Thunder Secured Financing beginning on page F-45.

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

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

OVERVIEW

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

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

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

The primary factors impacting our power generation earnings and cash flows are the prices for power and, to a lesser extent, natural gas, which in turn are largely driven by supply and demand. Demand for power can vary regionally due to, among other things, weather and general economic conditions. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation. We also are impacted by the relationship between prices for power and natural gas, commonly referred to as the “spark spread,” and its impact on the cost of generating electricity. However, we believe that our significant coal-fired and fuel oil generating facilities partially mitigate our sensitivity to changes in the spark spread, in that coal and fuel oil prices are relatively stable and insensitive to changes in gas prices, and position us for potential increases in earnings and cash flows in an environment where both power and gas prices increase. Please read “—Liquidity and Capital Resources—Internal Liquidity Sources—Cash Flows from Operations” beginning on page 16 for a discussion of our views on the current pricing environment and its anticipated long-term recovery.

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

•

our ability to control our capital expenditures, which primarily are limited to maintenance, safety, environmental and reliability projects, and other costs through disciplined management and safe, efficient operations;

•

our ability to optimize our assets through forward hedging activities and similar transactions, which is affected by general market liquidity and the need to satisfy counterparties’ collateral requirements given our non-investment grade credit ratings; and

•

our ability to enter into new sales contracts and to renew our existing contracts, particularly the CDWR and Illinois Power power purchase agreements that are scheduled to expire at the end of 2004. In connection with our recently announced agreement to sell Illinois Power to Ameren, we agreed, conditioned upon the closing of the sale, to sell 2,800 MWs of capacity and up to 11.5 million MWh of energy to Illinois Power at fixed prices for two years beginning in January 2005. The closing of the sale to Ameren, which is expected by the end of 2004, is subject to receipt of required regulatory approvals and other closing conditions. Please read “—Results of Operations—Segment Discussion—2004 Outlook—REG Outlook” beginning on page 34 and Note 23—Subsequent Event beginning on page F-86 for further discussion.

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

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

The earnings and cash flows that we generate in this business are sensitive to natural gas and natural gas liquids prices and the relationship between the two, commonly referred to as the “frac spread.” In our upstream business, we continued the restructuring of our contract portfolio in 2003. As a result, our current contract mix has reduced our exposure to frac spread risk. Please read Item 1. Business—Segment Discussion—Natural Gas Liquids—Upstream Business beginning on page 7 of our Original Filing for a detailed discussion of our current upstream contract mix.

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

•

our ability to control our capital expenditures, which primarily are limited to maintenance, safety and reliability projects, and other costs through disciplined management and safe, efficient operations;

•

reduced market liquidity and our obligation to post collateral to counterparties because of our non-investment grade credit ratings, which limit our ability to contract forward physically for some of our natural gas liquids products;

•

producer drilling activity, which is significantly affected by commodity prices;

•

a low frac spread environment and the resulting reduction in volumes available for fractionation, distribution and marketing;

•

the petrochemical industry’s need for and utilization of our natural gas liquids feedstocks and related natural gas liquids facilities;

•

our ability to manage our natural gas liquids inventories efficiently; and

•

our ability to meet customer demands for timely delivery and transportation.

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

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

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

•

weather and its effect on demand for our services, particularly with respect to residential electric customers;

•

the number of customers that choose another retail electric provider under the Illinois Customer Choice Law;

•

general economic conditions and the resulting effect on demand for our services, particularly with respect to commercial and industrial customers.

We recently entered into an agreement to sell Illinois Power and our 20% interest in the Joppa power generation facility to Ameren for $2.3 billion. The transaction is expected to close by the end of 2004, subject to the receipt of required regulatory approvals and other closing conditions. Please read Note 23—Subsequent Event beginning on page F-86 for further discussion.

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

Regarding our legacy gas and power trading positions, we have substantially reduced the size of our portfolio relative to when we were primarily a marketing and trading company. Please read Item 1. Business—Segment Discussion—Customer Risk Management beginning on page 18 of our Original Filing for further discussion.

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

•

interest expense, which increased in 2003 as a result of our refinancing and restructuring activities and will continue to reflect our non-investment grade credit ratings;

•

general and administrative costs, with respect to which we have implemented a number of initiatives expected to yield savings beginning in 2004; general and administrative costs also will be impacted by, among other things, (i) any future corporate-level litigation reserves or settlements and (ii) potential funding requirements under our pension plans; and

•

income taxes, with respect to which we currently only pay minimal state and foreign income taxes; income taxes will also be impacted by our ability to realize our significant deferred tax assets, including loss carryforwards.

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

Liquidity. As of February 23, 2004, we had cash on hand of $397 million and available borrowing capacity of $866 million, for total liquidity of nearly $1.3 billion. During 2003, we substantially reduced our debt and other obligations while maintaining liquidity between $1.4 billion and $1.7 billion. Our ability to maintain our liquidity position in the future will depend on a number of factors, including our ability to consummate the Illinois Power sale to Ameren and, over the longer term, to generate cash flows from our asset-based energy businesses in relation to our substantial debt obligations and ongoing operating requirements.

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

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

LIQUIDITY AND CAPITAL RESOURCES

Debt Maturities

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

•

Restructuring of $1.66 billion in credit facilities prior to their scheduled maturities, in connection with which we granted security interests in a substantial portion of the available assets and stock of our direct and indirect subsidiaries, excluding Illinois Power;

•

Issuance by DHI of $1.75 billion of senior notes at a weighted average interest rate of 9.71% and a weighted average yield to maturity of 9.65%, which notes are secured on a second priority basis by substantially the same collateral that secures the obligations under DHI’s restructured credit facility;

•

Issuance by Dynegy of $225 million of convertible subordinated debentures at an interest rate of 4.75%, which debentures are convertible into shares of our Class A common stock at $4.1210 per share, subject to certain adjustments, and guaranteed on a senior unsecured basis by DHI;

•

The purchase of approximately $282 million of DHI’s $300 million 8.125% Senior Notes due 2005, virtually all of DHI’s $150 million 6³/4% Senior Notes due 2005 and approximately $177 million of DHI’s $200 million 7.450% Senior Notes due 2006; and

•

Restructuring of the $1.5 billion in Series B Mandatorily Convertible Redeemable Preferred Stock previously held by a ChevronTexaco subsidiary, which we refer to as the Series B Preferred Stock. Under this restructuring, which we refer to as the Series B Exchange, the Series B Preferred Stock was exchanged for $225 million in cash, $225 million principal amount of our Junior Unsecured Subordinated Notes due 2016, which we refer to as the Junior Notes, and 8 million shares of our Series C Mandatorily Redeemable Convertible Preferred Stock due 2033 (liquidation preference $50 per share), which we refer to as the Series C preferred stock. The Series C preferred stock generally is convertible into shares of our Class B common stock at $5.78 per share, subject to shareholder approval, which approval we intend to solicit at our 2004 annual shareholder meeting.

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

•

Prepay in full the $200 million Term A loan outstanding under DHI’s restructured credit facility;

•

Prepay in full the $360 million Term B loan outstanding under DHI’s restructured credit facility;

•

Prepay in full the $696 million of debt outstanding under the Black Thunder secured financing; and

•

Prepay in full the $170 million capital lease obligation associated with our CoGen Lyondell power generating facility.

For a more complete description of these transactions, including the increasing interest rate and conversion features of the securities issued in connection with the Series B Exchange, please read Note 11—Refinancing and Restructuring Transactions beginning on page F-39.

As a result of these transactions, we extended a substantial portion of our 2005-2006 maturities to 2008 and beyond. Our aggregate maturities for long-term debt are as follows:


Period	Total		Illinois Power (1)		Total Less Illinois Power (1)
			(in millions)
2004 (2)	$	331	$	157	$	174
2005		258		156		102
2006		130		86		44
2007		270		86		184
2008		311		86		225
Thereafter		4,924		1,366		3,558

(1)	If the Ameren transaction closes as expected before the end of 2004, Ameren will assume Illinois Power’s then outstanding indebtedness. Please read Note 12—Debt beginning on page F-41 for further discussion of our outstanding debt.

(2)	Included in Illinois Power’s 2004 maturities of $157 million is $71 million related to the Tilton capital lease. In October 1999, Illinois Power entered into a sublease with DMG pursuant to which DMG is obligated to make all payments under the lease.

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

While our restructuring and refinancing transactions have extended our significant debt maturities, they also resulted in significantly increased interest expenses, as further described under “—Results of Operations – Interest Expense” beginning on page 32. We also are subject to the more restrictive covenants that are contained in the related transaction agreements. Specifically, among other limitations, these covenants limit our ability to receive payments from DHI for the purpose of paying dividends on our common stock and otherwise, limit DHI’s ability to incur additional indebtedness other than for refinancing purposes and require that a significant portion of proceeds from specified asset sales and equity issuances be used to pay down outstanding indebtedness. For example, upon closing of the agreed sale of Illinois Power to Ameren, we must use 75% of the net cash proceeds to repay the Junior Notes. We are required to use 25% of the net cash proceeds of the sale to reduce permanently or cash collateralize the commitments under the facility, subject to certain exceptions, to the extent the Junior Notes are repaid up to $100 million. If the Junior Notes are not outstanding, 100% of the net cash proceeds from asset sales are required to be used, subject to certain exceptions, to reduce the commitments under the revolver. While we are currently in compliance with these restrictive covenants, our future financial condition and results of operations could be significantly affected by our ability to execute our business and financial strategies within the confines of these restrictive covenants.

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


	December 31, 2003			December 31, 2002
	(in millions)
First Secured Obligations
Dynegy Holdings Inc.	$	1,127		$	2,440
Dynegy Inc.		—			360
Illinois Power (1)		1,967			2,092

Total First Secured Obligations		3,094			4,892
Second Secured Obligations		1,750			—
Unsecured Obligations		2,160			2,266

Subtotal		7,004			7,158
Preferred Obligations		411			1,711

Total Obligations	$	7,415		$	8,869

Less: DNE Lease Financing		(758	)		(746	)
Less: Preferred Obligations		(411	)		(1,711	)
Other (2)		(22	)		(97	)

Total Notes Payable and Long-term Debt	$	6,224		$	6,315

(1)

Ameren will assume Illinois Power’s debt obligations upon closing of our agreed sale of Illinois Power, which is anticipated to occur before the end of 2004, subject to receipt of required regulatory approvals and other closing conditions. Please read Note 23—Subsequent Event beginning on page F-86 for further discussion.

(2)	Consists of net discounts on debt (totaling $12 million and $16 million at December 31, 2003 and December 31, 2002, respectively) and the $10 million difference between the carrying value of the Tilton capital lease

and the purchase obligation of $81 million at December 31, 2003. At December 31, 2002, the Tilton lease was off-balance sheet as it was accounted for as an operating lease.

Collateral Postings

We have substantially reduced our collateral postings since the end of 2002. As detailed in the table below, total collateral postings are down by approximately $704 million as of February 23, 2004. The reduction is particularly pronounced in our CRM segment, which we commenced exiting in October 2002. Our collateral postings are down in that segment by more than $634 million since year-end 2002 and by more than $800 million from their peak at September 30, 2002.

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


	February 23, 2004		December 31, 2003		December 31, 2002
	(in millions)
GEN	$	146	$	136	$	168
CRM		172		121		806
NGL		144		179		166
REG		42		38		28
Other		8		8		48

Total	$	512	$	482	$	1,216

As described in Note 12—Debt—DHI Credit Facility beginning on page F-42, we incur a 0.15% fronting fee upon the issuance of letters of credit under our restructured credit facility. A letter of credit fee is also payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 4.75% of such undrawn amount. To reduce these fees, we have used, and expect to continue to use, cash on hand, as opposed to letters of credit, to satisfy our future collateral obligations where practicable. Our ability to continue this strategy depends to a large extent on the creditworthiness of our counterparties and the availability of cash on hand.

Going forward, we expect counterparties’ collateral demands to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their view of our creditworthiness. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for at least the next 12 months. Over the longer term, we expect to achieve incremental reductions associated with the completion of our exit from the customer risk management business. Please see “—Results of Operations—2004 Outlook—CRM Outlook” beginning on page 35 for a discussion of the expected collateral roll-off from this business.

Disclosure of Contractual Obligations and Contingent Financial Commitments

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

Contractual Obligations

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


	Payments Due by Period
	Total		2004		2005		2006		2007		2008		Thereafter
	(in millions)
Long-Term Debt (including Current Portion)	$	6,153	$	260	$	258	$	130	$	270	$	311	$	4,924
Capital Leases		81		81		—		—		—		—		—
Redeemable Preferred Securities		411		—		—		—		—		—		411
Operating Leases		1,588		81		81		81		127		147		1,071
Unconditional Purchase Obligations		53		53		—		—		—		—		—
Capacity Payments		2,852		259		243		231		232		232		1,655
Conditional Purchase Obligations		766		222		158		207		127		38		14
Pension Funding Obligations		111		8		57		46		—		—		—
Other Long-Term Obligations		7		6		1		—		—		—		—

Total Contractual Obligations	$	12,022	$	970	$	798	$	695	$	756	$	728	$	8,075

Long-Term Debt (including Current Portion). Total amounts of Long-Term Debt (including Current Portion) are included in the December 31, 2003 Consolidated Balance Sheet. For additional explanation, please read Note 12—Debt beginning on page F-41.

Additionally, we have entered into various joint ventures principally to share risk or optimize existing commercial relationships. These joint ventures maintain independent capital structures and, where necessary, have financed their operations on a non-recourse basis to us. Please read Note 9—Unconsolidated Investments beginning on page F-34 for further discussion of these joint ventures.

Capital Leases. Capital leases consist of our Tilton capital lease obligation. Of the $81 million obligation above, $71 million is included in the December 31, 2003 Consolidated Balance Sheet as a component of Notes Payable and Current Portion of Long-Term Debt. The $10 million difference will be accreted over the remaining term of the capital lease through a charge to interest expense with a corresponding increase to short-term debt. We began reflecting the Tilton facility and the related debt in our consolidated balance sheets in September 2003 as a result of our delivery of a notice of our intent to purchase the related turbines upon the lease expiration in September 2004. For additional explanation, please read Note 12—Debt—Tilton Capital Lease beginning on page F-46.

Redeemable Preferred Securities. Total amounts of Redeemable Preferred Securities are included in the December 31, 2003 Consolidated Balance Sheet. For additional explanation, please read Note 15—Redeemable Preferred Securities beginning on page F-53.

Operating Leases. Operating leases includes the minimum lease payment obligations associated with our DNE leveraged lease. For additional information, please read “—Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease” beginning on page 13. Amounts also include minimum lease payment obligations associated with office and office equipment leases.

Unconditional Purchase Obligations. Amounts include natural gas and power purchase agreements. For additional information, please read Note 17—Commitments and Contingencies—Other Commitments and Contingencies—Purchase Obligations beginning on page F-67.

Capacity Payments. Capacity payments include future payments aggregating $2.3 billion under our four remaining power tolling arrangements, as further described in Item 1. Business—Segment Discussion—Customer Risk Management beginning on page 18 of our Original Filing. This amount includes the fixed payments associated with a derivative instrument related to the Sithe tolling arrangement, which is reflected at its fair value on our Consolidated Balance Sheet in Risk-Management Liabilities, as well as amounts relating to contracts that are accounted for on an accrual basis. At December 31, 2003, approximately $325 million of fixed payments have been reflected in the fair value of the Sithe derivative instrument. We are exploring opportunities to renegotiate or terminate one or more of these arrangements on terms we consider economical. Please read “—Results of Operations—2004 Outlook—CRM Outlook” beginning on page 35 for further discussion of the anticipated effects of these arrangements on our future results of operations.

In addition, capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $573 million.

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

Amounts also include $205 million related to Illinois Power’s long-term power purchase agreement with AmerGen. The agreement was entered into in connection with the sale of Illinois Power’s former Clinton nuclear generation facility in December 1999. Illinois Power is obligated to purchase a predetermined percentage of Clinton’s electricity output through 2004 at fixed prices that exceed current and projected wholesale prices. At the time of the sale of the nuclear generation facility, a liability was recorded related to the above-market portion of this purchase agreement, which is being amortized through 2004, based on the expected energy to be purchased from AmerGen.

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

Pension Funding Obligations. Amounts include estimated defined benefit pension funding obligations for 2004 ($8 million), 2005 ($57 million) and 2006 ($46 million). Although we expect to incur significant funding obligations subsequent to 2006, such amounts have not been included in this table because our estimates are imprecise. Under the terms of the sale of Illinois Power to Ameren, we will be required to accelerate certain of our 2005 cash funding requirements at closing of the sale.

Other Long-Term Obligations. Amounts include decommissioning costs related to Illinois Power’s sale of its Clinton nuclear facility in 1999 and decontamination and decommissioning charges associated with Illinois Power’s use of a facility that enriched uranium for the Clinton Power Station.

Contingent Financial Obligations

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


	Expiration by Period
	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
	(in millions)
Letters of Credit (1)	$	188	$	188	$	—	$	—	$	—
Surety Bonds (2)(4)		80		80		—		—		—
Guarantees (3)		131		13		26		26		66

Total Financial Commitments	$	399	$	281	$	26	$	26	$	66

(1)	Amounts include outstanding letters of credit.

(2)	Surety bonds are generally on a rolling 12-month basis.

(3)

Amounts include two charter party agreements relating to VLGCs previously utilized in our global liquids business sub-chartered to a wholly owned subsidiary of Transammonia Inc. The terms of the sub-charters are identical to the terms of the original charter party agreements. We are currently in negotiations with the owners of the VLGCs and their lenders to obtain a novation/release of the two charter party agreements and a release of our guarantees.

(4)	$45 million of the surety bonds were supported by collateral.

Off-Balance Sheet Arrangements

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

DNE Leveraged Lease. As described in Item 1. Business—Segment Discussion—Power Generation—Northeast region—Northeast Power Coordinating Council (NPCC) beginning on page 5 of our Original Filing, we established our presence in the Northeast region by acquiring the DNE power generating facilities in January 2001 for $950 million from Central Hudson Gas & Electric Corporation, Consolidated Edison Company of New York, Inc. and Niagara Mohawk Power Corporation.

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

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

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


	2003		2002		2001
	(in millions)
Lease Expense	$	50	$	50	$	34
Lease Payments (Cash Flows)	$	60	$	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. As of December 31, 2003, the termination payment at par would be $997 million for all of the DNE facilities, which exceeds the $920 million we received on the sale of the facilities. If a termination of this type were to occur with respect to all of the DNE facilities, it would be difficult for DHI to raise sufficient funds to make this termination payment. Alternatively, if one or more of the leases were to be terminated because we determine, for reasons other than as a result of a change in law, that it has become economically or technologically obsolete or that it is no longer useful to our business, DHI must redeem the related pass through trust certificates at par plus a make-whole premium in an amount equal to the discounted present value of the principal and interest payments still owing on the certificates being redeemed less the unpaid principal amount of such certificates at the time of redemption. For this purpose, the discounted present value would be calculated using a discount rate equal to the yield-to-maturity on the most comparable U.S. treasury security plus 50 basis points.

Capital Expenditures

In connection with our restructuring, we have undertaken various efforts to tightly manage costs and capital expenditures. We had approximately $333 million in capital expenditures during 2003. This is a significant reduction from the approximately $947 million in capital expenditures during 2002 and reflects our efforts to improve our capital efficiency without compromising the operational integrity of our facilities. Our 2003 capital spending by segment was as follows (in millions):


GEN	$	151
NGL		51
REG		126
Other		5

Total	$	333

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

We expect capital expenditures for 2004 to approximate $375 million. This primarily includes maintenance capital projects, environmental projects, contributions to equity investments and limited GEN and NGL development projects. The capital budget is subject to revision as opportunities arise or circumstances change. Estimated funds budgeted for the aforementioned items by segment in 2004 are as follows (in millions):


GEN	$	150
NGL		75
REG		140
Other		10

Total	$	375

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

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

Our capital expenditures in 2004 and beyond will be limited by negative covenants contained in our restructured credit agreements. These covenants place specific dollar limitations on our ability to incur capital expenditures except in our REG segment. Please read Note 11—Refinancing and Restructuring Transactions beginning on page F-39 for further discussion of these transactions.

Financing Trigger Events

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

Commitments and Contingencies

Please read Note 17—Commitments and Contingencies beginning on page F-56, which is incorporated herein by reference, for a discussion of our commitments and contingencies.

Dividends on Preferred and Common Stock

Dividend payments on our common stock are at the discretion of our Board of Directors. We do not foresee a declaration of dividends in the near term, particularly given the dividend restrictions contained in our financing agreements. We have, however, continued to make the required dividend payments on our outstanding trust preferred securities. Please read Note 11—Refinancing and Restructuring Transactions beginning on page F-39 for a discussion of the dividend restrictions contained in our financing agreements.

The Series B Preferred Stock issued to ChevronTexaco in November 2001 had no dividend requirement. Because of ChevronTexaco’s discounted conversion option, however, we accreted an implied preferred stock dividend over the redemption period, as required by GAAP. Please read Note 15—Redeemable Preferred Securities beginning on page F-53 for further discussion of this non-cash implied dividend. In conjunction with the Series B Exchange, we recognized a gain of approximately $1.2 billion as a preferred stock dividend during 2003.

We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. We accrued $8 million in dividends during the year ended December 31, 2003. We did not make any dividend payments on the Series C preferred stock during the year ended December 31, 2003. However, we made the first semi-annual dividend payment of $11 million on February 11, 2004, as a result of which capacity under our revolving credit facility was reduced by $11 million. Dividends are payable on the Series C preferred stock in February and August of each year, but we may defer payments for up to 10 consecutive semi-annual periods. Please read Note 15—Redeemable Preferred Securities beginning on page F-53 for further discussion.

Internal Liquidity Sources

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

Cash Flows from Operations. We had operating cash flows of $876 million in 2003, which included approximately $500 million associated with our CRM business and $110 million from a federal income tax refund, neither of which is expected to be repeated in 2004. For 2004, we have projected operating cash flows of $150 to $185 million. This projection, which is subject to change based on a number of factors, many of which are beyond our control, reflects $825 to $850 million in forecasted operating cash flows from our GEN, NGL and REG business segments, offset by projected cash outflows of $180 to $185 million from our customer risk management business and $485 to $490 million in corporate-level expenses, including interest.

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

As described above, much of the restructuring work that we have done has extended our significant debt maturities to 2008 and beyond, positioning us to benefit from this expected long-term recovery in the U.S. power markets. Our future financial condition and results of operations will be materially adversely affected if the U.S power markets fail to recover in accordance with our expectations or if we experience significant price deterioration in the upstream portion of the NGL segment. Please read Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Original Filing for a discussion of our current views on supply and demand in the regions where our power generation business operates.

Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs and to renew or replace our CDWR agreement. With respect to costs, we launched a value creation project in early 2003, a company-wide initiative focused on identifying opportunities to improve our operational efficiencies. In connection with this project, we have undertaken a number of initiatives,

including our October 2003 co-sourcing agreement with Accenture Ltd. and a centralized procurement program, designed to reduce costs across the company. We also have sharpened our focus on reducing operating costs and, in January 2004, entered into a new rail transportation contract that we anticipate will reduce the fees associated with fuel procurement at our coal-fired generation facilities. Our ability to achieve these cost savings in the face of industry-wide increases in labor and benefits costs will impact our future operating cash flows.

In addition, our CDWR power purchase agreement expires by its terms on December 31, 2004. Our share of West Coast Power’s revenues under this agreement in 2003 totaled $305 million. If we are unable to renew or replace this agreement, we would seek to sell the associated energy and capacity into the open market, where our operating cash flows would be dependent on then prevailing market prices. We expect that the generating facilities supporting the CDWR contract would be significantly less profitable as merchant facilities.

Cash on Hand. At February 23, 2004 and December 31, 2003, we had cash on hand of $397 million and $477 million, respectively. We intend to continue our disciplined cash management practices to maintain our cash position. For example, we have been, and intend to continue, substituting more cash as collateral with certain high-credit quality counterparties than letters of credit under our revolving credit facility. This has resulted in reduced letter of credit fees relative to cash interest income. However, unforeseen events such as legal judgments or regulatory requirements, as well as litigation settlements or contract terminations, could negatively impact our ability to do so.

Revolver Capacity. Our primary credit facility is DHI’s $1.1 billion revolving credit facility, which is scheduled to mature on February 15, 2005. We currently have no drawn amounts under this facility, although as of February 23, 2004, we had $222 million in letters of credit issued under the facility. Our ability to borrow and/or issue letters of credit under a revolving credit facility could become increasingly important, particularly if we are unable to generate operating cash flows relative to our substantial debt obligations and ongoing operating requirements or to realize the asset sale proceeds we anticipate. We currently plan to pursue such a renewal or replacement during 2004, although we cannot guarantee that we will be successful in this pursuit. We expect to incur significant fees in connection with any such renewal or replacement. Please see Note 11—Refinancing and Restructuring Transactions—Credit Facility Restructuring beginning on page F-39 for a discussion of the fees we incurred in connection with our April 2003 credit facility restructuring.

Current Liquidity. During 2003, we maintained a strong liquidity position, averaging total available liquidity of approximately $1.5 billion. The following table summarizes our consolidated credit capacity and liquidity position at February 23, 2004, December 31, 2003 and December 31, 2002:


	February 23, 2004			December 31, 2003			December 31, 2002
	(in millions)
Total Revolver Capacity	$	1,088	(1)	$	1,100	(2)	$	1,400
Outstanding Loans		—			—			(228	)
Outstanding Letters of Credit Under Revolving Credit Facility		(222	)		(188	)		(872	)

Unused Revolver Capacity		866			912			300
Cash (3)		397	(4)		477			757
Liquid Inventory (5)		—			—			258

Total Available Liquidity	$	1,263	(6)	$	1,389	(6)	$	1,315

(1)	The February 23, 2004 amount reflects $12 million of mandatory reductions of our revolving credit facility related to asset sales and dividend payments on the Series C preferred stock.

(2)

Reflects the conversion of $200 million of credit capacity under the former DHI revolving credit facilities into the Term A loan in connection with the April 2003 restructuring of such facilities, as well as the May 2003 payment of the final $100 million then outstanding under Illinois Power’s termed out revolving credit facility.

(3)	Reflects $95 million repayment of Illinova senior notes on February 2, 2004.

(4)	Includes approximately $40 million of cash that remains in Canada and the U.K. that is associated primarily with contingent liabilities relating to our former Canadian and U.K. marketing and trading operations.

(5)	Amounts reflected for 2003 and 2004 periods do not include liquid inventory, as we have sold the natural gas inventories that comprised that item and converted them to cash.

(6)

Includes approximately $71 million and $17 million, respectively, of liquidity at Illinois Power. Please read Item 1. Business—Regulation beginning on page 21 of our Original Filing for a discussion of ICC regulations that restrict our ability to receive cash dividends from Illinois Power. Please also read Note 23—Subsequent Event beginning on page F-86 for a discussion of our pending sale of Illinois Power to Ameren.

External Liquidity Sources

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

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

In February 2004, we entered into an agreement to sell Illinois Power and our 20% interest in the Joppa power generation facility to Ameren for $2.3 billion. Upon closing of the transaction, which is subject to regulatory approval and other closing conditions, we would receive $400 million in cash, subject to working capital adjustments, and Ameren would put $100 million in escrow, subject to full release to us on December 31, 2010 or earlier upon the occurrence of specified events. Please read Note 23—Subsequent Event beginning on page F-86 for further discussion of the transaction, which is expected to close before the end of 2004, and the required use of proceeds.

In an effort to maximize our return on investment and to further clarify our business strategy, we are pursuing or considering sales of other assets that we do not consider core to our operations. These assets primarily include our ownership interests in certain non-strategic and international power generation facilities, as further described in Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Original Filing, as well as our minority ownership interests in a gas processing plant and Gulf Coast Fractionators, a partnership that owns a fractionator in Mont Belvieu. The sales of these non-core assets, together with other potential payments relating to our prior sale of the Hackberry LNG project, are expected to generate aggregate cash proceeds of $255 to $270 million in 2004. These aggregate proceeds include approximately $5.5 million in proceeds received in January 2004 in connection with the sale of our Jamaica investment. Generally, the aggregate projected earnings impact of these transactions is not considered material and is expected to be offset substantially by net gains on sale in 2004.

We are in the late stages of negotiations to sell our remaining interest in the Hackberry LNG project. Commercial conditions affecting projects of this type have reduced the value of our interest, which primarily included rights to future earnings from the project. As a result, we could agree to a sale of our interest at a price that would reduce the $255 to $270 million in anticipated sale proceeds above by $30 to $35 million.

Our desire or ability to effect these transactions is subject to a number of factors, many of which are beyond our control, including the market for the subject assets and investments and the receipt of any regulatory and other approvals that may be required. Accordingly, we cannot make any guarantees that these sales will be consummated or that the expected proceeds will be received. In addition, if the sales are consummated while the Junior Notes remain outstanding, we are required to use: (i) 75% of the net cash proceeds from the sale of Illinois Power to pay down the Junior Notes and 25% of the net cash proceeds to reduce the commitments of the

revolver; (ii) 25% of the net cash proceeds from other sales to pay down the Junior Notes; and (iii) 25% of the net cash proceeds from other sales to reduce permanently or cash collateralize the commitments under our revolving credit facility up to a maximum of $100 million. If the Junior Notes are not outstanding, 100% of the net cash proceeds from asset sales are required to be used, subject to certain exceptions, to reduce the commitments under the revolver. We intend to use the remaining proceeds to pay transaction fees and expenses and to repay other outstanding debt.

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

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

The proceeds from any such issuance would be subject to the mandatory prepayment provisions of our revolving credit agreement and second secured senior notes indenture, which generally do not require prepayment for the first $250 million in proceeds, which may be used for repayment of the Junior Notes and for dollar-for-dollar commitment reduction under our revolving credit facility up to a maximum of $100 million. Please see Note 12—Debt—DHI Credit Facility beginning on page F-42 for further discussion.

Conclusion

During 2003, we completed a series of refinancing and restructuring transactions that included sales of nearly $2.0 billion in DHI second priority senior secured notes and Dynegy convertible subordinated debentures. We used the net proceeds from these offerings, together with cash on hand, to repay approximately $2.0 billion in 2005-2006 debt maturities. We also made a $225 million cash payment to ChevronTexaco as part of the Series B Exchange. As a result of these transactions, we have extended a substantial portion of our debt maturities from 2005-2006 to 2008 and beyond and eliminated the uncertainty that surrounded the Series B Preferred Stock.

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

Over the longer term, our liquidity position and financial condition will be materially affected by a number of factors, including our ability to consummate the Illinois Power sale to Ameren and to generate cash flows from our asset-based energy businesses in relation to our debt and commercial obligations, including a substantial increase in interest expense, the fixed payment obligations associated with our CRM business and counterparty collateral requirements. The sale of Illinois Power would provide significant cash proceeds to repay

outstanding debt and advance our business strategy of focusing on our unregulated energy businesses. Our future financial success is also substantially dependent on our ability to renew or replace our $1.1 billion revolving credit facility, which is scheduled to mature on February 15, 2005, with respect to which our ability to borrow and/or issue letters of credit could become increasingly important.

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

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

RESULTS OF OPERATIONS

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

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

Prior to January 1, 2003, the GEN and CRM segments were operated together as an asset-based third-party marketing, trading and risk-management business, then referred to as the WEN segment. Please read Note 21—Segment Information beginning on page F-79 for a discussion of the impact of comparing segment results period over period. Regarding our results of operations for 2003, 2002 and 2001, the impact of acquisition and disposition activity reduces the comparability of some of our historical financial and volumetric data. Lastly, recent accounting pronouncements have affected our financial results, particularly those of our CRM business, so as to further reduce the comparability of some of our historical financial data. For example, the rescission of EITF Issue 98-10, effective January 1, 2003, has reduced the number of contracts accounted for on a mark-to-market basis in the 2003 period as compared to the 2002 and 2001 periods. Please read “—Results of Operations —Cumulative Effect of Change in Accounting Principles” beginning on page 31 for further discussion.

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

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for 2003, 2002 and 2001, respectively (in millions). This financial data has been restated to reflect the items described in the Explanatory Note to the accompanying Consolidated Financial Statements. The restatements relate to an increased impairment associated with the sale of Illinois Power and our deferred income tax accounts. Please read this Explanatory Note for further discussion of these restatement items.

Year Ended December 31, 2003


	GEN			NGL			REG			CRM			Other and Eliminations			Total
	(Restated)
Operating income (loss)	$	194		$	170		$	(302	)	$	(385	)	$	(246	)	$	(569	)
Earnings (losses) from unconsolidated investments		128			(2	)		—			(2	)		—			124
Other items, net		4			(17	)		—			31			2			20
Discontinued operations		—			(2	)		(3	)		(30	)		7			(28	)
Cumulative effect of change in accounting principles		24			—			(3	)		43			—			64

Earnings (loss) before interest and taxes	$	350		$	149		$	(308	)	$	(343	)	$	(237	)	$	(389	)
Interest expense																	(509	)

Pre-tax loss																	(898	)
Income tax benefit																	231

Net loss																$	(667	)


Year Ended December 31, 2002

	GEN			NGL			REG			CRM			Other and Eliminations			Total
	(Restated)
Operating income (loss)	$	(341	)	$	77		$	157		$	(951	)	$	—		$	(1,058	)
Earnings (losses) from unconsolidated investments		(71	)		14			(2	)		(21	)		—			(80	)
Other items, net		(20	)		(34	)		(4	)		(49	)		—			(107	)
Discontinued operations		—			(37	)		(561	)		(51	)		(854	)		(1,503	)
Cumulative effect of change in accounting principles		—			—			—			—			(234	)		(234	)

Earnings (loss) before interest and taxes	$	(432	)	$	20		$	(410	)	$	(1,072	)	$	(1,088	)	$	(2,982	)
Interest expense																	(297	)

Pre-tax loss																	(3,279	)
Income tax benefit																	701

Net loss																$	(2,578	)


Year Ended December 31, 2001

	GEN			NGL			REG			CRM			Other and Eliminations			Total
	(Restated)
Operating income	$	391		$	133		$	182		$	265		$	—		$	971
Earnings (losses) from unconsolidated investments		202			13			—			(24	)		—			191
Other items, net		(5	)		(3	)		2			(54	)		—			(60	)
Discontinued operations		—			(2	)		—			(25	)		(100	)		(127	)
Cumulative effect of change in accounting principles		—			—			—			3			—			3

Earnings (loss) before interest and taxes	$	588		$	141		$	184		$	165		$	(100	)	$	978
Interest expense																	(255	)

Pre-tax income																	723
Income tax provision																	(324	)

Net income																$	399

The following table provides summary segmented operating statistics for 2003, 2002 and 2001, respectively:


	Year Ended December 31,
	2003		2002		2001
Power Generation
Million megawatt hours generated—gross		39.1		39.8		40.3
Million megawatt hours generated—net		37.2		37.4		34.5
Average natural gas price—Henry Hub ($/MMbtu) (1)	$	5.28	$	3.35	$	3.90
Average on-peak market power prices ($/MW hour)
Cinergy	$	37.26	$	26.89	$	34.85
Commonwealth Edison		36.73		26.45		34.15
Southern		41.27		30.10		38.30
New York—Zone G		61.47		46.36		51.51
ERCOT		44.89		29.10		39.26

Natural Gas Liquids
Natural gas processing volumes (MBbls/d):
Field plants		59.6		56.0		56.1
Straddle plants		25.6		35.9		27.7

Total natural gas processing volumes		85.2		91.9		83.8

Fractionation volumes (MBbls/d)		185.3		215.2		226.2
Natural gas liquids sold (MBbls/d)		311.7		498.8		557.4
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	31.01	$	25.75	$	26.39
Natural gas—Henry Hub ($/MMbtu) (2)	$	5.38	$	3.22	$	4.26
Natural gas liquids ($/Gal)	$	0.55	$	0.40	$	0.45
Fractionation spread ($/MMBtu)—first of month	$	0.87	$	1.26	$	0.88
Fractionation spread ($/MMBtu)—daily	$	0.79	$	1.13	$	1.15

Regulated Energy Delivery
Electric sales in KWH (millions)
Residential		5,309		5,548		5,202
Commercial		4,413		4,415		4,337
Industrial		6,123		6,306		6,353
Transportation of customer-owned electricity		2,382		2,505		2,645
Other		374		370		373

Total electric sales		18,601		19,144		18,910

Gas sales in Therms (millions)
Residential		337		323		315
Commercial		145		137		136
Industrial		70		80		88
Transportation of customer-owned gas		226		233		246

Total gas delivered		778		773		785

Cooling degree days—Actual (3)		980		1,467		1,302
Cooling degree days—10-year rolling average		1,214		1,246		1,297
Heating degree days—Actual (4)		5,256		5,118		4,749
Heating degree days—10-year rolling average		4,930		5,002		5,032

(1)	Calculated as the average of the daily gas prices for the period.

(2)	Calculated as the average of the first of the month prices for the period.

(3)	A Cooling Degree Day (CDD) represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in our region. The CDDs for a period of time are computed by adding the CDDs for each day during the period.

(4)	A Heating Degree Day (HDD) represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in our region. The HDDs for a period of time are computed by adding the HDDs for each day during the period.

The following tables summarize significant items on a pre-tax basis, with the exception of the 2003 tax item, affecting net income (loss) for the periods presented.


	Year Ended December 31, 2003
	GEN			NGL			REG			CRM			Other			Total
	(in millions)
Goodwill impairment	$	—		$	—		$	(311	)	$	—		$	—		$	(311	)
Asset impairment		—			—			(193	)		—			—			(193	)
Southern Power tolling settlement		—			—			—			(133	)		—			(133	)
Sithe power tolling contract		—			—			—			(121	)		—			(121	)
Second quarter accrual of legal reserve		—			—			—			—			(50	)		(50	)
Batesville tolling settlement		—			—			—			(34	)		—			(34	)
Kroger settlement		—			—			—			(30	)		—			(30	)
Discontinued operations		—			(2	)		(3	)		(30	)		7			(28	)
Impairment of generation investments		(26	)		—			—			—			—			(26	)
Acceleration of financing costs		—			—			—			—			(24	)		(24	)
West Coast Power goodwill impairment		(20	)		—			—			—			—			(20	)
Impairment of fractionator investment		—			(12	)		—			—			—			(12	)
Taxes		(1	)		—			—			—			34			33
Gain on sale of Hackberry LNG		—			25			—			2			—			27
Cumulative effect of change in accounting principles		24			—			(3	)		43			—			64

Total	$	(23	)	$	11		$	(510	)	$	(303	)	$	(33	)	$	(858	)


	Year Ended December 31, 2002
	GEN			NGL			REG			CRM			Other			Total
	(in millions)
Discontinued operations	$	—		$	(37	)	$	(561	)	$	(51	)	$	(854	)	$	(1,503	)
Goodwill impairment		(489	)		—			—			(325	)		—			(814	)
Restructuring costs		(42	)		(19	)		(23	)		(73	)		—			(157	)
Impairment of generation investments		(144	)		—			—			—			—			(144	)
Generation equity earnings (loss)		(50	)		—			—			—			—			(50	)
Impairment of technology investments		(5	)		(4	)		(2	)		(20	)		—			(31	)
Tolling settlement accrual		—			—			—			(25	)		—			(25	)
Illinois Power regulatory asset amortization expense		—			—			(23	)		—			—			(23	)
ChevronTexaco contract settlement		—			—			—			(22	)		—			(22	)
Enron settlement		(6	)		(4	)		(2	)		(9	)		—			(21	)
Other (1)		(23	)		(3	)		(1	)		(37	)		—			(64	)
Cumulative effect of change in accounting principle		—			—			—			—			(234	)		(234	)

Total	$	(759	)	$	(67	)	$	(612	)	$	(562	)	$	(1,088	)	$	(3,088	)


	Year Ended December 31, 2001
	GEN			NGL			REG			CRM			Other			Total
	(in millions)
Discontinued operations	$	—		$	(2	)	$	—		$	(25	)	$	(100	)	$	(127	)
Enron bankruptcy exposure		—			—			—			(129	)		—			(129	)
Illinois Power severance costs		—			—			(15	)		—			—			(15	)
Terminated Enron merger costs		(2	)		(1	)		(3	)		(3	)		(1	)		(10	)
Cumulative effect of change in accounting principle		—			—			—			3			—			3

Total	$	(2	)	$	(3	)	$	(18	)	$	(154	)	$	(101	)	$	(278	)

(1)

Other includes a pre-tax charge of approximately $25 million related to the write-off of our investment in Dynegydirect and a pre-tax charge of approximately $14 million associated with the impairment of a generation turbine. These amounts are included in Impairment and other charges. Other also includes various other individually insignificant items.

Operating Income (Loss)

Operating income (loss) was $(569) million in 2003, compared to $(1,058) million and $971 million in 2002 and 2001, respectively.

GEN. Operating income (loss) for the GEN segment was $194 million in 2003, compared to $(341) million and $391 million in 2002 and 2001, respectively. Operating income for 2003 included general and administrative expense of $61 million and depreciation and amortization expense of $188 million. Please see “—Other” beginning on page 28 for a consolidated discussion of general and administrative expense and depreciation and amortization expense.

Operating income for 2002 included the following charges:

•

a $489 million impairment of goodwill (please see Note 10—Goodwill beginning on page F-38 for further discussion);

•

$42 million charge associated with this segment’s allocated portion of costs incurred in connection with our corporate restructuring and related work force reductions (please see Note 4—Restructuring and Impairment Charges—Severance and Other Restructuring Costs beginning on page F-27 for further discussion);

•

$14 million associated with the impairment of a turbine; and

•

$6 million associated with fees related to a voluntary action that we took that altered the accounting for certain lease obligations.

In addition, operating income for 2002 included general and administrative expense of $66 million and depreciation and amortization expense of $175 million. Operating income for 2001 included general and administrative expense of $103 million and depreciation and amortization expense of $163 million.

Operating income in 2003 included a $34 million benefit related to pricing and a $51 million benefit due to generated volumes versus 2002. GEN’s results for 2003 reflect higher power prices on average as compared to 2002. This is primarily driven by higher demand in the Midwest and Northeast regions given colder than expected weather conditions during the first half of 2003. Average on-peak prices in the Midwest and Northeast regions during 2003 increased 39 percent and 33 percent, respectively, from the corresponding prices for 2002. The earnings from our peaking generation facilities, which include both capacity and energy sales, were unfavorably impacted by compressed natural gas spark spreads and overcapacity in the generation marketplace. Overall, volumes remained relatively flat to 2002; however, the net MW hours in the Midwest and Northeast were 21.1 million and 5.7 million, respectively, for 2003 compared to 20.4 million and 3.6 million, respectively, for 2002.

Operating income for 2002 included approximately $30 million associated with favorable fuel supply contracts that expired in 2002. Additionally, revenues associated with the DNE facilities decreased approximately $20 million in 2003 as compared to 2002. This decrease primarily reflects reduced income recognized through amortization of a liability established for a transitional power purchase agreement acquired from the seller of the facilities as part of the acquisition, which agreement expires in October 2004. Finally, 2003 operating income includes an $11 million charge related to a comprehensive settlement agreement with a manufacturer of turbines in which we agreed in principle to forfeit a prepayment in the amount of $11 million.

Operating income in 2002 included a $155 million decrease related to pricing and a $50 million benefit due to generated volumes versus 2001. GEN’s results for 2002 reflect lower power prices on average as compared to 2001. This was primarily driven by a weakening economy, significantly compressed natural gas spark spreads

and milder than normal summer and winter temperatures. Average on-peak prices in the Midwest and Northeast regions during 2002 decreased 23 percent and 10 percent, respectively, from the corresponding prices for 2001. Volumes increased in 2002 by 8 percent over 2001 primarily due to increased coal-fired production in the Midwest. The net MW hours generated by our Midwest and Northeast facilities were 18 million and 4.3 million, respectively, for 2001.

The decrease in operating income for 2002 also results from the fact that 2001 included approximately $50 million in revenue generating capacity contracts that expired and were not renewed in 2002. Also, revenues associated with the DNE facilities decreased approximately $40 million in 2002 as compared to 2001. This decrease primarily reflects reduced income recognized through the amortization of a liability established for a transitional power purchase agreement acquired from the seller of the facilities as part of the acquisition, which agreement expires in October 2004.

GEN’s reported operating income for the 2003 period also includes approximately $4 million of mark-to-market income related to purchases and sales that did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market basis. GEN’s results for the 2002 and 2001 periods include approximately $8 million and $11 million, respectively, of mark-to-market income related to derivative contracts that did not qualify as hedges.

In December 2003, we tested certain 100% owned assets for impairment in accordance with SFAS No. 144, based on the identification of certain trigger events. These triggers indicated that our Bluegrass, Calcasieu, Riverside, Rockingham and Rolling Hills peaking facilities could be impaired due to decreased spark spreads and other market factors. After performing the test, it was concluded that no impairment was necessary as the estimated undiscounted cash flows exceeded the book value of the respective asset.

Operating income for 2002 and 2001 reflects the sale to our CRM segment of the fair value of GEN’s generation capacity, forward sales and related trading positions at an internally determined transfer price. For 2003, operating income for the GEN segment reflects the sale of power to third parties at market prices.

NGL. Operating income for the NGL segment was $170 million in 2003, compared to $77 million and $133 million in 2002 and 2001, respectively. Operating income for 2003 included general and administrative expense of $37 million and depreciation and amortization expense of $81 million. Please see “—Other” beginning on page 28 for a consolidated discussion of general and administrative expense and depreciation and amortization expense. 2003 operating income also included a $25 million gain associated with the sale of our Hackberry LNG project. Please see Note 3—Discontinued Operations, Dispositions, Contract Terminations and Acquisitions—Dispositions and Contract Termination—Hackberry LNG Project beginning on page F-25 for further discussion.

Operating income for 2002 included $19 million in charges relating to this segment’s allocated portion of costs incurred in connection with our corporate restructuring and related work force reductions, as well as general and administrative expense of $36 million and depreciation and amortization expense of $88 million. Operating income for 2001 included general and administrative expense of $48 million and depreciation and amortization expense of $84 million.

The decrease in operating income in 2002 as compared to 2001 and 2003 relates primarily to the upstream business. As compared to 2002, 2001 and 2003 experienced higher natural gas and natural gas liquids prices, which resulted in a significant increase in processing plant margins at our field plants, where our frac spread risk is largely mitigated as a result of our substantial POP and POL contracts. In addition to favorable pricing, volumes of natural gas liquids produced at our field plants were 6% higher in 2003 as compared to 2002 and 2001. This is primarily due to increased production in the highly active drilling area in North Texas. Our 2003 straddle plant volumes were substantially in line with 2001 volumes, but much lower as compared to 2002 because of the low frac spread, which resulted in our decision to by-pass unprofitable gas or to shut-down some of our plants that are subject to significant frac spread risk and whose contract mix is substantially made up of KW contracts.

In our downstream business, volumes available for fractionation have steadily declined over each of the last three years from 226 MBbls per day in 2001 to 185 MBbls per day in 2003 as a direct result of reduced natural gas liquids recovery from both our own and from third-party gas processing plants due to the low frac spread. Additionally, some of our competitors’ recent expansion of Mont Belvieu area fractionation capacity beyond the availability of raw natural gas liquids supplies has increased competition for supplies, leading to lower fees charged for fractionation service in the area.

In our wholesale marketing operations, profits were higher due to margin increases resulting from weather-driven propane sales in the first quarter and the impact of higher commodity prices on contracts where we retain a percentage of the sales price as our fee for marketing natural gas liquids on behalf of others, such as in our refinery services agreements and our natural gas liquids marketing agreements with ChevronTexaco. NGL’s marketing results declined from prior period levels as a result of reduced overall market liquidity and customer concerns relating to our liquidity and non-investment grade credit status. Finally, downstream operating income for 2002 and 2001 includes income of approximately $18 million and $14 million, respectively, related to our Canadian crude business, which was sold in August 2002. Although our marketed volumes declined from approximately 498,800 barrels per day in 2002 to approximately 311,700 barrels per day during 2003 due to reduced domestic marketing opportunities and the divestiture of our global liquids business, effective January 1, 2003, this decline had little impact on our operating income, as the financial impact of our global liquids business is included in discontinued operations for all periods presented. The global liquids business sold an average of 95,500 barrels per day in 2002.

REG. Operating income (loss) for the REG segment was $(302) million in 2003, compared to $157 million and $182 million in 2002 and 2001, respectively. Operating income for 2003 included a $504 million charge for the impairment of goodwill and other assets associated with this segment, as further described in Note 10—Goodwill beginning on page F-38, as well as general and administrative expense of $68 million and depreciation and amortization expense of $121 million. Please see “—Other” beginning on page 28 for a consolidated discussion of general and administrative expense and depreciation and amortization expense.

Operating income for 2002 included restructuring charges of $23 million, as well as general and administrative expense of $67 million and depreciation and amortization expense of $175 million. Operating income for 2001 included a $15 million charge for severance costs, as well as general and administrative expense of $65 million and depreciation and amortization expense of $171 million.

We were negatively impacted in 2003 as compared to 2002 by cooler than normal spring and summer weather partially offset by colder than normal winter weather, which caused net decreases in residential and commercial electricity sales volumes and increases in residential and commercial gas sales volumes. Additionally, revenues during 2003 and 2002 attributable to the sale of electricity to residential customers were negatively impacted by a 5% rate reduction effective May 1, 2002. 2002 operating income was favorably impacted as compared to 2001 due to weather-related increases in electric and gas residential and commercial sales volumes. The decrease in industrial revenues from 2001 to 2003 is primarily due to unfavorable economic conditions.

CRM. Operating income (loss) for the CRM segment was $(385) million in 2003, compared to $(951) million and $265 million in 2002 and 2001, respectively. Results for 2003 were impacted by the following pre-tax losses:

•

$133 million charge associated with the settlement of power tolling arrangements with Southern Power, for which we paid $155 million;

•

$121 million mark-to-market loss on contracts associated with the Sithe Independence power tolling arrangement;

•

$34 million charge associated with the cash settlement of the Batesville tolling arrangement; and

•

$30 million associated with the settlement of power supply agreements with Kroger, for which we received approximately $110 million.

In addition, 2003 results include losses associated with fixed payments on power tolling arrangements in excess of realized margins on power generated and sold pursuant to these arrangements. These items were offset by gains totaling approximately $61 million associated with sales of natural gas in storage which had previously been recorded at fair value. Please read Note 2—Accounting Policies—Revenue Recognition beginning on page F-15 for additional details.

Results for 2002 were impacted by the following items:

•

$325 million charge for the impairment of goodwill (for further information, please see Note 10—Goodwill beginning on page F-38);

•

$73 million in costs associated with our corporate restructuring and related work force reductions (for further information, please see Note 4—Restructuring and Impairment Charges—Severance and Other Restructuring Costs beginning on page F-27);

•

$25 million in charges associated with the settlement of tolling contracts;

•

$25 million in charges associated with the write-off of our investment in Dynegydirect; and

•

$7 million in losses associated with the sale of our Canadian physical gas business to Seminole.

In addition, 2002 results included general and administrative expense of $154 million and depreciation and amortization expense of $28 million. Please see “—Other” below for a consolidated discussion of general and administrative expense and depreciation and amortization expense. Finally, 2002 results were negatively impacted by reduced gas marketing volumes as a result of reduced market liquidity and our lower credit ratings.

Results for 2001 were impacted by the following:

•

$129 million charge relating to exposure to Enron as a result of its Chapter 11 filing;

•

$35 million mark-to-market gain on the Sithe Independence power tolling arrangement; and

•

Higher commodity prices and price and basis volatility as well as market liquidity.

In addition, 2001 results included general and administrative expense of $205 million and depreciation and amortization expense of $34 million.

During 2002 and 2001, the CRM segment was actively managed as part of our ongoing strategy and its results included, in part, settlement with third parties of physical power and other trading positions purchased from our GEN segment at an internally determined transfer price. Please read Note 21—Segment Information beginning on page F-79 for further discussion.

Other. Other operating income (loss) was $(246) million in 2003, compared to zero in 2002 and 2001. The $(246) million loss in 2003 primarily relates to general and administrative expenses and depreciation and amortization expenses which are incurred at a corporate level. Prior to 2003, these costs were allocated to the segments.

Consolidated general and administrative expenses were $366 million in 2003, compared to $325 million and $420 million in 2002 and 2001, respectively. The $41 million increase from 2002 to 2003 is principally the result of the $50 million second quarter 2003 litigation reserve and higher professional fees, offset by significantly

lower compensation costs in the 2003 period resulting from the work force reductions. The $95 million decrease from 2001 to 2002 is primarily due to lower compensation expenses in the 2002 period, due to the June 2002 and October 2002 work force reductions, which included 325 and 780 people, respectively, as well as a reduction in variable compensation expense.

Consolidated depreciation and amortization expenses were $454 million in 2003, compared to $466 million and $456 million in 2002 and 2001, respectively. The $12 million decrease from 2002 to 2003 is primarily due to reduced depreciation in our REG segment, offset by increased depreciation of generation assets due to an increased asset base. The $10 million increase from 2001 to 2002 is primarily due to the $23 million acceleration of regulatory amortization recorded in our REG segment in 2002, as well as a $17 million charge recorded in the fourth quarter 2002 associated with the acceleration of depreciation due to a change in the estimated useful lives of leasehold improvements and technology assets which were abandoned as part of our October 2002 restructuring. In addition, depreciation in 2002 was slightly higher due to an increased asset base. Increases in our asset base during the three-year period include the construction of the Heard and Riverside facilities in 2001, the construction of the Renaissance, Bluegrass and Foothills facilities in 2002 and the completion of Rolling Hills in 2003. These items were offset by a $46 million decrease due to the implementation of SFAS No. 142, which required the discontinuation of goodwill amortization beginning January 1, 2002.

Earnings (Losses) from Unconsolidated Investments.

Our earnings (losses) from unconsolidated investments were approximately $124 million during 2003 compared to $(80) million and $191 million in 2002 and 2001, respectively. Both 2002 and 2003 results include significant impairment charges related to these investments, primarily associated with the GEN segment.

GEN. GEN’s earnings (losses) from unconsolidated investments were approximately $128 million during 2003 compared to $(71) million and $202 million in 2002 and 2001, respectively. Earnings for 2003 include a $26 million impairment of U.S. and international investments and a $20 million charge associated with our 50% share of a goodwill impairment charge recorded by West Coast Power in the fourth quarter 2003. Earnings for 2002 include a $144 million impairment of U.S. investments as well as a $50 million charge associated with our 50% share of a bad debt allowance recognized by West Coast Power. West Coast Power provided equity earnings of approximately $117 million, $17 million and $162 million in the years ended December 31, 2003, 2002 and 2001, respectively. Excluding impairments, earnings from our West Coast Power investment are the primary driver of results for each of the three periods.

Earnings at West Coast Power were higher in 2003 as compared to 2002 due to higher realized margins resulting from forward hedges put in place in connection with the execution of the CDWR contract. The decrease in earnings at West Coast Power from 2001 to 2002 is due in part to a reduction in contingent capacity and energy sales under the CDWR contract, as well as lower overall market prices. Please read Item 1. Business—Segment Discussion—Power Generation—West region—Western Electricity Coordinating Council (WECC) beginning on page 6 of our Original Filing for further discussion of the CDWR contract.

As noted above, we recorded a $26 million impairment of our investments in Panama, Jamaica, Michigan Power, Commonwealth and Black Mountain, because of our determination that current market value was less than the book values of the investments.

As noted above, we recorded a $144 million impairment of U.S. investments in 2002, of which $33 million related to West Coast Power. We assessed the carrying value of our generation portfolio on an asset-by-asset basis and determined that the fair value of some of our U.S. investments was less than our book value. The diminution in the fair value of these investments was primarily a result of depressed energy prices.

NGL. NGL’s earnings (losses) from unconsolidated investments were approximately $(2) million during 2003 compared to $14 million and $13 million in 2002 and 2001, respectively. NGL’s 2003 results were

negatively impacted by a $12 million pre-tax impairment on our minority investment in GCF related to the difference between our book value and indicative bids received related to the possible sale of our minority investment. In addition, WTLPS, which we sold to ChevronTexaco in August 2002, contributed approximately $6 million and $5 million to our results for the years ended December 31, 2002 and 2001, respectively.

CRM. CRM’s earnings (losses) from unconsolidated investments were approximately $(2) million during 2003 compared to $(21) million and $(24) million in 2002 and 2001, respectively. As of December 31, 2003, CRM has no material unconsolidated investments. As such, 2004 and future results are expected to be immaterial. The 2002 loss is primarily comprised of charges allocated to the CRM segment for impairments associated with technology investments. The 2001 loss of $24 million is primarily comprised of a $19 million impairment on a technology investment and a $6 million loss on our investment in Nicor Energy.

Other Items, Net

Other items, net consists of other income and expense items, net, minority interest income (expense) and accumulated distributions associated with trust preferred securities. Other items, net totaled $20 million, $(107) million and $(60) million for 2003, 2002 and 2001, respectively.

The 2003 results included the following significant items:

•

$17 million in interest income;

•

$11 million gain on foreign currency transactions;

•

$8 million charge for accumulated distributions associated with trust preferred securities; and

•

The remaining amounts consist of individually insignificant items.

The 2002 results included the following significant items:

•

$36 million in interest income;

•

$36 million minority interest deduction, primarily related to ABG Gas Supply and Black Thunder;

•

$22 million charge relating to the cancellation of our natural gas purchases and sales contract with ChevronTexaco;

•

$21 million charge associated with the settlement of the Enron litigation relating to the termination of our proposed merger;

•

$12 million charge for accumulated distributions associated with trust preferred securities;

•

$10 million charge primarily related to our settlements with the CFTC ($4 million) and SEC ($3 million); and

•

The remaining amounts consist of individually insignificant items.

The 2001 results included the following significant items:

•

$49 million interest income;

•

$13 million dividend income on our investment in Northern Natural preferred stock;

•

$93 million minority interest deduction, primarily related to Black Thunder;

•

$22 million charge for accumulated distributions associated with trust preferred securities; and

•

The remaining amounts consist of individually insignificant items.

Discontinued Operations

Discontinued operations include Northern Natural in our REG segment, our global liquids business in the NGL segment, our U.K. natural gas storage assets and our U.K. CRM business in the CRM segment and our communications business in Other and Eliminations. The largest contributor to the pre-tax loss of $28 million ($19 million after-tax) for 2003 is $30 million in pre-tax losses on operations of U.K. CRM and the U.K. natural gas storage assets. This loss is associated with costs relating to our exit from these foreign operations.

During 2002, the $1,503 million pre-tax loss ($1,154 million after-tax) from discontinued operations was primarily comprised of $854 million in pre-tax losses ($538 million after-tax) from the global communications business and $561 million in pre-tax losses ($538 million after-tax) from Northern Natural. The global communications business recorded pre-tax charges of $635 million for the impairment of communications assets. The remaining $219 million in losses is related to approximately $48 million of impairments of technology investments and carrying costs associated with the business. In August 2002, we sold Northern Natural to MidAmerican and incurred a pre-tax loss of approximately $599 million associated with the sale. We recorded a valuation allowance against a portion of the tax benefit resulting from the sale, due to uncertainty as to the ability to generate capital gains in the future. Discontinued operations for the REG segment in 2002 also includes $38 million in pre-tax earnings associated with operating results from Northern Natural prior to its sale. The CRM pre-tax loss of $51 million ($49 million after-tax) consisted of $115 million in losses associated with the U.K. CRM business offset by $64 million in income from our U.K. natural gas storage assets. The global liquids pre-tax loss of $37 million ($29 million after-tax) included a pre-tax charge of approximately $12 million associated with the impairment of an LPG investment in the global liquids business. The remaining $25 million loss related to the write-off of a logistics and accounting computer system and other costs associated with the wind-down of the business.

The 2001 pre-tax loss of $127 million ($82 million after-tax) consists primarily of $100 million in pre-tax losses from the communications business and $31 million in pre-tax losses associated with the U.K. CRM business.

Cumulative Effect of Change in Accounting Principles

We reflected EITF Issue 02-03’s rescission of EITF Issue 98-10 effective January 1, 2003 as a cumulative effect of a change in accounting principle. The net impact was a pre-tax benefit of $33 million ($21 million after- tax), of which a benefit of $43 million was recognized in our CRM segment and a charge of $10 million was recognized in our GEN segment. We also adopted SFAS No. 143 effective January 1, 2003 and recognized a pre-tax benefit of $54 million ($34 million after-tax) associated with its implementation. The $54 million benefit was split between our GEN ($57 million) and REG ($(3) million) segments. Finally, we adopted certain provisions of FIN No. 46R in the fourth quarter 2003 and recognized a pre-tax charge of $23 million ($15 million after-tax) in our GEN segment related to our CoGen Lyondell facility.

On January 1, 2002, we adopted SFAS No. 142. In connection with its adoption, we realized a cumulative effect loss of approximately $234 million associated with a write-down of goodwill associated with our discontinued communications business.

On January 1, 2001, we adopted SFAS No. 133 and recognized a pre-tax benefit of $3 million ($2 million after-tax) in our CRM segment.

Please read Note 2—Accounting Policies beginning on page F-11 for further discussion of our adoption of recent accounting policies.

Interest Expense

Interest expense totaled $509 million for 2003, compared with $297 million and $255 million for 2002 and 2001, respectively. The significant increase in 2003, as compared to 2002, primarily is attributable to the following:

•

Higher average interest rates on borrowings (approximately $70 million of the increase), including Illinois Power’s new mortgage bonds and the new notes issued in connection with our August 2003 refinancing;

•

Interest expense for 2002 does not include approximately $65 million of interest expense which was allocated to our discontinued businesses;

•

Higher average principal balances in the 2003 period (approximately $30 million of the increase);

•

Increased amortization of debt issuance costs (approximately $35 million of the increase, of which approximately $24 million relates to accelerated amortization of previously incurred financing costs and the settlement value of the associated interest rate hedge instruments); and

•

Higher letter of credit fees (approximately $15 million of the increase). The higher letter of credit fees resulted from the restructuring of our credit facility in April 2003, with respect to which such fees are higher than those contained in our previous facility.

The increase in interest expense in 2002 compared to 2001 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.

Income Tax (Provision) Benefit

We reported an income tax benefit from continuing operations of $246 million in 2003, compared to an income tax benefit from continuing operations of $352 million in 2002 and an income tax provision from continuing operations of $368 million in 2001. These amounts reflect effective rates of 26%, 23% and 43%, respectively. The 2003 and 2002 effective rates were impacted significantly by the $311 million goodwill impairment relating to the REG segment in 2003 and the $814 million goodwill impairment relating the CRM and GEN segments in 2002. As there was no tax basis in the goodwill impaired in 2003 or $579 million of the goodwill impaired in 2002, there were no tax benefits associated with the charges. Additionally, the 2003 tax benefit includes a $33 million reduction in a valuation allowance associated with our capital loss carryforward as a result of capital gains recognized in 2003 or anticipated to be recognized in early 2004 related to various dispositions. Excluding these items from the 2003 and 2002 calculations would result in effective tax rates of 34% in 2003 and 37% in 2002, compared to the 2001 effective tax rate of 43%. In general, differences between these adjusted effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences.

Please see Note 14—Income Taxes beginning on page F-50 for further discussion of our income taxes.

2004 Outlook

The following summarizes our 2004 outlook for our four reportable segments.

GEN Outlook. We expect that this segment’s financial results will continue to reflect a sensitivity to power prices and that the 2004 pricing environment will be similar to what we experienced in 2003. We will continue our efforts to manage price risk through the optimization of fuel procurement and the marketing of power generated from our assets. Our sensitivity to prices and our ability to manage this sensitivity is subject to a

number of factors, including general market liquidity, particularly in forward years, our ability to provide necessary collateral support and the willingness of counterparties to transact business with us given our non-investment grade credit ratings.

As discussed in Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Original Filing, we enter into sales of capacity from our generation assets, which provide a revenue stream independent of energy sales. In late 2003 and continuing into 2004, we have seen increases in the market for capacity-related products from our peaking and intermediate generation facilities.

At the beginning of 2004, a substantial portion of our 2004 operating margin was under contract or hedged. The primary contracts included the CDWR contract held by West Coast Power and the Illinois Power power purchase agreement. Our future results of operations will be significantly impacted by our ability to extend or renew these agreements. West Coast Power, whose equity earnings are primarily derived from the CDWR contract, has been our largest contributor in terms of earnings from unconsolidated investments. The scheduled expiration of the CDWR contract in December 2004 will negatively impact the fair value of our investment in West Coast Power. As the value of the CDWR contract is realized through 2004, its fair value will decline, and, accordingly, we anticipate that the remaining value of the investment will be less than its book value. As a result, we will evaluate our investment quarterly and anticipate such reviews will necessitate an impairment of our investment of approximately $70 to $80 million in 2004. Please read Note 17—Commitments and Contingencies—Summary of Material Legal Proceedings—Western Long-Term Contract Complaints beginning on page F-61 for further discussion of the legal challenges to the CDWR contract.

Our power purchase agreement with Illinois Power is scheduled to expire at the end of 2004. In connection with the sale of Illinois Power to Ameren, DPM has agreed, conditioned on the closing of the sale, to enter into a two-year power purchase agreement with Ameren with volumes comparable to our current agreement. If we are unable to complete the sale of Illinois Power, any new agreement between Illinois Power and another Dynegy affiliate may not be executed at the same rates as our existing agreement. Please read “—REG Outlook” below for further discussion of the power purchase agreement. Please also read Note 23—Subsequent Event beginning on page F-86 for further discussion of the pending sale of Illinois Power.

The current power purchase agreement between DMG and Illinois Power requires that notice of termination be presented by December 31, 2003, one year prior to the scheduled expiration. The parties have agreed to amend the agreement to extend this notice date requirement to March 31, 2004.

We continue to pursue additional sales of our ownership interests in a number of domestic and international generating projects that we consider non-strategic to this business. We recently executed purchase and sale agreements for our interests in Oyster Creek and Michigan Power and are continuing to pursue sales of our interests in Commonwealth, Black Mountain and Hartwell. We hold ownership interests of 50% or less in these projects, which aggregate less than 600 MWs of net generating capacity. These investments contributed approximately $26 million to our results in 2003. Please read Note 9—Unconsolidated Investments—GEN Investments beginning on page F-35 for further discussion of these investments. Additionally, the pending transaction with Ameren includes the transfer of our 20% interest in the Joppa facility, which contributed approximately $2 million in earnings from unconsolidated investments in 2003. Our ability to consummate these sales on the terms and within the timeframes we anticipate is subject to several factors, many of which are beyond our control.

NGL Outlook. We expect that this segment’s financial results will continue to reflect a sensitivity to natural gas and natural gas liquids prices and that the 2004 pricing environment will be similar to what we experienced in 2003. Our upstream volumes under POP and POL contracts will continue to benefit from these relatively higher prices. However, natural gas liquids production from both our own and third-party natural gas processing plants that are exposed to KW economics will continue to be exposed to depressed frac spreads, as natural gas

continues to be higher in value than natural gas liquids on a Btu basis. As a result, we expect a reduced natural gas liquids supply to our fractionation, storage and distribution infrastructure, similar to 2003.

In some brief periods during 2003, the frac spread increased to a level sufficient to support natural gas liquids extraction, but not enough to generate meaningful upstream margin improvement. We expect this to occur during 2004. The increased natural gas liquids volumes produced during these brief periods resulted in some incremental margins in our downstream operations.

Drilling rig rates for natural gas throughout our core processing areas in New Mexico, West Texas, North Texas and offshore Louisiana continue to increase, consistent with natural gas prices that have averaged $5-$6/MMBtu. Continued exploration and production at these levels will benefit our upstream business by providing additional volumes for gathering and processing. If natural gas prices were to decline in the future, resulting in reduced drilling activities, this segment’s results could be adversely affected.

While we have not experienced significant turnover in customer contracts as a result of our non-investment grade credit ratings, we have been required to provide collateral or other adequate assurance of our obligations for many of our commercial relationships. We expect similar collateral requirements until such time as our credit ratings improve substantially. Our ability to hedge future natural gas liquids production during 2004 will again be limited by reduced market liquidity, our obligation to post collateral and significant backwardation of natural gas liquids prices.

We intend to continue our aggressive North Texas gathering system expansion, where additional compression and plant debottlenecking are expected to add volumes to our expanded Chico gas processing plant. We expect to see volume growth in this area of 24% in 2004.

We also intend to continue to review our asset portfolio to maximize our return on investment. We have identified a few assets where our interests are not aligned with our partners. We may pursue sales of one or more of these assets if the price is sufficient to mitigate the anticipated impact on future earnings. Please see “—Liquidity and Capital Resources—External Liquidity Sources—Asset Sale Proceeds” beginning on page 18 for further discussion.

REG Outlook. Future results of operations for the REG segment may be affected, either positively or negatively, by regulatory actions (with respect to rates or otherwise), general economic conditions, weather and customers choosing to utilize competitive alternate service providers. The effects of the REG segment on our consolidated results of operations will be significantly impacted by our ability to consummate the pending sale of Illinois Power to Ameren. Please read Note 23—Subsequent Event beginning on page F-86 for further discussion of this pending transaction.

We expect 2004 operating income, excluding depreciation, amortization, general and administrative expenses and the impairment of goodwill, to be similar to actual results for 2003. Cash flow from operations is expected to be higher in 2004 than in 2003 as a result of the delayed recovery of gas inventories in 2003 and higher prepaid gas costs from our customers in 2003 as compared to our 2004 expectations.

Illinois Power’s ability to meet its capacity and energy needs beyond 2004 is addressed in connection with the pending sale of Illinois Power to Ameren. Pursuant to a related agreement, which is conditioned upon the closing of the transaction, Illinois Power will purchase 2,800 MWs of capacity and up to 11.5 million MWh of energy from DPM at fixed prices for two years beginning in January 2005. Additionally, DPM will sell 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to Illinois Power at a fixed price with an option to purchase energy at market-based prices. Any capacity and energy needs not met by this agreement would be secured from either existing agreements, through a specified competitive purchasing process, or, in limited circumstances, through open market purchases.

In the event that both the pending transaction for the sale of Illinois Power to Ameren is not completed, the existing agreement with DMG is terminated and no replacement agreement is executed with a Dynegy affiliate, Illinois Power will be required to purchase a substantial portion of its power on the open market at then current market prices. In the event that the Ameren transaction is not completed and the existing agreement with DMG is either not terminated or is replaced by another agreement with a Dynegy affiliate, Illinois Power will be required to purchase any amount of capacity and energy not provided under the contract on the open market at then current market prices. Volatility in market prices for power could affect Illinois Power to the extent that it would be required to purchase power in the open market.

CRM Outlook. Our CRM business’ future results of operations will be significantly impacted by our ability to execute our exit strategy. We continue to explore opportunities to assign or renegotiate the terms of some of our four remaining power tolling arrangements. If we do not renegotiate or terminate these power tolling arrangements, these arrangements will continue to negatively impact our earnings and cash flows based on the current pricing environment. Even if we do renegotiate or terminate some of these arrangements, we could be required to pay a significant amount of cash relating to any such renegotiation or termination which may also negatively impact earnings and cash flows. For a discussion of our annual and long-term obligations under these arrangements, see Item 1. Business—Segment Discussion—Customer Risk Management beginning on page 18 of our Original Filing.

The earnings of the CRM segment may also be significantly impacted, either positively or negatively, by mark-to-market changes in the value of a derivative contract associated with the Sithe Independence tolling agreement as power and gas prices change.

We have posted approximately $120 million of collateral associated with this business. Approximately $20 million of this balance relates to our tolling arrangements. An additional $40 million relates to the ABG Gas Supply gas contract, which will expire in the first quarter of 2006. The remaining $60 million is related to our legacy gas and power positions, which collateral will be substantially eliminated by 2007.

CASH FLOW DISCLOSURES

The following tables include data from the operating section of the consolidated statements of cash flows and include cash flows from our discontinued operations, which are disclosed on a net basis in loss on discontinued operations, net of tax, in the consolidated statements of operations:


	For the Year Ended December 31, 2003
	GEN			NGL			REG			CRM			Other & Eliminations			Consolidated
	(in millions)
Operating Cash Flows Before Changes in Working Capital	$	457		$	233		$	198		$	(29	)	$	(420	)	$	439
Changes in Working Capital		(29	)		(47	)		(131	)		525			119			437

Net Cash Provided by (Used in) Operating Activities	$	428		$	186		$	67		$	496		$	(301	)	$	876


	For the Year Ended December 31, 2002
	GEN			NGL			REG			CRM			Other & Eliminations			Consolidated
	(in millions)
Operating Cash Flows Before Changes in Working Capital	$	349		$	73		$	371		$	200		$	(124	)	$	869
Changes in Working Capital		(91	)		(49	)		(109	)		(518	)		(127	)		(894	)

Net Cash Provided by (Used in) Operating Activities	$	258		$	24		$	262		$	(318	)	$	(251	)	$	(25	)


	For the Year Ended December 31, 2001
	GEN		NGL		REG			CRM			Other & Eliminations		Consolidated
	(in millions)
Operating Cash Flows Before Changes in Working Capital	$	431	$	147	$	269		$	180		$	43	$	1,070
Changes in Working Capital		71		12		(160	)		(476	)		33		(520	)

Net Cash Provided by (Used in) Operating Activities	$	502	$	159	$	109		$	(296	)	$	76	$	550

Operating Cash Flow. Our cash flow provided by operations totaled $876 million for the 12 months ended December 31, 2003. Cash provided in 2003 primarily relates to collateral returns, settlements of risk management assets and sales of natural gas storage in excess of $500 million from our CRM business, a $110 million income tax refund and solid operational performances from our GEN, NGL and REG segments. Despite a relatively weak commodity price environment, our GEN segment provided cash flows in excess of $400 million largely due to effective commercial and operational management and our coal- and dual-fired generation assets. Similarly, our NGL segment contributed cash flows from operations in excess of $180 million due to a strong commodity price environment, particularly in the upstream business, offset by increases in prepayments and lower downstream results due to industry-wide reductions in volumes available for fractionation. Our REG segment contributed operating cash flows in excess of $60 million, primarily from normal operating conditions, offset by working capital outflows due to increased injection of gas into storage, as well as an increase in prepayments. General and administrative costs, a $45 million litigation settlement and continued extinguishment of liabilities during our exit from our communications business offset these positive operational cash flows during the 12 months ended December 31, 2003.

For the 12 months ended December 31, 2002, our cash flow used in operations was $25 million. When compared to 2003, the primary driver of our operating cash outflows was our required posting during 2002 of significant amounts of collateral under the terms of our CRM commercial contracts due to the degradation of our credit ratings.

For the 12 months ended December 31, 2001, our cash flow provided by operations totaled $550 million. Our GEN segment experienced strong operational results, reflecting added generation capacity and a favorable commodity price environment, which contributed operating cash flows of approximately $500 million. Similarly, our NGL segment experienced strong operational results stemming from beneficial price realization and positive working capital changes related to sales of natural gas liquids in storage due to the favorable business environment.

Capital Expenditures and Investing Activities. Cash used in investing activities for the 12 months ended December 31, 2003 totaled $266 million. Our capital spending totaled $333 million and was primarily comprised of routine capital maintenance of our existing asset base. Of this amount, we spent approximately $40 million on the construction of Rolling Hills, which began commercial operations in June 2003. Our proceeds from asset sales totaled approximately $72 million and primarily relate to our sale of Hackberry LNG Terminal LLC ($35 million), SouthStar ($20 million), and generation equity investments ($25 million), which were offset by $10 million in cash outflows associated with the sale of our European communications business.

During the 12 months ended December 31, 2002, cash provided by investing activities totaled $677 million. Our capital spending totaled $947 million and was primarily comprised of improvements to the existing asset base. Of this amount, we spent approximately $195 million on the construction of Rolling Hills. Additionally, we spent $83 million on our discontinued communications business and incurred $54 million in capital expenditures associated with information technology. Business acquisitions of $20 million relate to our acquisition of Northern Natural, net of cash acquired. We received $1.5 billion in proceeds from asset sales primarily from the sales of Northern Natural in August 2002 ($879 million), the Hornsea gas storage facility in September 2002 ($189 million) and the Rough gas storage facility in November 2002 ($500 million). Other investing activities include proceeds from the sale of Northern Natural bonds.

Finally, cash used in investing activities in 2001 totaled $3.8 billion. Included in 2001 capital expenditures is the purchase of the Central Hudson power generation facilities for $903 million. Additional capital expenditures of approximately $1.7 billion principally related to the construction of power generation assets, improvements of existing facilities related to the REG segment and investments associated with technology infrastructure. Also during 2001, we invested $1.5 billion on our purchase of Northern Natural Series A Preferred Stock. Business acquisitions during 2001 included approximately $595 million related to the purchase of BGSL and approximately $40 million related to our purchase of iaxis. Proceeds from asset sales in 2001 included the sale of the Central Hudson facilities in May 2001 for $920 million pursuant to a leveraged lease transaction, in addition to proceeds from the disposal of non-strategic Canadian assets and investments. Other investing activities in 2001 primarily include investments relating to a generation and a telecommunications lease arrangement.

Financing Activities. During 2003, cash used for financing activities totaled $900 million. The following summarizes significant items:

•

Repayments of $128 million, net, under our revolving credit facilities.

•

Long-term debt proceeds, net of issuance costs, for 2003 totaled $2.2 billion and consisted of: (1) $311 million associated with the October 2003 follow-on notes offering; (2) $1,607 million associated with the August 2003 refinancing, (3) $142 million from the delayed issuance of $150 million in Illinois Power 11.5% Mortgage Bonds due 2010 and (4) $159 million from the Term A loan drawn in connection with the April 2, 2003 credit facility restructuring.

•

In connection with the August 2003 refinancing, we made a $225 million cash payment to ChevronTexaco.

•

Repayments of long-term debt totaled $2.7 billion for 2003 and consisted of: (1) $696 million prepayment of the outstanding balance under the Black Thunder financing; (2) $609 million purchase of DHI’s previously outstanding 2005/2006 public notes; (3) $360 million prepayment of the Term B loan outstanding under DHI’s restructured credit facility; (4) $200 million prepayment of the Term A loan outstanding under DHI’s restructured credit facility; (5) $200 million in payments under the Renaissance and Rolling Hills interim financing; (6) $190 million in payments of Illinois Power mortgage bond maturities; (7) $100 million payment on Illinois Power’s term loan; (8) $165 million payment in full for the Generation facility capital lease; (9) $86 million in payments on Illinois Power’s transitional funding trust notes; (10) $74 million in payments under the ABG Gas Supply credit agreement; (11) $62 million in payments under the Black Thunder secured financing prior to its prepayment; (12) $5 million purchase of Illinova senior notes on the open market; and (13) $2 million in payments on the Junior Notes.

•

Distributions to minority interest owners totaling $21 million.

During 2002, cash used for financing activities totaled $44 million. The following summarizes significant items:

•

Net long-term debt proceeds consisted primarily of the February 2002 issuance by DHI of $500 million of 8.75% senior notes due February 2012, the December 2002 issuance by Illinois Power of $400 million of 11.5% Mortgage bonds due 2010 and proceeds from the ABG Gas Supply credit agreement;

•

Repayments of long-term borrowings consisted of: (1) $88 million in transitional funding notes relating to Illinois Power; (2) $90 million relating to the April 2002 purchase of Northern Natural’s senior unsecured notes due 2005; (3) $92 million in principal payments related to the Black Thunder financing; (4) $200 million relating to the July 2002 DHI 6.875% senior note repayment; (5) $96 million relating to the July 2002 Illinois Power mortgage bond repayment; and (6) $59 million in repayments under the ABG Gas Supply credit agreement;

•

In July 2002, we completed a $200 million interim financing secured by interests in our Renaissance and Rolling Hills merchant power generation facilities. In June 2002, we completed a $250 million interim financing representing an advance on a portion of the proceeds from the sale of our U.K. natural gas storage facilities. In September 2002, we sold the entity that owned the Hornsea storage facility, and, in October 2002, we repaid approximately $189 million of this interim financing with the proceeds. In November 2002, we sold the entities that owned the Rough facilities and repaid the remaining balance of this financing with a portion of the proceeds therefrom;

•

Repayments of commercial paper borrowings and revolving credit facilities of Dynegy and DHI totaled approximately $614 million in the aggregate and borrowings totaled an aggregate of approximately $136 million under the Dynegy and DHI revolving credit facilities. During the same period, repayments of commercial paper borrowings and revolving credit facilities for Illinois Power totaled approximately $238 million;

•

Proceeds from the sale of capital stock totaled $205 million related to ChevronTexaco’s January 2002 purchase of approximately 10.4 million shares of Class B common stock pursuant to its preemptive rights under our shareholder agreement. Capital stock proceeds also include $24 million of cash inflows associated with cash received from senior management associated with a December 2001 private placement of shares of our Class A common stock;

•

In March 2002, Illinova consummated a tender offer pursuant to which it paid $28 million in cash for approximately 73% of the then-outstanding shares of Illinois Power’s preferred stock; and

•

We made dividend payments of $40 million to the holders of Class A common stock and $15 million to the holder of Class B common stock.

During 2001, cash provided by financing activities totaled approximately $3.5 billion. The following summarizes the significant items:

•

Proceeds from long-term borrowings consisted primarily of (1) the issuance of $496 million of 6.875% Senior Notes due April 1, 2011, net of issuance costs. Such proceeds were used to repay credit facility borrowings obtained to finance the purchase of the Central Hudson generation facilities; (2) $282 million associated with the ABG Gas Supply credit agreement; (3) the issuance of $187 million of variable rate pollution control bonds by Illinois Power; and (4) proceeds from lease arrangements of approximately $340 million, which were used in the construction of two generation facilities and the U.S. fiber optic network;

•

Repayments of long-term debt include $187 million of variable rate pollution control bonds, which were repaid and retired contemporaneously with the issuance of lower rate bonds discussed above, $87 million of transitional funding trust notes and $30 million of Illinova’s medium term notes;

•

Proceeds from the sale of capital stock and from options and 401(k) plans approximated $604 million. We sold approximately 29.8 million shares of common stock during 2001. The offerings included approximately 27.5 million shares of Class A common stock sold to the public in December 2001. We also sold approximately 1.2 million shares of Class B common stock to ChevronTexaco in private transactions pursuant to the exercise of ChevronTexaco’s preemptive rights. This amount is net of underwriting commissions and expenses of approximately $32 million;

•

Proceeds of $1.5 billion relate to the sale of 150,000 shares of Series B Preferred Stock to ChevronTexaco, concurrent with Dynegy’s purchase of Northern Natural Series A Preferred Stock;

•

We repurchased approximately 1.7 million shares of our outstanding Class A common stock pursuant to our stock repurchase plan at a cost of $68 million;

•

Illinois Power redeemed $100 million of Trust Originated Preferred Securities issued by Illinois Power Financing I. The redemption was financed with $85 million from cash on hand and $15 million in commercial paper; and

•

We made payments of dividends and other distributions totaling $98 million.

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 power, natural gas, and natural gas liquids. Power marketing operations and generating facilities have higher volatility and demand, respectively, in the summer cooling months, while the regulated energy delivery 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 impacting both volumes and prices.

CRITICAL ACCOUNTING POLICIES

Our Controller’s Department is responsible for the development and application of accounting policy and control procedures. This department conducts these activities independent of any active management of our risk exposures, is independent of our business segments 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:

•

Revenue Recognition;

•

Valuation of Tangible and Intangible Assets;

•

Estimated Useful Lives;

•

Accounting for Contingencies;

•

Accounting for Income Taxes; and

•

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, 2003, except as required by the adoption of EITF Issue 02-03, which rescinded EITF Issue 98-10.

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. We recognize revenue from these transactions when the product or service is delivered to a customer.

The fair value model has historically been used to account for forward physical and financial transactions, primarily in the CRM and GEN 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 or the equivalent, 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 and price. The estimated prices in this valuation are based either on (1) prices obtained from market quotes, when there are an adequate number of quotes to consider the period liquid, or, if market quotes are unavailable, or the market is not considered to be liquid, (2) prices from a proprietary model which incorporates forward energy prices derived from market quotes and values from executed transactions. The amounts recorded as revenue change as these estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control.

Under SFAS No. 133, as amended, derivative contracts can be accounted for in three different ways: (1) as an accrual contract, if the criteria for the “normal purchase normal sale” exemption are met and documented; (2) as a cash flow or fair value hedge, if the criteria are met and documented; or (3) as a mark-to-market contract with changes in fair value recognized in current period earnings. Generally, we only mark-to-market through earnings our derivative contracts if they do not qualify for the “normal purchase normal sale” exemption or as a cash flow hedge. Because derivative contracts can be accounted for in three different ways, as the “normal purchase normal sale” exemption and cash flow hedge accounting are elective, the accounting treatment used by another party for a similar transaction could be different than the accounting treatment we use.

Valuation of Tangible and Intangible Assets

We evaluate long-lived assets, such as property, plant and equipment, investments and goodwill, when events or changes in circumstances lead to a reduction in the estimated useful lives or estimated future cash flows sufficient to indicate that the carrying value of such assets may not be recoverable. Factors we consider important, which could trigger an impairment analysis, include, among others:

•

significant underperformance relative to historical or projected future operating results;

•

significant changes in the manner of our use of the assets or the strategy for our overall business;

•

significant negative industry or economic trends; and

•

significant declines in stock value for a sustained period.

We assess the carrying value of our property, plant and equipment in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” If a long-lived asset is held and used, the determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment loss recognized would be determined by estimating the fair value of the assets and recording a loss if the fair value is less than the book value. For assets identified as held for sale, the book value is compared to the estimated fair value to determine if an impairment loss is required.

We follow the guidance of APB 18, “The Equity Method of Accounting for Investments in Common Stock,” and SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” when reviewing our investments. The book value of the investment is compared to the estimated fair value, based either on discounted cash flow projections or quoted market prices, if available, to determine if an impairment is required. We record a loss when the decline in value is considered other than temporary. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets,” when assessing the carrying value of our goodwill. Accordingly, we evaluate our goodwill for impairment on an annual basis or when events warrant an assessment. Fair value utilized in this assessment is also based on our estimate of future cash flows.

Our assessment regarding the existence of impairment factors is based on market conditions, operational performance and legal factors impacting our businesses. Our review of factors present and the resulting estimation of the appropriate carrying value of our property, plant and equipment, investments and goodwill are subject to judgments and estimates that management is required to make. Our fair value estimates are impacted significantly by the estimated useful lives of the assets, commodity prices, regulations and discount rate assumptions. If different judgments were applied to fair value calculations, the fair value estimate, and potential resulting impairment, could differ from our estimate. Actual results could vary materially from these estimates.

Estimated Useful Lives

The estimated useful lives of our long-lived assets are used to compute depreciation expense and are also used for impairment testing. Estimated useful lives are based on the assumption that we provide an appropriate level of capital expenditures while the assets are still in operation. Without these continued capital expenditures, the useful lives of these assets could decrease significantly. These estimates could be impacted by future energy prices, environmental regulations and competition. If the useful lives of these assets were found to be shorter than originally estimated, depreciation charges would be accelerated.

Accounting for Contingencies

We are involved in numerous lawsuits, claims, proceedings, joint venture audits and tax-related audits in the normal course of our operations. In accordance with SFAS No. 5, we record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded on the balance sheet. These reserves are based on judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage for litigation matters, and are adjusted as circumstances warrant. Our judgment could change based on new information, changes in laws or regulations, changes in management’s plans or intentions, the outcome of legal proceedings, settlements or other factors. If different judgments were applied with respect to these matters, it is likely that reserves would be recorded for different amounts.

Liabilities are recorded when environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability. Any changes in assumptions could lead to increases or decreases in our ultimate liability, with any such changes recognized immediately in earnings.

Under the provisions of SFAS No. 143, “Asset Retirement Obligations,” we are required to record legal obligations to retire tangible, long-lived assets on our balance sheet as liabilities, which are recorded at a discount, when the liability is incurred. Significant judgment is involved in estimating our future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. If our estimates on the amount or timing of the cash flow change, the change is recognized immediately in earnings.

Accounting for Income Taxes

We follow the guidance in SFAS No. 109, “Accounting for Income Taxes,” which requires that we use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant temporary differences. Please read Note 14—Income Taxes beginning on page F-50 for further discussion.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, for tax and accounting purposes. These differences result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.

We must then assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that it is more likely than not (a likelihood of more than 50%) that some portion or all of the deferred tax assets will not be realized, we must establish a valuation allowance. We consider all available evidence, both positive and negative, to determine whether, based on the weight of the evidence, a

valuation allowance is needed. Evidence used includes information about our current financial position and our results of operations for the current and preceding years, as well as all currently available information about future years, including our anticipated future performance, the reversal of deferred tax liabilities and tax planning strategies. To the extent we establish a valuation allowance or increase or decrease this allowance in a period, we must include an expense or benefit within the tax provisions in the consolidated statements of operations. Significant management judgment is required in determining any valuation allowance recorded against our deferred tax assets.

We have recorded deferred tax assets principally resulting from net operating losses, AMT credits and capital losses. As of December 31, 2003 and 2002, deferred tax assets related to net operating losses totaled $543 million and $246 million, respectively. As of December 31, 2003 and 2002, deferred tax assets related to AMT credits totaled $218 million. We have not established a valuation allowance against these net operating losses or AMT credits, as we believe that it is more likely than not that these deferred tax assets will be realized. We expect that future sources of taxable income, including the sale of Illinois Power, reversing temporary differences and other tax planning strategies will be sufficient to realize these assets. While we have considered these factors in assessing the need for a valuation allowance, there is no assurance that a valuation allowance would not need to be established in the future if information about future years change. Any change in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made.

As of December 31, 2003 and 2002, deferred tax assets related to capital losses totaled $194 million and $223 million, respectively, and valuation allowances recorded related to these losses totaled $135 million and $171 million, respectively. In 2003, we reduced the valuation allowance by $33 million based on capital gains recognized in 2003 or anticipated to be recognized in early 2004 related to various dispositions, excluding our sale of our interest in Joppa, which is subject to regulatory approval. Any changes in the valuation allowance would impact our income tax provision and net income in the period in which such a determination is made. Please see Note 14—Income Taxes beginning on page F-50 for a discussion of the change in our valuation allowance.

Valuation of Pension Assets and Liabilities

Our pension and post-retirement benefit costs are developed from actuarial valuations. Inherent in these valuations are key assumptions provided by us to our actuaries, including the discount rate and expected long-term rate of return on plan assets. Material changes in our pension and post-retirement benefit costs may occur in the future due to changes in these assumptions, changes in the number of plan participants and changes in the level of benefits provided.

The discount rate is subject to change each year, consistent with changes in applicable high-quality, long-term corporate bond indices. Long-term interest rates declined during 2003. Accordingly, at December 31, 2003, we used a discount rate of 6.0%, a decline of 50 basis points from the 6.5% rate used as of December 31, 2002. This decline in the discount rate had the impact of increasing the underfunded status of our pension plans by approximately $44 million.

The expected long-term rate of return on pension plan assets is selected by taking into account the expected duration of the projected benefit obligation for the plans, the asset mix of the plans and the fact that the plan assets are actively managed to mitigate downside risk. Based on these factors, our expected long-term rate of return as of January 1, 2004 is 8.75%, compared with 9.00% during 2003. This change did not impact 2003 pension expense, but it will adversely impact pension expense beginning in 2004. We expect the decrease in this assumption, coupled with the decreased discount rate discussed above and the passage of time, will increase 2004 pension expense by approximately $15 million over 2003 expense.

On December 31, 2003, our annual measurement date, the accumulated benefit obligation related to our pension plans exceeded the fair value of the pension plan assets (such excess is referred to as an unfunded

accumulated benefit obligation). This difference is attributed to (1) an increase in the accumulated benefit obligation that resulted from the decrease in the discount rate and the expected long-term rate of return and (2) a decline in the fair value of the plan assets due to a sharp decrease in the equity markets through December 31, 2002, which was partially recovered during 2003. As a result, in accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” as of December 31, 2003, we have recognized a charge to accumulated other comprehensive loss of $57 million (net of taxes of $33 million), which decreases stockholders’ equity. The charge to stockholders’ equity for the excess of additional pension liability over the unrecognized prior service cost represents a net loss not yet recognized as pension expense.

The following table summarizes the sensitivity of pension expense and our projected benefit obligation, or PBO, to changes in the discount rate and the expected long-term rate of return on pension assets:


	Impact on PBO, December 31, 2004			Impact on 2004 Expense
	(in millions)
Increase Discount Rate 50 basis points	$	(58.5	)	$	(5.3	)
Decrease Discount Rate 50 basis points		64.6			5.7
Increase Expected Rate of Return 50 basis points		—			(3.2	)
Decrease Expected Rate of Return 50 basis points		—			3.2

We expect to make $8 million in cash contribution related to our pension plans during 2004. In addition, it is likely that we will be required to continue to make contributions to the pension plan beyond 2004. Although it is difficult to estimate these potential future cash requirements due to uncertain market conditions, we currently expect that the cash requirements would be approximately $57 million in 2005 and $46 million in 2006.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 2—Accounting Policies—Accounting Principles Adopted beginning on page F-19 for a discussion of recently issued accounting pronouncements affecting us. Specifically, we adopted the net presentation provisions of EITF Issue 02-03 in the third quarter 2002 and we adopted the provision within EITF Issue 02-03 that rescinds EITF Issue 98-10 effective January 1, 2003. We also adopted SFAS No. 143 effective January 1, 2003. We adopted SFAS No. 150 and EITF Issue 03-11 effective July 1, 2003. We adopted portions of FIN 46R, as required by GAAP, effective December 31, 2003.

RISK-MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk-management data on the consolidated balance sheets, statements of operations and statements of cash flows:


	As of and for the Year Ended December 31, 2003
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2003	$	363
Risk-management losses recognized through the income statement in the period, net (1)		(184	)
Cash received related to risk-management contracts settled in the period, net (2)		(260	)
Changes in fair value as a result of a change in valuation technique (3)		—
Non-cash adjustments and other (4)		(56	)

Fair value of portfolio at December 31, 2003	$	(137	)

Income Statement Reconciliation
Risk-management losses recognized through the income statement in the period, net (1)	$	(184	)
Physical business recognized through the income statement in the period, net (5)		(130	)
Non-cash adjustments and other		5

Net recognized operating loss	$	(309	)

Cash Flow Statement
Cash received related to risk-management contracts settled in the period, net (2)	$	260
Estimated cash paid related to physical business settled in the period, net (5)		(130	)
Timing and other, net (6)		(57	)

Cash received during the period	$	73

Risk-Management cash flow adjustment for the year ended December 31, 2003 (7)	$	382

(1)	This amount consists primarily of $121 million in mark-to-market losses on contracts associated with the Sithe Independence power tolling arrangement and a $30 million loss associated with the settlement of power supply agreements with Kroger.

(2)	This amount consists primarily of the Kroger settlement of approximately $110 million and cash received due to the wind-down of our CRM business.

(3)	Our modeling methodology has been consistently applied.

(4)

This amount primarily consists of approximately $97 million of risk-management assets that were removed from the risk-management accounts at January 1, 2003 in conjunction with the adoption of certain provisions of EITF Issue 02-03. This amount is offset primarily by changes in value associated with cash flow hedges.

(5)	This amount consists primarily of capacity payments on our power tolling arrangements.

(6)	This amount consists primarily of cash paid in connection with the settlement of cash flow hedges.

(7)	This amount is calculated as “Cash received during the period” less “Net recognized operating loss.”

The net risk management liability of $137 million is the aggregate of the following line items on the consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures

The following table depicts the mark-to-market value and cash flow components, based on contract terms, of our net risk-management assets and liabilities at December 31, 2003. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below.

Net Risk-Management Asset and Liability Disclosures


	Total			2004			2005			2006			2007			2008			Thereafter
	(in millions)
Mark-to-Market (1)	$	(144	)	$	(22	)	$	(17	)	$	(25	)	$	(39	)	$	(12	)	$	(29	)
Cash Flow (2)		(152	)		(17	)		(14	)		(24	)		(43	)		(15	)		(39	)

(1)

Mark-to-market reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management liabilities at December 31, 2003 of $137 million on the consolidated balance sheets includes the $144 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2)

Cash Flow reflects undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges.

The following table provides an assessment of net contract values by year as of December 31, 2003, based on our valuation methodology.

Net Fair Value of Risk-Management Portfolio


	Total			2004			2005			2006			2007			2008			Thereafter
	(in millions)
Market Quotations (1)	$	(69	)	$	(22	)	$	(20	)	$	—		$	(25	)	$	(1	)	$	(1	)
Prices Based on Models (2)		(75	)		—			3			(25	)		(14	)		(11	)		(28	)

Total	$	(144	)	$	(22	)	$	(17	)	$	(25	)	$	(39	)	$	(12	)	$	(29	)

(1)	Prices obtained from actively traded, liquid markets for commodities other than natural gas positions. All natural gas positions for all periods are contained in this line based on available market quotations.

(2)	See discussion of our use of long-term models in “Critical Accounting Policies” beginning on page 40.

Derivative Contracts

The absolute notional contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts are discussed in Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 80 of our Original Filing.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-K/A includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements.” All statements included or incorporated by reference in this annual report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “project,” “forecast,” “plan,” “may,” “will,” “should,” “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:

•

projected operating or financial results, include anticipated cash flows from operations and asset sale proceeds for 2004;

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expectations regarding capital expenditures, interest expense and other payments;

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our ability to execute the cost-savings measures we have identified;

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our beliefs and assumptions relating to our liquidity position, including our ability to satisfy or refinance our significant debt maturities and other obligations as they come due, particularly the February 2005 maturity of our $1.1 billion revolving credit facility;

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our ability to address our substantial leverage;

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our ability to compete effectively for market share with industry participants;

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beliefs about the outcome of legal and administrative proceedings, including matters involving the western power and natural gas markets, shareholder claims and environmental and master netting agreement matters, as well as the investigations primarily relating to Project Alpha and our past trading practices;

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our ability to consummate the disposition of specified non-strategic assets on the terms and in the timeframes anticipated, particularly the agreed upon sale of Illinois Power to Ameren; and

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our ability to complete our exit from the CRM business and the costs associated with this exit.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors including, among others:

•

the timing and extent of changes in weather and commodity prices, particularly for power, natural gas, natural gas liquids and other fuels, as such as the frac spread and, to a lesser extent, the natural gas spark spread;

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the effects of competition in our asset-based business lines;

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the effects of the proposed sale of specified non-strategic assets, particularly the agreed upon sale of Illinois Power to Ameren;

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the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions, and our financial condition, including our ability to satisfy our significant debt maturities;

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our ability to realize our significant deferred tax assets, including loss carryforwards;

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the effectiveness of our risk-management policies and procedures and the ability of our counterparties to satisfy their financial commitments;

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the liquidity and competitiveness of wholesale trading markets for energy commodities, particularly natural gas, electricity and natural gas liquids;

•

operational factors affecting the start up or ongoing commercial operations of our power generation, natural gas and natural gas liquids and regulated energy delivery facilities, including catastrophic weather-related damage, regulatory approvals, permit issues, unscheduled blackouts, outages or repairs, unanticipated changes in fuel costs or availability of fuel emission credits, the unavailability of gas transportation and the unavailability of electric transmission service or workforce issues;

•

increased interest expense and the other effects of our 2003 restructuring and refinancing transactions, including the security arrangements and restrictive covenants contained in the related financing agreements;

•

counterparties’ collateral demands and other factors affecting our liquidity position and financial condition;

•

our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) tightly and generate earnings and cash flow from our asset-based businesses in relation to our substantial debt and other obligations;

•

the direct or indirect effects on our business of any further downgrades in our credit ratings (or actions we may take in response to changing credit ratings criteria), including refusal by counterparties to enter into transactions with us and our inability to obtain credit or capital in amounts or on terms that are considered favorable;

•

the costs and other effects of legal and administrative proceedings, settlements, investigations and claims, including legal proceedings related to the western power and natural gas markets, shareholder claims, claims arising out of the CRM business and environmental liabilities that may not be covered by indemnity or insurance, as well as the FERC, U.S. Attorney and other similar investigations primarily surrounding Project Alpha and our past trading practices;

•

other North American regulatory or legislative developments that affect the regulation of the electric utility industry, the demand and pricing for energy generally, increase in the environmental compliance cost for our facilities or that impose liabilities on the owners of such facilities; and

•

general political conditions and developments in the United States and in foreign countries whose affairs affect our asset-based businesses including any extended period of war or conflict.

In addition, there may be other factors that could cause our actual results to be materially different from the results referenced in the forward-looking statements, some of which are included elsewhere in this Form 10-K/A. Many of these factors will be important in determining our actual future results. Consequently, no forward-looking statement can be guaranteed. Our actual future results may vary materially from those expressed or implied in any forward-looking statements.

All forward-looking statements contained in this Form 10-K/A are qualified in their entirety by this cautionary statement. Forward-looking statements speak only as of the date they are made, and we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this Form 10-K/A, except as otherwise required by applicable law.

Item 8. Financial Statements and Supplementary Data

Our financial statements and financial statement schedules are set forth at pages F-1 through F-94 inclusive, found at the end of this annual report, and are incorporated herein by reference.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. Effective as of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of our establishment of a disclosure committee and the various processes carried out under the direction of this committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective at the reasonable assurance level and designed to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal controls over financial reporting (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) identified in connection with the evaluation of our internal controls performed during the fourth quarter 2003 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

During the second and third quarter 2004 we identified deficiencies in our internal controls over financial reporting, including matters relating to system access and system implementation controls, segregation of duties and documentation of controls and procedures and their effective operation and monitoring. We also identified deficiencies in our tax accounting and tax reconciliation controls and processes that make this an area of particular focus. During the third quarter 2004, we determined that adjustments related to our deferred income tax accounts in periods prior to 2004 were required. We identified these deficiencies and promptly brought them to the attention of our audit and compliance committee and independent auditors. Accordingly, in this Form 10-K/A, we have restated our consolidated financial statements. For further information, please see the Explanatory Note beginning on page F-8. We believe we have addressed these tax deficiencies, by taking the following steps to improve our internal controls around our tax accounting and tax reconciliation controls and processes:

•

Increased the levels of review in the preparation of the quarterly and annual tax provision;

•

Formalized processes, procedures and documentation standards; and

•

Restructured our Tax Department to ensure segregation of duties regarding preparation and review of the quarterly and annual tax provision.

Beginning with the year ending December 31, 2004, Section 404 of the Sarbanes-Oxley Act of 2002 requires us to provide an annual internal controls report of management. This report must contain (i) a statement of management’s responsibility for establishing and maintaining adequate internal controls over financial reporting for our company, (ii) a statement identifying the framework used by management to conduct the required evaluation of the effectiveness of our internal controls over financial reporting, (iii) management’s assessment of the effectiveness of our internal controls over financial reporting as of the end of our most recent fiscal year, including a statement as to whether or not our internal controls over financial reporting are effective, and (iv) a statement that our independent auditors have issued an attestation report on management’s assessment of our internal controls over financial reporting. Additionally, Section 404 requires that our independent auditors

attest to and report on management’s assessment of our internal controls over financial reporting. In seeking to achieve compliance with Section 404 within the prescribed period, management formed a steering committee to oversee our efforts to comply with Section 404, engaged outside consultants and adopted and implemented a detailed project work plan to assess the adequacy of our internal controls over financial reporting, remediate any control weaknesses that may be identified, validate through testing that controls are functioning as documented and implement a continuous reporting and improvement process for internal controls over financial reporting.

Additionally, the Public Company Accounting Oversight Board recently adopted very stringent standards governing management’s required evaluation of its internal controls over financial reporting and the independent auditors’ review of those controls and management’s evaluation thereof. These standards will likely result in a significant number of companies, which may include Dynegy, identifying significant deficiencies and/or material weaknesses in their internal controls. Indeed, the items referenced in the preceding paragraphs could preclude our independent auditors from delivering an unqualified opinion on internal controls under Section 404 of Sarbanes-Oxley.

PART IV

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

(a) The following documents, which we have filed with the SEC pursuant to the Securities Exchange Act of 1934, as amended, are by this reference incorporated in and made a part of this annual report:

1. Financial Statements—Our consolidated financial statements are incorporated under Item 8. of this annual report.

2. Financial Statement Schedules—Financial Statement Schedules are incorporated under Item 8. of this annual report.

3. Exhibits—The following instruments and documents are included as exhibits to this annual report. All management contracts or compensation plans or arrangements set forth in such list are marked with a ††.


Exhibit Number		Description
3.1		—Amended and Restated Articles of Incorporation of Dynegy Inc. (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A of Dynegy Inc., File No. 1-15659, filed with the SEC on April 25, 2001).

3.2		—Statement of Resolution Establishing Series of Series C Convertible Preferred Stock of Dynegy Inc. (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

***3.3		—Amended and Restated Bylaws of Dynegy Inc.

4.1		—Indenture, dated as of December 11, 1995, by and among NGC Corporation, the Subsidiary Guarantors named therein and the First National Bank of Chicago, as Trustee (incorporated by reference to exhibits to the Registration Statement on Form S-3 of NGC Corporation, Registration No. 33-97368).

4.2		—First Supplemental Indenture, dated as of August 31, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).

4.3		—Second Supplemental Indenture, dated as of October 11, 1996, by and among NGC Corporation, the Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).

4.4		—Subordinated Debenture Indenture between NGC Corporation and The First National Bank of Chicago, as Debenture Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.5		—Amended and Restated Declaration of Trust among NGC Corporation, Wilmington Trust Company, as Property Trustee and Delaware Trustee, and the Administrative Trustees named therein, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.6		—Series A Capital Securities Guarantee Agreement executed by NGC Corporation and The First National Bank of Chicago, as Guarantee Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).


Exhibit Number		Description
4.7		—Common Securities Guarantee Agreement of NGC Corporation dated as of May 28, 1997 (incorporated by reference to Exhibit 4.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.8		—Registration Rights Agreement, dated as of May 28, 1997, among NGC Corporation, NGC Corporation Capital Trust I, Lehman Brothers, Salomon Brothers Inc. and Smith Barney Inc. (incorporated by reference to Exhibit 4.11 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

4.9		—Fourth Supplemental Indenture among NGC Corporation, Destec Energy, Inc. and The First National Bank of Chicago, as Trustee, dated as of June 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.12 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1997 of NGC Corporation, File No. 1-11156).

4.10		—Fifth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of September 30, 1997, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).

4.11		—Sixth Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of January 5, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).

4.12		—Seventh Supplemental Indenture among NGC Corporation, The Subsidiary Guarantors named therein and The First National Bank of Chicago, as Trustee, dated as of February 20, 1998, supplementing and amending the Indenture dated as of December 11, 1995 (incorporated by reference to Exhibit 4.20 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1997 of NGC Corporation, File No. 1-11156).

4.13		—Indenture, dated as of September 26, 1996, restated as of March 23, 1998, and amended and restated as of March 14, 2001, between Dynegy Holdings Inc. and Bank One Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 of Dynegy Holdings Inc., File No. 0-29311).

4.14		—Exchange and Registration Rights Agreement (Preferred Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.15		—Exchange and Registration Rights Agreement (Notes) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.3 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.16		—Amended and Restated Registration Rights Agreement (Common Stock) dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.17		—Amended and Restated Shareholder Agreement dated August 11, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).


Exhibit Number		Description
4.18		—Indenture dated August 11, 2003 between Dynegy Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.19		—Junior Unsecured Subordinated Note due 2016 in the principal amount of $225,000,000 issued on August 11, 2003 by Dynegy Inc. to Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.7 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.20		—Indenture dated as of August 11, 2003 among Dynegy Holdings Inc., the guarantors named therein, Wilmington Trust Company, as trustee, and Wells Fargo Bank Minnesota, N.A., as collateral trustee, including the form of promissory note for each series of notes issuable pursuant to the Indenture (incorporated by reference to Exhibit 4.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.21		—Indenture dated August 11, 2003 between Dynegy Inc., Dynegy Holdings Inc. and Wilmington Trust Company, as trustee, including the form of debenture issuable pursuant to the Indenture (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.22		—Registration Rights Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein (incorporated by reference to Exhibit 4.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

4.23		—First Supplemental Indenture dated July 25, 2003 to that certain Indenture, dated as of September 26, 1996, between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).

4.24		—Eighth Supplemental Indenture dated July 25, 2003 that certain Indenture, dated as of December 11, 1995, between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).

		There have not been filed or incorporated as exhibits to this annual report, other debt instruments defining the rights of holders of our long-term debt, none of which relates to authorized indebtedness that exceeds 10% of our consolidated assets. We hereby agree to furnish a copy of any such instrument not previously filed to the SEC upon request.

10.1		—Dynegy Inc. Amended and Restated 1991 Stock Option Plan (incorporated by reference to Exhibit 10.3 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). ††

10.2		—Dynegy Inc. 1998 U.K. Stock Option Plan (incorporated by reference to Exhibit 10.4 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). ††

10.3		—Dynegy Inc. Amended and Restated Employee Equity Option Plan (incorporated by reference to Exhibit 10.5 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). ††

10.4		—Dynegy Inc. 1999 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). ††


Exhibit Number		Description
10.5		—Dynegy Inc. 2000 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). ††

10.6		—Dynegy Inc. 2001 Non-Executive Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††

10.7		—Dynegy Inc. 2002 Long Term Incentive Plan (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A of Dynegy Inc., File No. 1-15659, filed with the SEC on April 9, 2002). ††

10.8		—Extant, Inc. Equity Compensation Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-47422). ††

10.9		—Employment Agreement, effective October 23, 2002, between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2002 of Dynegy Inc., File No. 1-11156). ††

10.10		—Employment Agreement, effective February 1, 2000, between Charles L. Watson and Dynegy Inc. (incorporated by reference to Exhibit 10.9 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156)††

10.11		—Employment Agreement, effective February 1, 2000, between Stephen W. Bergstrom and Dynegy Inc. (incorporated by reference to Exhibit 10.10 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). ††

10.12		—Employment Agreement, effective as of September 16, 2002, between R. Blake Young and Dynegy Inc. (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2002 of Dynegy Inc., File No. 1-15659). ††

10.13		—Employment Agreement, effective February 1, 2000, between Alec G. Dreyer and Dynegy Inc. (incorporated by reference to Exhibit 10.15 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2002 of Dynegy Inc., File No. 1-11156). ††

10.14		—Employment Agreement, effective December 2, 2002, between Nick J. Caruso and Dynegy Inc. (incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2002 of Dynegy Inc., File No. 1-11156). ††

***10.15		—Employment Agreement, effective March 11, 2003, between Carol F. Graebner and Dynegy Inc. ††

10.16		—Dynegy Inc. Deferred Compensation Plan for Certain Directors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2000 of Dynegy Inc., File No. 1-15659). ††

10.17		—Dynegy Inc. 401(k) Savings Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 383-76570). ††

***10.18		—Amendment to the Dynegy Inc. 401(K) Savings Plan, effective January 1, 2004. ††

***10.19		—First Amendment to Dynegy Inc. 401(K) Savings Plan, effective February 11, 2002. ††

***10.20		—Second Amendment to Dynegy Inc. 401(K) Savings Plan, effective January 1, 2002. ††

***10.21		—Third Amendment to Dynegy Inc. 401(K) Savings Plan, effective October 1, 2003. ††

10.22		—Dynegy Inc. 401(k) Savings Plan Trust Agreement (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76570). ††

10.23		—Dynegy Inc. Deferred Compensation Plan (incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††

10.24		—Dynegy Inc. Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††

10.25		—Dynegy Inc. Short-Term Executive Stock Purchase Loan Program (incorporated by reference to Exhibit 10.19 to the Annual Report on Form 10-K for the Year Ended December 31, 2001 of Dynegy Inc., File No. 1-15659). ††


Exhibit Number		Description
10.26		—Dynegy Inc. Deferred Compensation Plan for Certain Directors (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659). ††

10.27		—Dynegy Inc. Executive Severance Pay Plan, as amended effective September 30, 2003 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2003 of Dynegy Inc., File No. 1-15659). ††

***10.28		—Second Supplement to the Dynegy Inc. Executive Severance Pay Plan. ††

***10.29		—Dynegy Inc. Mid-Term Incentive Performance Award Program. ††

10.30		— Dynegy Northeast Generation, Inc. Savings Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-111985). ††

***10.31		—Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, effective January 1, 2004. ††

10.32		—Dynegy Inc. Severance Pay Plan, as amended effective September 30, 2003 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 2003 of Dynegy Inc., File No. 1-15659). ††

10.33		—Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower Realty Company, Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to Exhibit 10.69 to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).

10.34		— First Amendment to Lease Agreement entered into on June 12, 1996 between Metropolitan Life Insurance Company and Metropolitan Tower Realty Company, Inc., as landlord, and NGC Corporation, as tenant (incorporated by reference to Exhibit 10.70 to the Registration Statement on Form S-4 of Midstream Combination Corp., Registration No. 333-09419).

*10.35		—Master Natural Gas Liquids Purchase Agreement, dated as of September 1, 1996, between Warren Petroleum Company, Limited Partnership and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended September 30, 1996 of NGC Corporation, File No. 1-11156).

10.36		—Dynegy Inc. Severance Pay Plan (incorporated by reference to Exhibit 10.41 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1998 of Dynegy Inc., File No. 1-11156). ††

10.37		—Credit Agreement, dated as of April 1, 2003, among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the lenders party thereto (incorporated by reference to Exhibit 10.31 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).

10.38		—Shared Security Agreement, dated April 1, 2003, among Dynegy Holdings, Inc., various grantors named therein, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.32 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).

10.39		—Non-Shared Security Agreement, dated April 1, 2003, among Dynegy Inc., various grantors named therein and Bank One, N.A. as collateral agent (incorporated by reference to Exhibit 10.33 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).

10.40		—Collateral Trust and Intercreditor Agreement, dated as of April 1, 2003, among Dynegy Holdings Inc., various grantors named therein, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K for the Year Ended December 31, 2002 of Dynegy Inc., File No. 1-15659).


Exhibit Number		Description
10.41		—Third Amendment to the Loan Documents dated as of July 15, 2003 among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the lenders party thereto, including the Lender Consent dated August 1, 2003 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.42		—Fourth Amendment to the Credit Agreement dated as of October 9, 2003 among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, various subsidiary guarantors and the lenders party thereto (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on October 15, 2003, File No. 1-15659).

10.43		—Series B Preferred Stock Exchange Agreement dated as of July 28, 2003 between Dynegy Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.44		—Indemnity Agreement dated August 11, 2003 among Dynegy Inc., Dynegy Holdings Inc. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.45		—Intercreditor Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein, Wilmington Trust Company, as corporate trustee, John M. Beeson, Jr., as individual trustee, Bank One, NA, as collateral agent, and Wells Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.46		—Second Lien Shared Security Agreement dated August 11, 2003 among Dynegy Holdings Inc., various grantors named therein and Wells Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.47		—Second Lien Non-Shared Security Agreement dated August 11, 2003 among Dynegy Inc., various grantors named therein and Wells Fargo Bank Minnesota, N.A., as collateral trustee (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.48		—Purchase Agreement dated August 1, 2003 among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.49		—Purchase Agreement dated August 1, 2003 among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

10.50		—Purchase Agreement dated September 30, 2003 among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 15, 2003, File No. 1-15659).

10.51		— Purchase Agreement dated February 2, 2004 among Dynegy Inc., Illinova Corporation, Illinova Generating Company and Ameren Corporation (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on February 4, 2004, File No. 1-15659).

***14.1		—Dynegy Inc. Code of Ethics for Senior Financial Professionals.

***21.1		—Subsidiaries of the Registrant.


Exhibit Number		Description
**23.1		—Consent of PricewaterhouseCoopers LLP.

**31.1		—Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.2		—Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

†32.1		—Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†32.2		—Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Exhibit omits certain information that we have filed separately with the SEC pursuant to a confidential treatment request pursuant to Rule 406 promulgated under the Securities Act of 1933, as amended.

**	Filed herewith

***	Previously filed

†

Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act.

(b) Reports on Form 8-K of Dynegy Inc. for the fourth quarter of 2003.

1. During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on October 2, 2003. Items 5 and 7 were reported and no financial statements were filed.

2. During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on October 15, 2003. Items 5 and 7 were reported and no financial statements were filed.

3. During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on October 30, 2003. Items 7 and 12 were reported and no financial statements were filed.

4. During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on November 4, 2003. Items 5 and 7 were reported and no financial statements were filed.

5. During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on November 18, 2003. Items 5 and 7 were reported and no financial statements were filed.

6. During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on November 24, 2003. Items 5 and 7 were reported and no final statements were filed.

7. During the quarter ended December 31, 2003, we filed a Current Report on Form 8-K on December 8, 2003. Items 5 and 7 were reported and no final statements were filed.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


	DYNEGY INC.

Date: January 18, 2005	By:	/S/ NICK J. CARUSO
		Nick J. Caruso Executive Vice President and Chief Financial Officer

DYNEGY INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Consolidated Financial Statements (Restated)
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2003 and 2002		F-3
Consolidated Statements of Operations for the years ended December 31, 2003, 2002 and 2001		F-4
Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001		F-5
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2003, 2002 and 2001		F-6
Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2003, 2002 and 2001		F-7
Notes to Consolidated Financial Statements		F-8

Financial Statement Schedules
Schedule I – Parent Company Financial Statements (Restated)		F-90
Schedule II – Valuation and Qualifying Accounts (Restated)		F-94

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Dynegy Inc.:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Dynegy Inc. and its subsidiaries at December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying indexpresent fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedules are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedules based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States), which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 17, the Company is the subject of substantial litigation. The Company’s ongoing liquidity, financial position and operating results may be adversely impacted by the nature, timing and amount of the resolution of such litigation. The consolidated financial statements do not include any adjustments, beyond existing accruals applicable under Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” that might result from the ultimate resolution of such matters.

As discussed in the Explanatory Note beginning on page F-8, the consolidated financial statements have been restated to reflect an increase in the impairment associated with the sale of Illinois Power and for adjustments to the deferred income tax accounts.

As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” as of January 1, 2003. As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting Standards No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity,” as of July 1, 2003. As discussed in Note 2, the Company adopted certain provisions of Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities – an interpretation of ARB 51 (revised December 2003),” as of December 31, 2003. As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting Standards No. 132 (revised 2003), “Employers’ Disclosures About Pensions and Other Postretirement Benefits – an Amendment of FASB Statements No. 87, 88, and 106 and a revision of FASB Statement No. 132,” as of December 31, 2003. As discussed in Note 2, the Company adopted the provisions of Emerging Issues Task Force No. 02-03, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” related to the rescission of Emerging Issues Task Force Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as of January 1, 2003. As discussed in Note 2, the Company adopted the provisions of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” and Statement of Financial Accounting Standards No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” as of January 1, 2002.

PricewaterhouseCoopers LLP

Houston, Texas

February 26, 2004, except for the Explanatory Note beginning on page F-8, as to which the date is January 18, 2005.

F-2

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(RESTATED)

See Explanatory Note

(in millions, except share data)


	December 31, 2003			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	477		$	757
Restricted cash		19			17
Accounts receivable, net of allowance for doubtful accounts of $184 and $151, respectively		1,010			2,791
Accounts receivable, affiliates		25			31
Inventory		279			236
Assets from risk-management activities		818			2,618
Prepayments and other current assets		402			1,136

Total Current Assets		3,030			7,586

Property, Plant and Equipment		9,867			9,659
Accumulated depreciation		(1,664	)		(1,201	)

Property, Plant and Equipment, Net		8,203			8,458
Other Assets
Unconsolidated investments		612			668
Assets from risk-management activities		629			2,529
Goodwill		15			326
Other long-term assets		472			462

Total Assets		12,961			20,029

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	522		$	1,586
Accounts payable, affiliates		74			65
Accrued liabilities and other current liabilities		811			1,818
Liabilities from risk-management activities		838			2,418
Notes payable and current portion of long-term debt		245			861
Current portion of long-term debt to affiliates		86			—

Total Current Liabilities		2,576			6,748

Long-term debt		5,124			5,454
Long-term debt to affiliates		769			—

Total Long-term Debt		5,893			5,454
Other Liabilities
Liabilities from risk-management activities		746			2,366
Deferred income taxes		524			765
Other long-term liabilities		743			924

Total Liabilities		10,482			16,257

Minority Interest		121			146
Commitments and Contingencies (Note 17)
Redeemable Preferred Securities, redemption value of $411 and $1,711 at December 31, 2003 and December 31, 2002, respectively (Note 15)		411			1,423
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at December 31, 2003 and December 31, 2002; 280,350,169 and 274,850,589 shares issued and outstanding at December 31, 2003 and December 31, 2002, respectively		2,848			2,825
Class B Common Stock, no par value, 360,000,000 shares authorized at December 31, 2003 and December 31, 2002; 96,891,014 shares issued and outstanding at December 31, 2003 and December 31, 2002		1,006			1,006
Additional paid-in capital		41			705
Subscriptions receivable		(8	)		(12	)
Accumulated other comprehensive loss, net of tax		(20	)		(55	)
Accumulated deficit		(1,852	)		(2,198	)
Treasury stock, at cost, 1,679,183 shares at December 31, 2003 and December 31, 2002		(68	)		(68	)

Total Stockholders’ Equity		1,947			2,203

Total Liabilities and Stockholders’ Equity	$	12,961		$	20,029

See the notes to the consolidated financial statements.

F-3

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(RESTATED)

See Explanatory Note

(in millions, except per share data)


	Year Ended December 31,
	2003			2002			2001
Revenues	$	5,787		$	5,326		$	9,124
Cost of sales, exclusive of depreciation shown separately below		(5,054	)		(4,596	)		(7,317	)
Depreciation and amortization expense		(454	)		(466	)		(452	)
Goodwill impairment		(311	)		(814	)		—
Impairment and other charges		(200	)		(190	)		—
Gain on sale of assets		29			7			36
General and administrative expenses		(366	)		(325	)		(420	)

Operating income (loss)		(569	)		(1,058	)		971
Earnings (losses) from unconsolidated investments		124			(80	)		191
Interest expense		(509	)		(297	)		(255	)
Other income and expense, net		25			(59	)		55
Minority interest income (expense)		3			(36	)		(93	)
Accumulated distributions associated with trust preferred securities		(8	)		(12	)		(22	)

Income (loss) from continuing operations before income taxes		(934	)		(1,542	)		847
Income tax benefit (expense)		246			352			(368	)

Income (loss) from continuing operations		(688	)		(1,190	)		479
Loss on discontinued operations, net of taxes (Note 3)		(19	)		(1,154	)		(82	)

Income (loss) before cumulative effect of change in accounting principles		(707	)		(2,344	)		397
Cumulative effect of change in accounting principles, net of taxes (Note 2)		40			(234	)		2

Net income (loss)		(667	)		(2,578	)		399
Less: preferred stock dividends (gain) (Note 15)		(1,013	)		330			42

Net income (loss) applicable to common stockholders	$	346		$	(2,908	)	$	357

Earnings (Loss) Per Share (Note 16):
Basic earnings (loss) per share:
Earnings (loss) from continuing operations	$	0.87		$	(4.16	)	$	1.35
Loss from discontinued operations		(0.05	)		(3.15	)		(0.26	)
Cumulative effect of change in accounting principles		0.11			(0.64	)		0.01

Basic earnings (loss) per share	$	0.93		$	(7.95	)	$	1.10

Diluted earnings (loss) per share:
Earnings (loss) from continuing operations	$	0.79		$	(4.16	)	$	1.29
Loss from discontinued operations		(0.04	)		(3.15	)		(0.25	)
Cumulative effect of change in accounting principles		0.09			(0.64	)		0.01

Diluted earnings (loss) per share	$	0.84		$	(7.95	)	$	1.05

Basic shares outstanding		374			366			326
Diluted shares outstanding		423			370			340

See the notes to the consolidated financial statements.

F-4

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(RESTATED)

See Explanatory Note

(in millions)


	Year Ended December 31,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(667	)	$	(2,578	)	$	399
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		525			613			482
Goodwill impairment		311			814			—
Impairment and other charges		200			847			—
(Earnings) losses from unconsolidated investments, net of cash distributions		33			232			(117	)
Risk-management activities		382			638			(17	)
Loss (gain) on sale of assets		(57	)		620			(36	)
Deferred income taxes		(258	)		(706	)		253
Cumulative effect of change in accounting principles (Note 2)		(40	)		234			(2	)
Reserve for doubtful accounts		19			68			55
Other		(9	)		87			53
Changes in working capital:
Accounts receivable		1,683			421			1,622
Inventory		93			3			24
Prepayments and other assets		726			(762	)		(183	)
Accounts payable and accrued liabilities		(2,017	)		(454	)		(2,011	)
Changes in non-current assets and liabilities, net		(48	)		(102	)		28

Net cash provided by (used in) operating activities		876			(25	)		550

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(333	)		(947	)		(2,551	)
Investments in unconsolidated affiliates		(5	)		(14	)		(1,533	)
Business acquisitions, net of cash acquired		—			(20	)		(603	)
Proceeds from asset sales, net		72			1,583			1,078
Other investing, net		—			75			(219	)

Net cash provided by (used in) investing activities		(266	)		677			(3,828	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		2,219			969			1,537
Net proceeds from short-term borrowings		—			181			—
Repayments of borrowings		(2,749	)		(623	)		(504	)
Net cash flow from commercial paper and revolving lines of credit		(128	)		(724	)		599
Payment to ChevronTexaco for Series B preferred stock restructuring		(225	)		—			—
Proceeds from issuance of capital stock		6			240			604
Proceeds from issuance of convertible preferred stock		—			—			1,500
Purchase of serial preferred securities of a subsidiary		—			(28	)		—
Purchase of treasury stock		—			(1	)		(68	)
Redemption of Illinois Power Preferred Securities		—			—			(100	)
Dividends and other distributions, net		—			(55	)		(98	)
Decrease (increase) in restricted cash		(2	)		11			(1	)
Other financing, net		(21	)		(14	)		(19	)

Net cash provided by (used in) financing activities		(900	)		(44	)		3,450

Effect of exchange rate changes on cash		10			(59	)		(23	)
Net increase (decrease) in cash and cash equivalents		(280	)		549			149
Cash and cash equivalents, beginning of period		757			208			59

Cash and cash equivalents, end of period	$	477		$	757		$	208

See the notes to the consolidated financial statements.

F-5

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(RESTATED)

See Explanatory Note

(in millions)


	Common Stock		Additional Paid-In Capital		Subscriptions Receivable			Accumulated Other Comprehensive Loss			Retained Earnings (Accumulated Deficit)			Treasury Stock			Total
December 31, 2000	$	2,912	$	15	$	—		$	(15	)	$	496		$	(3	)	$	3,405
Net income		—		—		—			—			399			—			399
Other comprehensive loss, net of tax		—		—		—			(12	)		—			—			(12	)
Common Stock issued		605		—		—			—			—			—			605
Subscriptions receivable		—		—		(38	)		—			—			—			(38	)
Implied dividend on Series B Preferred Stock		—		660		—			—			—			—			660
Options exercised		57		—		—			—			—			—			57
Dividends and other distributions		—		—		—			—			(140	)		—			(140	)
401(k) plan and profit sharing stock		13		—		—			—			—			—			13
Options granted		—		13		—			—			—			—			13
Treasury stock		—		—		—			—			—			(68	)		(68	)

December 31, 2001	$	3,587	$	688	$	(38	)	$	(27	)	$	755		$	(71	)	$	4,894
Net loss		—		—		—			—			(2,578	)		—			(2,578	)