Edgar Filing: DYNEGY INC /IL/

Amendment No. 2 to Form 10-Q for the Period Ended March 31, 2004

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

AMENDMENT NO. 2

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

For the quarterly period ended March 31, 2004

¨	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)

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 such filing requirements for the past 90 days. Yes x No ¨

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

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, 282,071,325 shares outstanding as of May 3, 2004; Class B common stock, no par value per share, 96,891,014 shares outstanding as of May 3, 2004.

DYNEGY INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets (Restated): March 31, 2004 and December 31, 2003		5

Condensed Consolidated Statements of Operations: For the three months ended March 31, 2004 (Restated) and 2003		6

Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2004 (Restated) and 2003		7

Condensed Consolidated Statements of Comprehensive Income: For the three months ended March 31, 2004 (Restated) and 2003		8

Notes to Condensed Consolidated Financial Statements		9

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		36

Item 4. CONTROLS AND PROCEDURES		59

PART II. OTHER INFORMATION

Item 6. EXHIBITS AND REPORTS ON FORM 8-K		61

DYNEGY INC. FORM 10-Q/A

INTRODUCTORY NOTE

Dynegy Inc. is filing this Amendment No. 2 on Form 10-Q/A (“Amendment No. 2”) to reflect the effect of the following items on our historical unaudited condensed consolidated financial statements and related information, as reported in our Quarterly Report on Form 10-Q for the period ended March 31, 2004, which was originally filed on May 7, 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, as well as a $4 million after-tax increase to the $15 million loss on the sale of Illinois Power recorded in the first quarter 2004 and

•

A $154 million decrease to our deferred income 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 unaudited condensed consolidated financial statements beginning on page 9. Revised financial information for the periods presented reflecting these restatements was previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2003, which was most recently amended by Amendment No. 2 thereto filed with the SEC on January 18, 2005 (the “Form 10-K/A”). The restated financial and other information included in this Amendment No. 2 should be read together with the Form 10-K/A. The following Items of the Original Filing are amended by this Amendment No. 2:

Item 1.

Condensed Consolidated Financial Statements

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 4.

Controls and Procedures

Item 6.

Exhibits 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 UNAUDITED CONDENSED CONSOLIDATED 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 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 MAY 7, 2004, INCLUDING OUR QUARTERLY REPORTS ON FORM 10-Q FOR THE PERIODS ENDED JUNE 30, 2004 AND SEPTEMBER 30, 2004, OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

DEFINITIONS

As used in this Form 10-Q/A, the abbreviations listed below have the following meanings:


ARO		Asset retirement obligation.
Bbtu/d		Billions of British thermal units per day.
Cal ISO		The California Independent System Operator.
Cal PX		The California Power Exchange.
CDWR		California Department of Water Resources.
CFTC		Commodity Futures Trading Commission.
CPUC		California Public Utilities Commission.
CRM		Our customer risk management business segment.
CUSA		Chevron U.S.A. Inc., a wholly owned subsidiary of ChevronTexaco.
$/Bbl		Dollars per barrel.
$/Gal		Dollars per gallon.
DGC		Dynegy Global Communications.
DHI		Dynegy Holdings Inc., our primary financing subsidiary.
DMG		Dynegy Midwest Generation, Inc.
DMS		Dynegy Midstream Services.
DMT		Dynegy Marketing and Trade.
DPM		Dynegy Power Marketing Inc.
EITF		Emerging Issues Task Force.
EPA		Environmental Protection Agency.
ERCOT		Electric Reliability Council of Texas, Inc.
ERISA		The Employee Retirement Income Security Act of 1974, as amended.
FASB		Financial Accounting Standards Board.
FERC		Federal Energy Regulatory Commission.
FIN		FASB Interpretation.
Form 10-K		Our Annual Report on Form 10-K for the year ended December 31, 2003, filed on February 27, 2004, as amended by Amendment No. 1 on Form 10-K/A filed on July 20, 2004.
Form 10-K/A		Amendment No. 2 to our Annual Report on Form 10-K for the year ended December 31, 2003, filed on January 18, 2005.
Form 10-Q/A		Amendment No. 2 to our Form 10-Q for the quarter ended March 31, 2004.
FPA		Federal Power Act of 1935, as amended.
GAAP		Accounting principles generally accepted in the United States of America.
GEN		Our power generation business segment.
ICC		Illinois Commerce Commission.
KWH		Kilowatt hours.
LNG		Liquefied natural gas.
MBbls/d		Thousands of barrels per day.
MMBtu		Millions of British thermal units.
MMCFD		Million cubic feet per day.
MW		Megawatt.
MWh		Megawatt hour.
NGL		Our natural gas liquids business segment.
NOV		Notice of Violation.
Original Filing		Our Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, filed on May 7, 2004, as amended by Amendment No. 1 or Form 10-Q/A filed on July 20, 2004.
PPO		Power Purchase Option.
PUCT		Public Utility Commission of Texas.
REG		Our regulated energy delivery business segment.
SEC		U.S. Securities and Exchange Commission.
SFAS		Statement of Financial Accounting Standards.
SPE		Special Purpose Entity.
VaR		Value at Risk.
VIE		Variable Interest Entity.

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

See Explanatory Note


	March 31, 2004			December 31, 2003
	(Restated)
ASSETS
Current Assets
Cash and cash equivalents	$	367		$	477
Restricted cash		—			19
Accounts receivable, net of allowance for doubtful accounts of $175 and $184, respectively		721			1,010
Accounts receivable, affiliates		10			25
Inventory		164			279
Assets from risk-management activities		942			818
Prepayments and other current assets		364			402
Assets held for sale (Note 2)		378			—

Total Current Assets		2,946			3,030

Property, Plant and Equipment		7,729			9,867
Accumulated depreciation		(1,477	)		(1,664	)

Property, Plant and Equipment, Net		6,252			8,203
Other Assets
Unconsolidated investments		611			612
Assets from risk-management activities		680			629
Goodwill		15			15
Other long-term assets		190			472
Assets held for sale (Note 2)		2,199			—

Total Assets	$	12,893		$	12,961

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Accounts payable	$	547		$	665
Accounts payable, affiliates		83			74
Accrued liabilities and other current liabilities		454			668
Liabilities from risk-management activities		1,017			838
Notes payable and current portion of long-term debt		80			245
Current portion of long-term debt to affiliates		—			86
Liabilities held for sale (Note 2)		421			—

Total Current Liabilities		2,602			2,576

Long-term debt		3,666			5,124
Long-term debt to affiliates		422			769

Long-Term Debt		4,088			5,893
Other Liabilities
Liabilities from risk-management activities		792			746
Deferred income taxes		478			524
Other long-term liabilities		547			743
Liabilities held for sale (Note 2)		1,894			—

Total Liabilities		10,401			10,482

Minority Interest		121			121
Commitments and Contingencies (Note 9)
Redeemable Preferred Securities, redemption value of $411 at March 31, 2004 and December 31, 2003, respectively		411			411
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at March 31, 2004 and December 31, 2003; 283,362,441 and 280,350,169 shares issued and outstanding at March 31, 2004 and December 31, 2003, respectively		2,853			2,848
Class B Common Stock, no par value, 360,000,000 shares authorized at March 31, 2004 and December 31, 2003; 96,891,014 shares issued and outstanding at March 31, 2004 and December 31, 2003		1,006			1,006
Additional paid-in capital		44			41
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive loss, net of tax		(80	)		(20	)
Accumulated deficit		(1,787	)		(1,852	)
Treasury stock, at cost, 1,679,183 shares at March 31, 2004 and December 31, 2003		(68	)		(68	)

Total Stockholders’ Equity		1,960			1,947

Total Liabilities and Stockholders’ Equity	$	12,893		$	12,961

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions, except per share data)

See Explanatory Note


	Three Months Ended March 31,
	2004			2003
	(Restated)
Revenues	$	1,657		$	1,879
Cost of sales, exclusive of depreciation shown separately below		(1,378	)		(1,512	)
Depreciation and amortization expense		(88	)		(115	)
Impairment and other charges		(16	)		7
Gain on sale of assets, net		2			1
General and administrative expenses		(69	)		(73	)

Operating income		108			187
Earnings from unconsolidated investments		40			53
Interest expense		(132	)		(110	)
Other income and expense, net		13			8
Minority interest income (expense)		(2	)		17
Accumulated distributions associated with trust preferred securities		—			(4	)

Income from continuing operations before income taxes		27			151
Income tax benefit (expense)		29			(56	)

Income from continuing operations		56			95
Income (loss) on discontinued operations, net of taxes (Note 2)		14			(3	)

Income before cumulative effect of change in accounting principles		70			92
Cumulative effect of change in accounting principles, net of taxes (Note 1)		—			55

Net income		70			147
Less: preferred stock dividends		5			83

Net income applicable to common stockholders	$	65		$	64

Earnings Per Share (Note 8):
Basic earnings per share:
Earnings from continuing operations	$	0.14		$	0.03
Earnings (loss) from discontinued operations		0.03			(0.01	)
Cumulative effect of change in accounting principles		—			0.15

Basic earnings per share	$	0.17		$	0.17

Diluted earnings per share:
Earnings from continuing operations	$	0.11		$	0.03
Earnings (loss) from discontinued operations		0.03			(0.01	)
Cumulative effect of change in accounting principles		—			0.15

Diluted earnings per share	$	0.14		$	0.17

Basic shares outstanding		376			371
Diluted shares outstanding		502			372

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

See Explanatory Note


	Three Months Ended March 31,
	2004			2003
	(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	70		$	147
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization		97			125
Impairment and other charges		16			—
Earnings from unconsolidated investments, net of cash distributions		(4	)		(42	)
Risk-management activities		(24	)		71
Gain on sale of assets		(2	)		(22	)
Deferred income taxes		(23	)		45
Cumulative effect of change in accounting principles (Note 1)		—			(55	)
Other		(12	)		(4	)
Changes in working capital:
Accounts receivable		99			1,061
Inventory		83			167
Prepayments and other assets		(8	)		215
Accounts payable and accrued liabilities		(119	)		(1,273	)
Changes in non-current assets and liabilities, net		(6	)		(28	)

Net cash provided by operating activities		167			407

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(53	)		(84	)
Proceeds from asset sales, net		23			7

Net cash used in investing activities		(30	)		(77	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		—			142
Repayments of long-term borrowings		(137	)		(158	)
Net cash flow from commercial paper and revolving lines of credit		—			712
Proceeds from issuance of capital stock		4			—
Dividends and other distributions, net		(11	)		—
Other financing, net		(5	)		(2	)

Net cash provided by (used in) financing activities		(149	)		694

Effect of exchange rate changes on cash		(1	)		(6	)

Net increase (decrease) in cash and cash equivalents		(13	)		1,018
Cash and cash equivalents, beginning of period		477			757
Less: Illinois Power cash classified as held for sale at end of period (Note 2)		(97	)		—

Cash and cash equivalents, end of period	$	367		$	1,775

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited) (in millions)

See Explanatory Note


	Three Months Ended March 31,
	2004			2003
	(Restated)
Net income	$	70		$	147
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(59	)		12
Reclassification of mark-to-market losses (gains) to earnings, net		12			(19	)

Changes in cash flow hedging activities, net (net of tax benefit of $28 and $4, respectively)		(47	)		(7	)
Foreign currency translation adjustments		(15	)		24
Minimum pension liability (net of tax expense of $1 and zero, respectively)		2			—

Other comprehensive income (loss), net of tax		(60	)		17

Comprehensive income	$	10		$	164

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

PLEASE NOTE THAT THESE FINANCIAL STATEMENTS AND THE NOTES THERETO DO NOT REFLECT EVENTS OCCURRING AFTER MAY 7, 2004 (THE DATE OF THE ORIGINAL FILING). FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE MAY 7, 2004, INCLUDING OUR QUARTERLY REPORTS ON FORM 10-Q FOR THE PERIODS ENDED JUNE 30, 2004 AND SEPTEMBER 30, 2004, OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

EXPLANATORY NOTE

This Amendment No. 2 to our Quarterly Report on Form 10-Q for the period ended March 31, 2004 includes restatements related to our audited consolidated financial statements as of December 31, 2003 and our unaudited condensed consolidated financial statements for the quarters ended March 31, 2004 and 2003. On January 18, 2005, we filed Amendment No. 2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2003. The Form 10-K/A also included restated financial information for the quarter ended March 31, 2003. The restatements relate to increased and additional impairments associated with the sale of Illinois Power and our deferred income tax accounts. Specifically, the restatements are as follows:

Impairment of Illinois Power. As more fully discussed in Note 10—Goodwill beginning on page F-38 of our Form 10-K/A, during 2003, the value of goodwill associated with Illinois Power was determined to be impaired, resulting in our recognizing a charge of $242 million. During 2004, while preparing to record the Illinois Power sale, we identified a deferred tax asset that was excluded from our 2003 impairment analysis. Our exclusion of this asset understated the net book value of the assets and, as a result, understated the impairment that had been recorded in 2003. The impact of the error resulted in an after-tax understatement of goodwill impairment of $139 million and an after-tax understatement of asset impairments of $120 million. As such, we were required to recognize an additional after-tax charge of $259 million ($0.61 per diluted share) in the fourth quarter 2003. In addition, we were required to recognize additional after-tax charges of $4 million ($0.01 per diluted share) in the three months ended March 31, 2004, due to changes in the value of the deferred tax asset. This correction had no impact on previously reported net cash provided by (used in) operating activities, investing activities or financing activities. The financial information in this Form 10-Q/A has been revised to reflect the impact of this correction.

The table below summarizes the effects of the correction on our previously reported net income:


	Three Months Ended March 31, 2004
	(in millions)
Impairment and other charges as previously reported	$	(10	)
Adjustment		(6	)

Impairment and other charges as restated	$	(16	)

Income tax benefit (expense) as previously reported	$	27
Adjustment		2

Income tax benefit (expense) as restated	$	29

Net income as previously reported	$	74
Adjustment		(4	)

Net income as restated	$	70

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Deferred Income Tax Accounts. As discussed in the Form 10-K/A, we have completed an evaluation of our tax accounting and reconciliation controls and processes, including a tax basis balance sheet review. Through this initiative, we determined that adjustments related to our deferred income tax accounts in periods prior to 2004 are required. These adjustments primarily related to errors associated with accounting for acquisitions, incorrect classification of goodwill impairments as permanent differences for purposes of calculating the tax provision and other items. As a result of these errors, adjustments were also made to goodwill and other long-term liabilities accounts.

This restatement has no effect on our previously reported net income or net cash provided by (used in) operating activities, investing activities or financing activities for the three months ended March 31, 2004 or 2003.

Balance Sheet Summary. The table below summarizes the effects of both items discussed above on our December 31, 2003 and March 31, 2004 balance sheets:


	March 31, 2004			December 31, 2003
	(in millions)
Property, Plant and Equipment, Net
As previously reported	$	6,252		$	8,396
Impairment of Illinois Power		—			(193	)

As restated	$	6,252		$	8,203

Goodwill
As previously reported	$	15		$	154
Impairment of Illinois Power		—			(139	)

As restated	$	15		$	15

Non-current assets held for sale
As previously reported	$	2,537		$	—
Impairment of Illinois Power		(338	)		—

As restated	$	2,199		$	—

Total Assets
As previously reported	$	13,231		$	13,293
Impairment of Illinois Power		(338	)		(332	)

As restated	$	12,893		$	12,961

Deferred income taxes
As previously reported	$	366		$	751
Impairment of Illinois Power		273			(73	)
Deferred income tax accounts		(161	)		(154	)

As restated	$	478		$	524

Other long-term liabilities
As previously reported	$	547		$	750
Deferred income tax accounts		—			(7	)

As restated	$	547		$	743

Total Liabilities
As previously reported	$	10,637		$	10,716
Impairment of Illinois Power		(75	)		(73	)
Deferred income tax accounts		(161	)		(161	)

As restated	$	10,401		$	10,482

Stockholders’ Equity
As previously reported	$	2,062		$	2,045
Impairment of Illinois Power		(263	)		(259	)
Deferred income tax accounts		161			161

As restated	$	1,960		$	1,947

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Note 1—Accounting Policies

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year end condensed balance sheet data was derived from audited financial statements but does not include all disclosures required by GAAP. These interim financial statements should be read together with the restated consolidated financial statements and notes thereto included in our Form 10-K/A, which includes restated financial statements reflecting the adjustments described in the Explanatory Note above.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Interim period results are not necessarily indicative of the results for the full year. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect our reported financial position and results of operations. These estimates and assumptions also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Judgments and estimates are based on our beliefs and assumptions derived from information available at the time such estimates are made. Adjustments made with respect to the use of these estimates often relate to information not previously available. Uncertainties with respect to such estimates and assumptions are inherent in the preparation of financial statements. Estimates are primarily used in (1) developing fair value assumptions, including estimates of future cash flows and discounts rates, (2) analyzing tangible and intangible assets for possible impairment, (3) estimating the useful lives of our assets, (4) assessing future tax exposure and the realization of tax assets, (5) determining amounts to accrue for contingencies and (6) estimating various factors used to value our pension assets. Actual results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.

Accounting Principles Adopted

EITF Issue 02-03. In October 2002, the EITF rescinded EITF Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” which previously required use of mark-to-market accounting for our energy trading contracts. While the rescission of EITF Issue 98-10 reduced the number of contracts accounted for on a mark-to-market basis, it did not eliminate mark-to-market accounting. All derivative contracts that either do not qualify, or are not designated, as hedges or as normal purchases or sales, as defined by SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, continue to be marked-to-market in accordance with SFAS No. 133. Any earnings or losses previously recognized under EITF Issue 98-10 that would not have been recognized under SFAS No. 133 were reversed in 2003 pursuant to adopting the provisions of EITF Issue 02-03. The cumulative effect of this change in accounting principle

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

resulted in after-tax earnings of $21 million in the first quarter 2003 and comprised the following items that are no longer required to be recorded using mark-to-market accounting (in millions):


Removal of net risk-management assets representing the value of natural gas storage contracts	$	(176	)
Removal of other net risk-management assets		(24	)
Removal of net risk-management liabilities representing the value of power tolling arrangements		103

Net change in risk-management assets and liabilities		(97	)
Addition of inventory previously included in risk-management assets (1)		130

Pre-tax gain recorded from change in accounting principle		33
Income tax provision		(12	)

After-tax gain recorded in the unaudited condensed consolidated statements of operations	$	21

(1)	A substantial portion of this natural gas inventory was sold during the three months ended March 31, 2003, with the remainder being sold in the second quarter 2003.

SFAS No. 143. In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” We adopted SFAS No. 143, which provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets, effective January 1, 2003. Under SFAS No. 143, an ARO is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted towards the ultimate obligation amount and the capitalized ARO costs are depreciated over the useful life of the related asset.

As part of the transition adjustment in adopting SFAS No. 143, existing environmental liabilities in the amount of $73 million were reversed in the first quarter 2003. The fair value of the remediation costs estimated to be incurred upon retirement of the respective assets is included in the ARO and was recorded upon adoption of SFAS No. 143. Since the previously accrued liabilities exceeded the fair value of the future retirement obligations, the impact of adopting SFAS No. 143 was an increase in earnings, net of tax, of $34 million in the first quarter 2003, which is included in cumulative effect of change in accounting principles in the unaudited condensed consolidated statements of operations. In addition to these liabilities, we also have potential retirement obligations for dismantlement of power generation facilities, power transmission assets, a fractionation facility and natural gas storage facilities. Our current intent is to maintain these facilities in a manner such that they will be operated indefinitely. As such, we cannot estimate any potential retirement obligations associated with these assets. Liabilities will be recorded in accordance with SFAS No. 143 at the time we are able to estimate any new AROs.

At January 1, 2004, our ARO liabilities were $30 million for our GEN segment, $10 million for our NGL segment and $1 million for our REG segment. These retirement obligations related to activities such as ash pond and landfill capping, closure and post-closure costs, environmental testing, remediation, monitoring and land and equipment lease obligations. During the three-month periods ended March 31, 2004 and 2003, accretion expense recognized for the fair value for all of our ARO liabilities totaled approximately $1 million and $1 million, respectively. There were no additional AROs recorded or settled, nor were there any revisions to estimated cash flows associated with existing AROs, during the three-month periods ended March 31, 2004 and 2003. At March 31, 2004, our aggregate ARO liability was $42 million.

SFAS No. 148. In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Based Compensation,” and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. We transitioned to a fair value-based method of accounting for stock-based compensation in the first quarter 2003 and are using the prospective method of transition as described under SFAS No. 148.

Under the prospective method of transition, all stock options granted after January 1, 2003 are accounted for on a fair value basis. Options granted prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Accordingly, for options granted prior to January 1, 2003, compensation expense is not reflected for employee stock options unless they were granted at an exercise price lower than market value on the grant date. We have granted in-the-money options in the past and have recognized compensation expense over the applicable vesting periods. No in-the-money stock options have been granted since 1999.

Had compensation cost for all stock options granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income and basic and diluted earnings per share amounts would have approximated the following pro forma amounts for the three-month periods ended March 31, 2004 and 2003, respectively.


	Three Months Ended March 31,
	2004			2003
	(in millions, except per share data)
Net income as reported	$	70		$	147
Add: Stock-based employee compensation expense included in reported net loss, net of related tax effects		1			1
Deduct: Total stock-based employee compensation expense determined under fair value-based method for all awards, net of related tax effects		(9	)		(17	)

Pro forma net income	$	62		$	131

Earnings per share:
Basic—as reported	$	0.17		$	0.17
Basic—pro forma	$	0.15		$	0.13
Diluted—as reported	$	0.14		$	0.17
Diluted—pro forma	$	0.12		$	0.13

FIN No. 46R. In the fourth quarter 2003, we adopted the initial provisions of FIN No. 46R, “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51.” FIN No. 46R was effective on December 31, 2003 for entities considered SPEs. We adopted the remaining provisions of FIN No. 46R on March 31, 2004. These provisions require that we review the structure of non-SPE legal entities in which we have an investment and other legal entities with whom we transact to determine whether such entities are VIEs, as defined by FIN No. 46R. With respect to each of the VIEs we identified, we assessed whether we are the “primary beneficiary,” as defined by FIN No. 46R. We concluded that we were not the primary beneficiary of any of these entities and, therefore, the adoption did not have an impact on our unaudited condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

FIN No. 46R requires additional disclosures for entities which meet the definition of a VIE in which we hold a significant variable interest but are not the primary beneficiary. We own 50% equity interests in various generation facilities in Illinois, California, Georgia, Texas and Michigan, which are accounted for using equity method accounting and are included in Unconsolidated investments in our unaudited condensed consolidated balance sheets. We acquired or began involvement with these equity interests in 1997 and 1999. Total net generating capacity for these generating facilities ranges from 62 MW to 1,156 MW. As a result of various contractual arrangements into which these entities have entered, we have concluded that they are VIEs. As we do not absorb a majority of the expected losses or receive a majority of the expected residual returns, we are not considered the primary beneficiary of these entities. Our equity investment balance in the facilities totaled $475 million at March 31, 2004, and one of our affiliates has a loan outstanding to one of these entities, which totaled $11 million at March 31, 2004.

FIN No. 46R also requires additional disclosure for entities where we are unable to obtain financial information to determine (1) if the entity is a VIE and (2) if we are deemed to be the primary beneficiary of the entity. We identified one potential VIE for which we were unable to obtain adequate financial information. As required to be disclosed by FIN No. 46R, following is a description of the agreements with this potential VIE. In July 2001, we entered into several agreements, including a power tolling agreement, a financial derivative instrument, an energy management agreement and a natural gas supply agreement, with Sithe Independence Power Partners, L.P., which owns and operates a 955 MW combined cycle natural gas generation facility in Oswego, New York. These agreements are in effect through 2014. Our future obligations under these agreements are approximately $807 million, which includes the fixed capacity payments for our physical tolling contract and fixed payments related to the financial derivative instrument. We recorded expense of $6 million and $9 million under the tolling agreement and financial derivative instrument during the quarters ended March 31, 2004 and 2003, respectively.

Cumulative Effect of Change in Accounting Principles

We adopted SFAS No. 143 and provisions of EITF Issue 02-03 in the first quarter 2003. We adopted provisions of FIN No. 46R in the first quarter 2004. Please see above for a discussion of the impact of adopting these standards.

Note 2—Dispositions and Discontinued Operations

Amounts in this footnote have been restated. For further information, please see the Explanatory Note beginning on page 9.

Dispositions

Pending Sale of Illinois Power. In February 2004, we entered into a purchase agreement to sell all of the outstanding common and preferred shares of Illinois Power Company, which currently comprises our REG segment, owned by Illinova Corporation, our indirect wholly owned subsidiary and the direct parent company of Illinois Power, and our 20% interest in the Joppa power generation facility, to Ameren for $2.3 billion. The sale is scheduled to be completed by the end of 2004. In a related agreement that is conditioned upon the closing of the transaction, we have contracted to sell 2,800 MWs of generating capacity and up to 11.5 million MWh of energy to Illinois Power at fixed prices for two years beginning in January 2005. We also agreed to sell 300 MWs of capacity in 2005 and 150 MWs of capacity in 2006 to Illinois Power at a fixed price with an option to purchase energy at market-based prices.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

At March 31, 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144 and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets and liabilities classified as Assets held for sale or Liabilities held for sale at March 31, 2004 are as follows (in millions):


Current Assets:
Cash	$	97
Accounts receivable		209
Inventory		28
Other		44

Total Current Assets	$	378

Long-Term Assets:
Property, plant and equipment, net	$	1,907
Regulatory assets		194
Other		98

Total Long-Term Assets	$	2,199

Current Liabilities:
Accounts payable	$	30
Current portion of long-term debt, including $72 million due to affiliates		216
Other		175

Total Current Liabilities	$	421

Long-Term Liabilities:
Long-term debt, including $323 million due to affiliates	$	1,689
Other		205

Total Long-Term Liabilities	$	1,894

Additionally, $11 million included in Redeemable preferred securities and $34 million of Accumulated other comprehensive loss at March 31, 2004 relate to Illinois Power and will not be included in our unaudited condensed consolidated balance sheets subsequent to the sale.

SFAS No. 144 also requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of Illinois Power’s property, plant and equipment and regulatory assets, effective February 1, 2004. In addition, SFAS No. 144 requires a loss to be recognized by the amount Assets held for sale less Liabilities held for sale are in excess of fair value less costs to sell. Accordingly, in the first quarter 2004, we recorded a $15 million pre-tax loss on sale primarily associated with the expected transaction costs. This loss is reflected in Gain on sale of assets, net on the unaudited condensed consolidated statements of operations. Additionally, we recorded a pre-tax asset impairment totaling $6 million ($4 million after-tax). This impairment is reflected in Impairments and other charges on the unaudited condensed consolidated statements of operations.

Pursuant to SFAS No. 144, we are not reporting the results of Illinois Power’s operations as a discontinued operation. If we were to account for Illinois Power as a discontinued operation, its results of operations would be condensed into Income (loss) on discontinued operations, net of taxes, on our unaudited condensed consolidated statements of operations and prior periods would be required to be restated to conform to this presentation. To qualify for discontinued operations classification, SFAS No. 144 and subsequent interpretations, specifically

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

EITF Issue 03-13, “Applying the Conditions in Paragraph 42 of FAS 144 in Determining Whether to Report Discontinued Operations,” require that the seller have no significant continuing involvement with the business being sold. As noted above, we have contracted to sell capacity and energy to Illinois Power for two years subsequent to the sale. Consequently, because we will have significant continuing involvement with Illinois Power, we will continue to report the historical results of Illinois Power’s operations in continuing operations. Earnings from power sales to Illinois Power derived from periods following the closing of the transaction will continue to be reported in the GEN segment in continuing operations.

Changes in Assets held for sale less Liabilities held for sale in future quarters, prior to the closing of the transaction, may result in additional losses. In accordance with SFAS No. 142, such losses would first be recorded as a reduction to goodwill in our REG segment. The amount of such losses depends on various factors including timing of the closing of the transaction, capital expenditures prior to closing and other matters. Given the nature of these factors, we currently are unable to predict with certainty the amount of loss we expect to realize.

We expect to record a pre-tax gain of approximately $75 million upon closing of the transaction related to the sale of our 20% interest in the Joppa power generation facility. Our interest in the Joppa power generation facility is included in our unaudited condensed consolidated balance sheets in Unconsolidated investments and totaled $23 million at March 31, 2004.

Hackberry LNG Project. During the first quarter 2003, we entered into an agreement to sell our ownership interest in Hackberry LNG Terminal LLC, the entity we formed in connection with our proposed LNG terminal/gasification project in Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction closed in April 2003, after which we received contingent payments in 2003 based upon project development milestones. In March 2004, we sold our remaining financial interest in this project, which interest included rights to future contingent payments under the 2003 agreement, for $17 million and recognized a pre-tax gain of $17 million on the sale. This gain is included in Gain on sale of assets, net on the unaudited condensed consolidated statements of operations.

Indian Basin. In April 2004, we sold our 16% interest in the Indian Basin Gas Processing Plant for approximately $48 million. In the second quarter 2004, we expect to recognize a pre-tax gain on the sale of approximately $36 million.

PESA. In April 2004, we sold our interest in the Plantas Eolicas, S. de R.L. 20 MW wind-powered electric generation facility located in Costa Rica for approximately $11 million. We do not expect to recognize a material gain or loss on the sale.

Capital Loss Valuation Allowance. As a result of the transactions discussed above, as well as other transactions forecasted to occur in 2004, we reduced the valuation allowance related to our significant capital loss carryforward by $39 million in the first quarter 2004. This capital loss carryforward primarily relates to our third quarter 2002 sale of Northern Natural Gas Company. The $39 million benefit is reflected in Income tax benefit (expense) on the unaudited condensed consolidated statements of operations.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Discontinued Operations

As part of our restructuring plan, we sold or liquidated some of our operations during 2003, including substantial portions of our communications business and our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144. The following table summarizes information related to our discontinued operations:


	U.K. CRM			DGC			Total
	(in millions)
Three Months Ended March 31, 2004
Income from operations before taxes	$	17		$	3		$	20
Income from operations after taxes		12			2			14

Three Months Ended March 31, 2003
Revenue	$	21		$	4		$	25
Loss from operations before taxes		(15	)		(19	)		(34	)
Loss from operations after taxes		(10	)		(12	)		(22	)
Gain on sale before taxes		—			21			21
Gain on sale after taxes		—			19			19

In the first quarter 2004, we recognized $17 million of pre-tax income related to translation gains on foreign currency in the U.K. Please see Note 4—Risk Management Activities and Accumulated Other Comprehensive Loss—Net investment hedges in foreign operations for further information. Also in the first quarter 2004, we recognized $3 million of pre-tax income associated with DGC’s receipt of $3 million from a third party in settlement of a prior contractual claim.

Note 3—Restructuring Charges

In October 2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business. The following is a schedule of 2004 activity for the liabilities recorded in connection with this restructuring:


	Severance			Cancellation Fees and Operating Leases			Total
	(in millions)
Balance at December 31, 2003	$	23		$	30		$	53
2004 adjustments to liability		8			2			10
Cash payments		(1	)		(3	)		(4	)

Balance at March 31, 2004	$	30		$	29		$	59

The adjustment to the accrued liability during 2004 primarily reflects increases in the severance accrual due to changes in our estimate of the probable loss associated with the severance claims of our former chief executive officer. Please see Note 9—Commitments and Contingencies—Severance Arbitrations for further information regarding the status of these claims.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Note 4—Risk Management Activities and Accumulated Other Comprehensive Loss

The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in an attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more fully described in Note 5—Risk Management Activities and Financial Instruments beginning on page F-29 of our Form 10-K/A.

Cash flow hedges. We enter into financial derivative instruments that qualify as cash flow hedges. Instruments related to our power generation and natural gas liquids businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin. Interest rate swaps are used to convert the floating interest-rate component of some obligations to fixed rates.

During the three months ended March 31, 2004 and 2003, there was no material ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three months ended March 31, 2004 and 2003, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at March 31, 2004 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity or natural gas liquids and payments of interest, as applicable to each type of hedge. Of this amount, after-tax losses of approximately $34 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 2005. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market conditions and other factors.

Fair value hedges. We also enter into derivative instruments that qualify as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into variable-rate debt. During the three months ended March 31, 2004 and 2003, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three months ended March 31, 2004 and 2003, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

Net investment hedges in foreign operations. We have investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. In the past, we used derivative financial instruments, including foreign exchange forward contracts and cross-currency interest rate swaps, to hedge this exposure. As of March 31, 2004, we had no net investment hedges in place.

During the first quarter 2003, our efforts to exit the U.K. CRM business and the European communications business were substantially completed. As required by SFAS No. 52, “Foreign Currency Translation,” a significant portion of unrealized gains and losses resulting from translation and financial instruments utilized to hedge currency exposures previously recorded in stockholders’ equity were recognized in income, resulting in an after-tax loss of approximately $16 million in the three months ended March 31, 2003. During the first quarter 2004, we repatriated a majority of our cash from the U.K., resulting in the substantial liquidation of our investment in the U.K. As such, we recognized approximately $17 million of pre-tax translation gains in income that arose since April 1, 2003 and had accumulated in stockholders’ equity.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Accumulated other comprehensive loss. Accumulated other comprehensive loss, net of tax, is included in stockholders’ equity on the unaudited condensed consolidated balance sheets as follows:


	March 31, 2004			December 31, 2003
	(in millions)
Cash flow hedging activities, net	$	(37	)	$	10
Foreign currency translation adjustment		12			27
Minimum pension liability		(55	)		(57	)

Accumulated other comprehensive loss, net of tax	$	(80	)	$	(20	)

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:


	March 31, 2004		December 31, 2003
	(in millions)
Equity affiliates:
GEN investments	$	523	$	518
NGL investments		82		82

Total equity affiliates		605		600
Other affiliates, at cost		6		12

Total unconsolidated investments	$	611	$	612

Summarized aggregate financial information for unconsolidated equity investments and our equity share thereof was:


	Three Months Ended March 31,
	2004				2003
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	485	$	217	$	998	$	390
Operating income		112		53		143		61
Net income		96		47		120		53

Earnings from unconsolidated investments of $40 million for the three months ended March 31, 2004, include the $47 million above, offset by a $7 million impairment of our Michigan Power equity investment discussed below. Earnings from unconsolidated investments of $53 million for the three months ended March 31, 2003 consist entirely of the net income related to such investments.

During the first quarter 2004, we sold our interest in our power generating facility located in Jamaica. Net proceeds associated with the sale were approximately $5.5 million, and we did not recognize a gain or loss on the sale. Also during the first quarter 2004, we entered into agreements to sell our unconsolidated investments in the Oyster Creek and Michigan Power generation facilities for aggregate net cash proceeds of approximately $103 million. Closing of the transactions, targeted for the second quarter 2004, are subject to lender and counterparty

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

consents and other closing conditions. In the first quarter 2004, we recorded an impairment on our investment in Michigan Power totaling $7 million to adjust our book value to the selling price.

Note 6—Debt

Revolvers and Commercial Paper. During the three-month period ended March 31, 2004, we issued an aggregate of approximately $20 million of letters of credit under our $1.1 billion revolving credit facility for a total of $208 million at March 31, 2004. As of March 31, 2004, there were no borrowings outstanding under this facility. During the period from March 31, 2004 through May 3, 2004, we reduced our outstanding letters of credit under this facility by $19 million.

Repayments. In the first quarter 2004, we repaid the $95 million aggregate principal amount of Illinova’s 7.125% Senior Notes due 2004. We also made payments of $19 million related to the ABG Gas Supply financing and $22 million related to Illinois Power’s transitional funding trust notes.

Note 7—Related Party Transactions

We engage in transactions with ChevronTexaco Corporation and its affiliates, including purchases and sales of natural gas and natural gas liquids, which we believe are executed on terms that are fair and reasonable. Please see Note 13—Related Party Transactions—Transactions with ChevronTexaco beginning on page F-48 of our Form 10-K/A for further discussion.

Series C Convertible Preferred Stock. As discussed in Note 15—Redeemable Preferred Securities—Series C Convertible Preferred Stock beginning on page F-53 of our Form 10-K/A, we issued 8 million shares of our Series C convertible preferred stock due 2033 to CUSA. We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. We made the first semi-annual dividend payment of $11 million on February 11, 2004.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Note 8—Earnings Per Share

Amounts in this footnote have been restated. For further information, please see the Explanatory Note beginning on page 9. Basic earnings per share represents the amount of earnings for the period available to each share of common stock outstanding during the period. Diluted earnings per share represents the amount of earnings for the period available to each share of common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period. The reconciliation of basic earnings per share from continuing operations to diluted earnings per share from continuing operations is shown in the following table:


	Three Months Ended March 31,
	2004			2003
	(in millions, except per share amounts)
Income from continuing operations	$	56		$	95
Convertible preferred stock dividends		(5	)		(83	)

Income from continuing operations for basic earnings per share		51			12
Effect of dilutive securities:
Interest on convertible subordinated debentures		1			—
Dividends on Series C convertible preferred stock		5			—

Income from continuing operations for diluted earnings per share	$	57		$	12

Basic weighted-average shares		376			371
Effect of dilutive securities:
Stock options and restricted stock		2			1
Convertible subordinated debentures		55			—
Series C convertible preferred stock		69			—

Diluted weighted-average shares		502			372

Earnings per share from continuing operations
Basic	$	0.14		$	0.03

Diluted	$	0.11		$	0.03

Note 9—Commitments and Contingencies

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS NOTE 9, WHICH WAS PRESENTED IN OUR FIRST QUARTER 2004 FORM 10-Q ORIGINALLY FILED WITH THE SEC ON MAY 7, 2004 IN ORDER TO REFLECT THE MATERIAL CHANGES IN OR UPDATES TO OUR MATERIAL LEGAL PROCEEDINGS SINCE THE ORIGINAL FILING OF OUR 2003 FORM 10-K, DOES NOT REFLECT EVENTS OCCURRING AFTER MAY 7, 2004. FOR A DESCRIPTION OF THESE EVENTS, INCLUDING MATERIAL CHANGES IN, OR UPDATES TO, OUR MATERIAL LEGAL PROCEEDINGS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE MAY 7, 2004, INCLUDING OUR QUARTERLY REPORTS ON FORM 10-Q FOR THE QUARTERS ENDED JUNE 30, 2004 AND SEPTEMBER 30, 2004, OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO.

Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of operations or cash flows.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable under SFAS No. 5, “Accounting for Contingencies.” For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please see Note 2—Accounting Policies—Other Contingencies beginning on page F-15 of our Form 10-K/A for further discussion of our reserve policies. Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the amount of any reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

With respect to some of the items listed below, management has determined that a loss is not probable or that any such loss, to the extent probable, is not reasonably estimable. In some cases, management is not able to predict with any degree of certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed these matters based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

Summary of Recent Developments. As described in greater detail below, the following significant developments involving our material legal proceedings occurred since the original filing of our Form 10-K:

•

We announced an agreement on a comprehensive settlement of numerous contested FERC claims relating to western electric energy market transactions that occurred between January 2000 and June 2001. As part of the settlement, which is subject to final documentation and approval by the FERC and the CPUC, West Coast Power will forego its right to collect past due receivables and interest from the Cal ISO and the Cal PX related to the settlement period and pay $22.5 million in exchange for the dismissal of claims against Dynegy and West Coast Power related to the settlement period.

•

The arbitration relating to Mr. Bergstrom’s severance agreement was tried before a panel of three arbitrators, which issued a decision awarding Mr. Bergstrom approximately $10.4 million.

•

The judge presiding over our ERISA class action lawsuit entered an order that substantially reduced the class period, dismissed several of the plaintiffs’ claims and dismissed all of the defendants except Dynegy and the members of the Dynegy Benefit Plans Committee from January 2002 to January 2003, the new class period established by the order.

•

Following our unsuccessful appeal of an adverse judgment in the Maxus litigation, we paid the judgment of approximately $6.9 million.

•

We are defending a lawsuit in New York arising from the 2001 shutdown of the Vienna office used in our former global communications business. A stay of this lawsuit, which is premised on alter ego-based claims of liability primarily relating to real property leases to which our former Austrian subsidiary was a party, was recently lifted, and we intend to answer the claim in May 2004.

The above summary of recent developments is qualified in its entirety by, and should be read in conjunction with, the more detailed summary of our significant legal proceedings set forth below.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Shareholder Litigation. We are defending a class action lawsuit filed on behalf of purchasers of our publicly traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit principally asserts that we and certain of our current and former officers and directors violated the federal securities laws in connection with our disclosures, including accounting disclosures, regarding Project Alpha (a structured natural gas transaction entered into by us in April 2001), round-trip trading, the submission of false trade reports to publications that calculate natural gas index prices, the alleged manipulation of the California power market and the restatement of our financial statements for 1999-2001. The Regents of the University of California have been appointed as lead plaintiff and Milberg Weiss is class counsel. The plaintiff filed an amended complaint in January 2004 and, in March 2004, we filed a motion to dismiss. We expect the plaintiff’s response and our corresponding reply to be filed in May and June 2004, respectively. An adverse result in this action could have a material adverse effect on our financial condition, results of operations and cash flows. We previously recorded a reserve in connection with this litigation.

In addition, we are a nominal defendant in several derivative lawsuits brought by shareholders on Dynegy’s behalf against certain of our former officers and current and former directors whose claims are similar to those described above. These lawsuits have been consolidated into two groups—one pending in federal court and the other pending in state court. Our motion to dismiss the federal derivative claim is currently pending and is set for hearing in June 2004. We do not expect to incur any material liability with respect to these claims.

ERISA/401(k) Litigation. We are defending a purported class action complaint filed in federal district court on behalf of participants holding Dynegy common stock in the Dynegy 401(k) Savings Plan during the period from April 1999 to January 2003. This complaint alleges violations of ERISA in connection with our 401(k) Savings Plan, including claims that our Board and certain of our former and current officers, past and present members of our Benefit Plans Committee, former employees who served on a predecessor committee to our Benefit Plans Committee, and Vanguard Fiduciary Trust Company and CG Trust Company (trustees of the trust that held Plan assets for portions of the putative class period) breached their fiduciary duties to the Plan’s participants and beneficiaries in connection with the Plan’s investment in Dynegy common stock—in particular with respect to our financial statements, Project Alpha, round-trip trades and the gas price index investigation. The lawsuit seeks unspecified damages for the losses to the Plan, as well as attorney’s fees and other costs. In July 2003, we filed a motion to dismiss this action. The judge entered an order on our motion in March 2004, dismissing several of the plaintiff’s claims and all of the defendants except Dynegy and the members of the Dynegy Benefit Plans Committee from January 2002 to January 2003, the substantially reduced class period established by the order. An answer was filed to the plaintiff’s suit denying the remaining claims in April 2004. Discovery is proceeding. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in connection with this lawsuit. However, given the nature of the claims, an adverse outcome could have a material adverse effect on our financial condition, results of operations and cash flows.

Baldwin Station Litigation. Illinois Power and DMG are the subject of an NOV from the EPA and a complaint filed by the EPA and the Department of Justice in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations. Similar notices and complaints were filed against other owners of coal-fired power plants in what we refer to as the Utility Enforcement Initiative. Both the NOV and the complaint allege that certain equipment repairs, replacements and maintenance activities at our three Baldwin Station generating units constituted “major modifications” under the Prevention of Significant Deterioration (PSD), the New Source Performance Standard (NSPS) regulations and applicable Illinois regulations, and that we failed to obtain required operating permits under applicable Illinois regulations. When activities which are not

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

otherwise exempt result in an increase in annual emissions that exceeds the amount deemed significant under the PSD regulations, those activities are considered “major modifications.” When activities meeting this definition occur, the Clean Air Act and related regulations generally subject those activities to PSD review and permit requirements and require that the generating facilities where the activities occur meet more stringent emissions standards, which may entail the installation of potentially costly pollution control equipment.

We have significantly reduced emissions of sulphur dioxide and nitrogen oxides at the Baldwin Station since the 1999 complaint by converting it from high to low sulfur coal and installing selective catalytic reduction equipment. However, the EPA may seek to require the installation of the “best available control technology,” or the equivalent, at the Baldwin Station, which we estimate could require us to incur capital expenditures of up to $410 million. The EPA also has the authority to seek penalties for the alleged violations at the rate of up to $27,500 per day for each violation.

In February 2003, the Court granted our motion for partial summary judgment based on the five-year statute of limitations. As a result, the EPA is not permitted to seek any monetary civil penalties for claims related to construction without a permit under the PSD regulations. The Court’s ruling also precludes monetary civil penalties for a portion of the claims under the NSPS regulations and the applicable Illinois regulations. We believe that we have meritorious defenses against the remaining claims and vigorously defended against them at trial. The trial to resolve claims of liability began in June 2003 and closing arguments occurred in September 2003. Shortly after closing arguments, several interveners were granted the right to file briefs in support of arguments they believe the United States ceased to pursue. These interventions and delays in post-trial briefing have postponed the issuance of the liability order, and we cannot predict with certainty when a decision will be rendered. We have recorded a reserve in an amount we consider reasonable for potential penalties that could be imposed if the Court finds us liable and the EPA prosecutes successfully the remaining claims for penalties.

In August 2003, two significant decisions were handed down in other cases that are part of the Utility Enforcement Initiative. The court in United States v. Ohio Edison applied the EPA’s narrow interpretation of the “routine maintenance, repair and replacement” exclusion, which defines it with respect to what is routine for the specific unit where the projects occurred, while the court in United States v. Duke Energy Company rejected the EPA’s narrow interpretation, holding that the exclusion should be defined relative to what is routine for the particular industry. The Duke court also held that the hours and conditions of a unit’s operations must be held constant when measuring emissions increases. Under this rationale, an increase in maximum hourly emissions is required before activities would be considered “major modifications.” We are unable to predict the significance of these cases to our Baldwin Station litigation as they are pending in other jurisdictions and are not binding authority.

Also in August 2003, the EPA issued a new rule, the “Equipment Replacement Provision of the Routine Maintenance, Repair and Replacement Exclusion,” the effectiveness of which has been delayed pending the resolution of an appeal filed by several northeastern states and environmental groups. The new rule, if sustained, would provide that replacing components of a process unit with identical components (or functional equivalents) falls within the scope of the routine maintenance, repair and replacement exclusion if (i) the replacement cost is less than 20% of the total cost of replacing the unit, (ii) the replacement does not alter the unit’s basic design and (iii) the unit will continue to comply with applicable emission and operational standards.

None of our other facilities are covered in the complaint and NOV, but the EPA previously requested information, which we provided, concerning activities at our Vermilion, Wood River, Hennepin, Danskammer and Roseton plants. The EPA could eventually commence enforcement actions based on activities at these plants,

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although the uncertainty surrounding the new rule makes it difficult to assess the likelihood of additional EPA enforcement actions.

California Market Litigation. We and numerous other power generators and marketers are the subject of numerous lawsuits arising from our participation in the western power markets during the California energy crisis. Eight of these lawsuits, which primarily allege manipulation of the California wholesale power markets and seek unspecified treble damages, were consolidated before a single federal judge. That judge dismissed two of the cases in the first quarter 2003 on the grounds of FERC preemption and the filed rate doctrine. A decision on the plaintiffs’ appeal of that dismissal is not expected before the third quarter 2004. Regarding the other six consolidated cases, we are awaiting a ruling from the Ninth Circuit Court of Appeals, which we do not expect to occur prior to the third quarter 2004, on our appeal of a prior decision to remand those cases to state court.

In addition to the eight consolidated lawsuits discussed above, nine other putative class actions and/or representative actions were filed in state and federal court on behalf of business and residential electricity consumers against us and numerous other power generators and marketers between April and October 2002. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek to enjoin illegal conduct, restitution and unspecified damages. While some of the allegations in these lawsuits are similar to the allegations in the eight lawsuits described above, these lawsuits include additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. The court granted our motion to dismiss eight of these nine actions, although the plaintiffs have appealed and we are awaiting a hearing date on their appeal. The ninth case was remanded to state court, where a newly added defendant filed a motion in February 2004 to remove the case back to federal court. Once a decision is made on this motion, we intend to file a motion to dismiss this case.

In December 2002, two additional actions were filed with similar allegations on behalf of residents of Washington and Oregon. In May 2003, the plaintiffs voluntarily dismissed these actions and refiled them in California Superior Court as a class action complaint. The complaint, which was brought on behalf of consumers and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleges violations of the Cartwright Act and unfair business practices. We have removed the action from state court and consolidated it with existing actions pending before the United States District Court for the Northern District of California. The hearing on plaintiffs’ appeal to remand to state court occurred in February 2004. The judge stayed his ruling on the appeal pending the Ninth Circuit’s ruling on the six consolidated cases referenced above. Most recently, the Montana Attorney General has filed a case alleging similar antitrust and market manipulation claims, although we have not been served with this lawsuit.

We believe that we have meritorious defenses to these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or estimate the range of possible loss, if any, that we might incur in connection with these lawsuits. However, given the nature of the claims, an adverse result in any of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

FERC and Related Regulatory Investigations—Requests for Refunds. In July 2001, the FERC initiated a hearing to establish refunds to electricity customers, or offsets against amounts owed to electricity suppliers, during the period of October 2000 through June 2001. In particular, the FERC established a methodology to calculate mitigated market clearing prices in the Cal ISO and the Cal PX markets. In December 2002, an administrative law judge issued his recommendations regarding the appropriate level of refunds or offsets. Those

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recommendations, however, do not fully reflect proposed refund or offset amounts for individual companies. In October 2003, the FERC issued two orders addressing various applications for rehearing, including ours, relating to its previous refund orders. The orders addressed numerous requests by the parties, the most significant of which was the refusal to change the gas pricing methodology and a requirement that the Cal ISO and Cal PX recalculate the refund liability of market participants. The gas price methodology approved by the FERC in March 2003 replaces the gas prices used in the computation, thus reducing the mitigated market clearing price for power and increasing calculated refunds, subject to a provision that provides full recoverability of actual gas costs paid by the generators to unaffiliated third parties. No final refund calculation is expected prior to August 2004. West Coast Power recorded a reserve in the fourth quarter 2003 relating to its estimated refund exposure.

In June 2003, the FERC issued an order to show cause why the activities of certain participants in the California power markets from January 2000 to June 2001, including Dynegy, did not constitute gaming and/or anomalous market behavior as defined in the Cal ISO and Cal PX tariffs. In January 2004, Dynegy and the FERC staff submitted a stipulation and settlement agreement to the presiding administrative law judge to settle the issues raised in the June 2003 show cause order. This settlement, which provides that West Coast Power will pay approximately $3 million, following final FERC approval, into a fund established at the U.S. Treasury for the benefit of California and Western electricity consumers, will be incorporated into the broader settlement described below.

Also in June 2003, the FERC issued an order requiring parties to demonstrate that certain bids did not constitute anomalous market behavior. Specifically, the order requires the FERC staff to investigate all parties who bid above the level of $250/MWh in the Cal ISO and Cal PX markets during the period from May 2000 to October 2000. Parties identified through this process will be required to demonstrate why this bidding behavior did not violate market protocols. The order also states that, to the extent such practices are not found to be legitimate business behavior, the FERC will require the disgorgement of all unjust profits for that period and will consider other non-monetary remedies, such as the revocation of market-based rate authority.

In April 2004, Dynegy and West Coast Power announced an agreement to settle FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001. The parties to this settlement other than Dynegy and West Coast Power include the FERC, Pacific Gas and Electric Company, Southern California Edison, San Diego Gas & Electric Company, the CDWR, the California Electricity Oversight Board and the California Attorney General. Other market participants may opt into this settlement and share in the distribution of the settlement proceeds. As part of the settlement agreement, West Coast Power will (i) forego its right to collect past-due receivables and interest from the Cal ISO and the Cal PX related to the settlement period, (ii) forego natural gas cost recovery claims against the California settling parties related to the settlement period, and (iii) place into escrow accounts a total of $22.5 million, which includes the above-referenced $3 million settlement with the FERC staff, for subsequent distribution to various California energy purchasers. In exchange, the other settling parties will forego (i) all claims relating to refunds or other monetary damages for sales of electricity during the settlement period, and (ii) claims alleging receipt of unjust or unreasonable rates for the sale of electricity during the settlement period.

The settlement is subject to the execution of definitive agreements and approval by the FERC and the CPUC, which is expected in the third quarter 2004. We recorded an additional $5 million charge in the first quarter 2004 related to the settlement.

The settlement will not apply to the ongoing civil litigation related to the California energy markets described above in which Dynegy and West Coast Power are defendants. The settlement also will not apply to

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the pending appeal by the CPUC and the California Electricity Oversight Board of the FERC’s prior decision to affirm the validity of the West Coast Power-CDWR contract. We are currently awaiting a ruling on this appeal and related filings and cannot predict their outcome.

West Coast Power. Through our interest in West Coast Power, we have credit exposure for transactions to the Cal ISO and Cal PX, which rely on cash payments from California utilities to in turn pay their bills. West Coast Power currently sells directly to the CDWR pursuant to a long-term sales agreement.

At March 31, 2004, our portion of the receivables owed to West Coast Power by the Cal ISO and Cal PX, as reflected in West Coast Power’s financial records, approximated $235 million. Management periodically assesses our exposure through West Coast Power, relative to our California receivables and establishes and maintains reserves under SFAS 5. Our share of the total reserve taken by West Coast Power at March 31, 2004 was approximately $196 million. We also recorded an additional $5 million charge in the first quarter 2004 related to the above-described settlement which, if approved, will resolve the claims and disputes which initially gave rise to these reserves at West Coast Power.

Enron Trade Credit Litigation. At the time of their bankruptcy filing in the fourth quarter 2001, Enron Corp. and its affiliates had net exposure to us, including certain liquidated damages and other amounts relating to the termination of commercial transactions among the parties, of approximately $84 million. This exposure, with respect to which we recognized a charge in our fourth quarter 2001 financial statements, was calculated by setting off approximately $230 million owed from Dynegy entities to Enron entities against approximately $314 million owed from Enron entities to Dynegy entities. The master netting agreement between Enron and us and the valuation of the commercial transactions covered by the agreement, which valuation is based principally on the parties’ assessment of market prices for such period, remain subject to dispute by Enron. We are engaged in an ongoing process with Enron to reconcile the differences between our respective valuations of the transactions and accounts receivable. As a result of recalculations of mark-to-market values of past transactions, we have reduced the amount that we believe we are owed by Enron to approximately $68 million, including the liabilities under the gas transportation agreement related to the Sithe Independence power tolling arrangement. As required by the master netting agreement, we instituted arbitration proceedings against those Enron parties not in bankruptcy in 2002 and filed a motion with the Bankruptcy Court requesting that we be allowed to proceed to arbitration against those Enron parties that are in bankruptcy. The Enron parties opposed our request and filed an adversary proceeding against us, alleging that the master netting agreement should not be enforced and that the Enron companies should recover approximately $230 million from us. We have disputed such allegations and are vigorously defending our position regarding the setoff rights contained in the master netting agreement, although the Bankruptcy Court has yet to rule on the enforceability of the master netting agreement.

In November 2003, we gave notice of our intent to pursue arbitration against Enron Canada Corp. as a non-bankrupt party to the master netting agreement. In response, Enron Canada Corp. filed a lawsuit in Canadian District Court to recover the amounts that it claims to be owed by our Canadian subsidiary under the master netting agreement, contingent upon a Bankruptcy Court ruling on the enforceability of the master netting agreement. In December 2003, Enron filed an application with the Bankruptcy Court for an injunction to prohibit this arbitration; the Bankruptcy Court ruled that the automatic stay of the bankruptcy applied to our request to pursue arbitration against Enron Canada Corp. under the master netting agreement. Consequently, we are currently prohibited from enforcing the master netting agreement by arbitration. In March 2004, we appealed the enforcement of the automatic stay and requested permission from the appellate court to proceed with arbitration against Enron Canada Corp. We also filed a motion with the Bankruptcy Court requesting a trial to determine the enforceability of the master netting agreement under the U.S. Bankruptcy Code. We are currently awaiting rulings on the appeal and the motion.

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If the setoff rights are modified or disallowed, either by agreement or otherwise, the amount available for our entities to set off against sums that might be due Enron entities could be reduced materially. In fact, we could be required to pay to Enron the full amount that it claims to be owed, while we would be an unsecured creditor of Enron to the extent of our claim. We cannot predict with certainty whether we will incur any liability in connection with these disputes. However, given the size of the claims at issue, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.

Trans-Elect Litigation. In October 2003, Trans-Elect, Inc. and Illinois Electric Transmission Company, LLC filed suit against Illinois Power Company in the Northern District of Illinois requesting specific performance and estoppel, and claiming damages as a result of breach of contract and lost profits. These causes of action allegedly arise from Illinois Power’s termination of an asset purchase and sale agreement entered into by the parties in October 2002. Under the terms of the agreement, Illinois Power agreed to sell its transmission assets to Trans-Elect if, on or before July 7, 2003, the agreement received the required FERC, ICC, SEC and Hart-Scott Rodino approvals. As of July 7, 2003, the agreement had not been approved by, among other entities, the FERC and, as a result, Illinois Power terminated the agreement in accordance with its terms on July 8, 2003. Trans-Elect claims that Illinois Power breached the agreement by failing to use its “best efforts” to obtain the required approvals and/or to negotiate an alternate agreement that could be approved. In April 2004, the plaintiffs amended their complaint to add Dynegy Inc. as a defendant, claiming that we tortiously interfered with the asset purchase and sale agreement. Trial has been scheduled in this matter for January 2005.

In April 2004, the plaintiffs also filed a separate lawsuit in Illinois state court against DHI, similarly claiming that DHI tortiously interfered with the Illinois Power asset purchase and sale agreement. We intend to file an answer to this claim in May 2004.

We deny these claims, in that we believe we complied with the terms of the agreement, and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or estimate the damages, if any, that might be incurred in connection with these lawsuits. However, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition or results of operations. Additionally, in connection with our proposed sale of Illinois Power to Ameren, we have retained this contingent liability and do not expect that the outcome will negatively impact our ability to close the sale.

Severance Arbitrations. Our former CEO, Chuck Watson, former President, Steve Bergstrom, and former CFO, Rob Doty, have each filed for arbitration pursuant to the terms of their employment/severance agreements. In each case, the parties disagree as to the amounts that may be owed pursuant to their respective agreements. These former officers made arbitration claims seeking payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. Their agreements are subject to interpretation and we believe that, with respect to the claims asserted by Messrs. Watson and Doty, the amounts owed are substantially lower than the amounts sought.

The arbitration relating to Mr. Bergstrom’s severance agreement was tried before a panel of three arbitrators in March 2004. In April 2004, the panel issued its decision with respect to his severance claim awarding Mr. Bergstrom approximately $10.4 million. We anticipate a decision on Mr. Bergstrom’s request for attorneys’ fees and interest in May 2004. The arbitrations with respect to Messrs. Watson and Doty are currently scheduled to commence in June and November 2004, respectively.

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We have taken severance accruals in amounts we consider reasonable relating to these proceedings. Please read Note 3—Restructuring Charges for further discussion regarding the accrual relating to Mr. Watson.

Farnsworth Litigation. In August 2002, Bradley Farnsworth filed a lawsuit against us in state court claiming breach of contract and that he was demoted and ultimately fired from the position of Controller for refusing to participate in illegal activities. Specifically, Mr. Farnsworth alleges, in the words of his amended complaint, that certain of our former executive officers requested that he “shave or reduce for accounting purposes” the forward price curves associated with the natural gas business in the United Kingdom for the period of October 1, 2000 through March 31, 2001, in order to indicate a reduction in our mark-to-market losses. Mr. Farnsworth, who seeks unspecified actual and exemplary damages and other compensation, also alleges that he is entitled to a termination payment under his employment agreement equal to 2.99 times the greater of his average base salary and incentive compensation for the highest three calendar years preceding termination or his base salary and target bonus amount for the year of termination (currently estimated at a range of approximately $700,000 to $1,200,000). In March 2004, the judge dismissed Mr. Farnsworth’s claim that he was asked to “shave” forward price curves. Trial on the claim concerning his employment agreement has been rescheduled for October 2004. We are vigorously defending this claim. Although we have recorded a reserve with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.

Apache Litigation. In May 2002, Apache Corporation filed suit in state court against Versado, as purchaser and processor of Apache’s gas, and DMS, as operator of the Versado assets in New Mexico, seeking more than $9 million in damages. The amended petition alleges that Versado engaged in “sham” transactions with affiliates, resulting in Versado not receiving fair market value when it sells gas and liquids, and that the formula for calculating the amount Versado receives from its buyers of gas and liquids is flawed since it is based on gas price indexes that these same affiliates are alleged to have manipulated by providing false price information to the index publisher. At trial, the jury found in favor of the plaintiff and awarded approximately $1.6 million in damages. We are awaiting a ruling from the court on a motion to set aside the judgment. Although we have recorded a reserve with respect to this litigation, we do not believe that any liability we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.

Gas Index Pricing Litigation. We are defending the following suits claiming damages resulting from the alleged manipulation of gas index publications and prices by us and others: Sierra Pacific Resources and Nevada Power Company v. El Paso Corp. et al.; Bustamante v. The McGraw Hill Companies et al.; In re Natural Gas Commodity Litigation; Texas-Ohio Energy Inc. et al. v. Centerpoint Energy et al; People of the State of Montana et al. v. Williams Energy Marketing et al; Benscheidt v. AEP Energy Services et al. In each of these suits, the plaintiffs allege that we and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to gas index publications, thereby manipulating the price. All of the complaints rely heavily on the FERC and CFTC investigations into and report concerning index-reporting manipulation in the energy industry. The plaintiffs generally seek unspecified actual and punitive damages relating to costs they claim to have incurred as a result of the alleged conduct. Our motion to dismiss the Sierra Pacific suit was granted. In April 2004, in response to a motion by the plaintiff, the court affirmed its dismissal of the original complaint but allowed plaintiff leave to file an amended complaint. We have not yet received the amended complaint. The other cases are in varying procedural stages, although we have not been served in the Montana case.

We are analyzing all of these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that might be incurred in

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connection with these lawsuits. We do not believe that any liability that we might incur as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.

Triad Litigation. In March 2003, Triad Energy Resources Corp. and five other alleged representatives of two plaintiffs’ classes filed a putative antitrust class action against NiSource Inc. and other defendants, including us, in federal district court. The plaintiffs purport to represent classes of purchasers, marketers, wholesalers, managers, sellers and shippers of natural gas that allegedly were damaged by an illegal gas scheme devised by three federally regulated interstate pipeline systems which are now owned by NiSource, and certain shippers on these pipelines. It alleges that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate, in violation of FERC regulations, and in return for percentages of the profits reaped by the marketing affiliate. The complaint also alleges that certain shippers, including us, having learned of these preferential arrangements, demanded and received similar preferential storage and transportation services that were not available to all shippers.

Although this alleged scheme was the subject of an October 2000 FERC order, which required the Columbia companies to pay $27.5 million to certain customers of Columbia Gas and Columbia Gulf, plaintiffs claim that the FERC order did not remedy the competitive injury to plaintiffs caused by the scheme. The complaint seeks aggregate damages of approximately $1.716 billion, which damages are subject to trebling under federal antitrust laws. In October 2003, the court granted defendants’ motion to dismiss for lack of jurisdiction and allowed time for the plaintiffs to amend their complaint. The plaintiffs have since filed a motion to voluntarily dismiss their complaint and indicated an intent to refile in a proper jurisdiction, although plaintiffs have not yet re-filed. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or estimate the damages, if any, that we might incur in connection with this lawsuit.

Atlantigas Corp. Litigation. In November 2003, Atlantigas Corporation filed a suit similar to Triad in Maryland against us and several other defendants alleging certain conspiracies between natural gas shippers and storage facilities. The complaint seeks unspecified compensatory and punitive damages. In addition, we are alleged to have conspired with the other defendants to receive preferential natural gas storage and transportation services at off-tariff prices. Defendants are currently challenging plaintiff on the threshold issues of standing, statute of limitations and jurisdiction. These issues were fully briefed in February 2004 and a hearing date has been requested but not scheduled. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability or to estimate the damages, if any, that we might incur in connection with this lawsuit.

Maxus Litigation. In April 2001, in the case of Natural Gas Clearinghouse v. Midgard Energy, formerly known as Maxus Exploration Co., a Texas district court found us liable for failing to deliver processable “wet” gas to a Maxus processing plant. Following our appeal of the judgment, we filed an expedited writ with the Texas Supreme Court seeking further review, which was denied in April 2004. We paid the judgment of approximately $6.9 million dollars in April 2004, against which we had recorded a reserve.

Stumpf Litigation. We and two former subsidiaries are defendants in a lawsuit filed in New York by Stumpf AG and two of its affiliates stemming from the shutdown of our Vienna telecommunications office in the spring of 2001. The plaintiffs are seeking $29 million in compensatory and unspecified punitive damages, alleging breach of contract, tortious interference and alter ego-based claims primarily relating to the termination of real property leases to which our former Austrian subsidiary was a party. These claims are based on similar lawsuits

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filed in Austria against our former Austrian subsidiary, which was sold to a third party in January 2003. This former subsidiary is in liquidation and, recently, one of its liquidators admitted or is prepared to admit for purposes of the liquidation the plaintiffs’ claims in the amount of $30 million. Although these Austrian lawsuits are stayed as a result of the liquidation, the outcome of the liquidation could impact the New York lawsuit. We intend to oppose these claims vigorously and believe we have meritorious defenses. Although it is not possible to predict with certainty whether we will incur any liability in connection with these lawsuits, we do not believe that any liability we might incur as a result of these lawsuits would have a material adverse effect on our financial condition or results of operations. We have recorded a reserve in connection with this litigation.

Alleged Marketing Contract Defaults. We have posted collateral to support a substantial portion of our obligations in our CRM business, including our obligations under power tolling arrangements. While we worked with various counterparties to provide mutually acceptable collateral or other adequate assurance under these contracts, we have not reached agreement with Sithe Independence and Sterlington/Quachita Power LLC regarding a mutually acceptable amount of collateral in support of our obligations under our power tolling arrangements with either of these two parties. Although we are current on all contract payments to these counterparties, we previously received a notice of default from each such party with regard to collateral. Despite receiving these notices, all parties are continuing to perform and we have fulfilled our economic commitments under these contracts. Our average annual capacity payments under these two arrangements approximate $75 million and $63 million, respectively, and the contracts extend through 2014 and 2012, respectively, with a five-year extension option for Sterlington. If these two parties were successfully to pursue claims that we defaulted on these contracts, they could declare a termination of their respective contracts, which provide for termination payments based on the agreed mark-to-market value of the contracts. Because of the effects of changes in commodity prices on the mark-to-market value of these contracts, as well as the likelihood that we would differ with our counterparties as to the estimated value of these contracts, we cannot predict with any degree of certainty the amounts of termination payments that could be required under these two contracts. Disputes relating to these two contracts, if resolved against us, could materially adversely affect our financial condition, results of operations and cash flows.

U.S. Attorney Investigations. The U.S. Attorney’s office in Houston is continuing its investigation of our actions relating to Project Alpha and our gas trade reporting practices. We have produced documents and witnesses for interviews in connection with this investigation. Seven of our natural gas traders were terminated in the fourth quarter 2002 for violating our Code of Business Conduct after an ongoing internal investigation conducted by our Audit and Compliance Committee in collaboration with independent counsel discovered that inaccurate information regarding natural gas trades had been reported to various energy industry publications. In January 2003, one of our former natural gas traders was indicted in Houston on three counts of knowingly causing the transmission of false trade reports used to calculate the index price of natural gas and four counts of wire fraud. In August 2003, however, several of these counts were dismissed as unconstitutional. Upon request by the U.S. Attorney’s office for reconsideration of this ruling, the judge reinstated the dismissed counts. The case was originally set for trial in January 2004; however, both the U.S. Attorney’s office and the defense have appealed the court’s rulings regarding the dismissed and reinstated charges. The appeals are pending and a new trial date has not been set.

In June 2003, three former Dynegy employees were indicted on charges of conspiracy, securities fraud and mail and wire fraud related to the Project Alpha transaction. Subsequently, two of these former employees pleaded guilty to conspiracy to commit securities fraud and are scheduled to be sentenced in August 2004. Trial on the indictment against the third employee was held in November 2003, and the defendant was convicted on all charges. In March 2004, this defendant was sentenced to a term of approximately 24 years in federal prison.

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We are cooperating fully with the U.S. Attorney’s office in its continuing investigation of these matters and cannot predict the ultimate outcome of these investigations.

Additionally, the United States Attorney’s office in the Northern District of California has issued a Grand Jury subpoena requesting information related to our activities in the California energy markets in November 2002. We have been, and intend to continue, cooperating fully with the U.S. Attorney’s office in its investigation of these matters, including production of substantial documents responsive to the subpoena and other requests for information. We cannot predict the ultimate outcome of this investigation.

Department of Labor Investigation. In August 2002, the U.S. Department of Labor commenced an official investigation pursuant to Section 504 of ERISA with respect to the benefit plans we maintain and our ERISA affiliates. We have cooperated with the Department of Labor throughout this investigation, which remains ongoing. As of this date, the investigation has focused on a review of plan documentation, plan reporting and disclosure, plan recordkeeping, plan investments and investment options, plan fiduciaries and third-party service providers, plan contributions and other operational aspects of the plans. We have not yet received the Department of Labor’s definitive findings resulting from its investigation.

Note 10—Regulatory Issues

We are subject to regulation by various federal, state, local and foreign agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations. In addition, the United States Congress has before it a number of bills that could impact regulations or impose new regulations applicable to us and our subsidiaries. We cannot predict the outcome of these bills or other regulatory developments or the effects that they might have on our business.

Note 11—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans, which are more fully described in Note 20—Employee Compensation, Savings and Pension Plans beginning on page F-74 of our Form 10-K/A.

Components of Net Periodic Benefit Cost. The components of net periodic benefit cost were:


	Pension Benefits						Other Benefits
	Quarter Ended March 31,
	2004			2003			2004			2003
	(in millions)
Service cost benefits earned during period	$	6		$	5		$	1		$	1
Interest cost on projected benefit obligation		10			10			3			3
Expected return on plan assets		(12	)		(13	)		(1	)		(1	)
Recognized net actuarial loss		4			2			1			1

Total net periodic benefit cost	$	8		$	4		$	4		$	4

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Contributions. In our Form 10-K/A, we reported that we expected to contribute approximately $13 million to our pension and other postretirement benefit plans in 2004. However, due to the Pension Funding Equity Act of 2004, we will no longer be required to make estimated quarterly contributions in 2004. However, under the terms of the sale of Illinois Power to Ameren, we will be required to accelerate approximately $15 to $20 million of future cash funding requirements at closing, which we expect will occur before the end of 2004.

Note 12—Segment Information

Amounts in this footnote have been restated. For further information, please see the Explanatory Note beginning on page 9.

We report our operations in the following segments: GEN, NGL, REG and CRM. All direct general and administrative expenses incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred. Other income (expense) items incurred by us on behalf of our subsidiaries are allocated directly to the four segments.

Pursuant to EITF Issue 02-03, all gains and losses on third-party energy-trading contracts in the CRM segment, whether realized or unrealized, are presented net in the unaudited condensed consolidated statements of operations. For the purpose of the segment data presented below, intersegment transactions between CRM and our other segments are presented net in CRM intersegment revenues but are presented gross in the intersegment revenues of our other segments, as the activities of our other segments are not subject to the net presentation requirements contained in EITF Issue 02-03. If transactions between CRM and our other segments result in a net intersegment purchase by CRM, the net intersegment purchases and sales are presented as negative revenues in CRM intersegment revenues. In addition, intersegment hedging activities are presented net pursuant to SFAS No. 133.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Reportable segment information for the three-month periods ended March 31, 2004 and 2003 is presented below.

Dynegy’s Segment Data for the Quarter Ended March 31, 2004

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	48		$	831		$	452		$	370		$	—		$	1,701
Other		—			—			—			(44	)		—			(44	)

		48			831			452			326			—			1,657
Intersegment revenues		393			70			5			(348	)		(120	)		—

Total revenues	$	441		$	901		$	457		$	(22	)	$	(120	)	$	1,657

Depreciation and amortization	$	(48	)	$	(20	)	$	(10	)	$	—		$	(10	)	$	(88	)

Operating income (loss)	$	53		$	67		$	54		$	(13	)	$	(53	)	$	108
Earnings from unconsolidated investments		38			2			—			—			—			40
Other items, net		—			(4	)		1			3			11			11
Interest expense																	(132	)

Income from continuing operations before taxes																	27
Income tax benefit																	29

Income from continuing operations																	56
Income from discontinued operations, net of taxes																	14

Net income																$	70

Identifiable assets:
Domestic	$	6,306		$	1,669		$	4,949		$	2,377		$	(2,674	)	$	12,627
Other		46			1			—			189			30			266

Total	$	6,352		$	1,670		$	4,949		$	2,566		$	(2,644	)	$	12,893

Unconsolidated investments	$	529		$	82		$	—		$	—		$	—		$	611

Capital expenditures	$	(14	)	$	(9	)	$	(28	)	$	—		$	(2	)	$	(53	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited and Restated)

For the Interim Periods Ended March 31, 2004 and 2003

Dynegy’s Segment Data for the Quarter Ended March 31, 2003

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	117		$	978		$	455		$	320		$	—		$	1,870
Other		—			—			—			9			—			9

		117			978			455			329			—			1,879
Intersegment revenues		287			73			8			(238	)		(130	)		—

Total revenues	$	404		$	1,051		$	463		$	91		$	(130	)	$	1,879

Depreciation and amortization	$	(42	)	$	(20	)	$	(30	)	$	(1	)	$	(22	)	$	(115	)
Operating income (loss)	$	83		$	51		$	59		$	38		$	(44	)	$	187
Earnings from unconsolidated investments		39			3			—			11			—			53
Other items, net		3			(5	)		—			26			(3	)		21
Interest expense																	(110	)

Income from continuing operations before taxes																	151
Income tax expense																	(56	)

Income from continuing operations																	95
Loss on discontinued operations, net of taxes																	(3	)
Cumulative effect of change in accounting principles, net of taxes																	55

Net income																$	147

Identifiable assets:
Domestic	$	6,568		$	1,804		$	5,582		$	4,808		$	(2,111	)	$	16,651
Other		—			—			—			725			(80	)		645

Total	$	6,568		$	1,804		$	5,582		$	5,533		$	(2,191	)	$	17,296

Unconsolidated investments	$	598		$	98		$	—		$	14		$	—		$	710

Capital expenditures	$	(37	)	$	(12	)	$	(32	)	$	—		$	(3	)	$	(84	)

Note 13—Subsequent Events

In April 2004, we announced an agreement to settle numerous FERC claims relating to transactions we conducted in the western electric markets, including California, between January 2000 and June 2001. Please read Note 9—Commitments and Contingencies—FERC and Related Regulatory Investigations—Requests for Refunds for further discussion.

Also in April 2004, we sold our minority interests in the Indian Basin gas processing plant and a 20 MW power generating facility located in Costa Rica. Please see Note 2—Dispositions and Discontinued Operations for further discussion.

In May 2004, we announced the launch of a new $1.3 billion credit facility. The new facility is intended to replace our current $1.1 billion revolving credit facility, which is scheduled to mature in February 2005. We expect that the new facility will have a term loan component as well as a revolving credit component, with respect to which we have received $625 million in aggregate commitments from the lead arrangers. The increased size of the new facility, which is targeted to close in the second quarter 2004, would be used to repay existing higher-cost debt and for general corporate purposes.

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended March 31, 2004 and 2003

Item 2—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read together with the unaudited condensed consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Form 10-K. As discussed in the Introductory Note to this Amendment No. 2, the financial information contained in this Form 10-Q/A has been revised to reflect the restatement items described in the Explanatory Note to the accompanying unaudited condensed consolidated financial statements. We have also amended our 2003 Annual Report on Form 10-K, most recently with Amendment No. 2 thereto filed with the SEC on January 18, 2005. The restatements to the financial statements contained in the Form 10-K and related information are further described in the Form 10-K/A, and this Amendment No. 2 should be read together with the Form 10-K/A.

GENERAL

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.

Since the filing of our Form 10-K, we have continued our efforts to restructure our company while maintaining our focus on safe, reliable and efficient operations. These restructuring efforts included the completion of regulatory filings and other matters required to consummate the previously announced sale of Illinois Power to Ameren, which we expect will occur before the end of 2004, and sales of or agreements to sell non-core assets in our GEN and NGL businesses. These actions are expected to enable us to further reduce our substantial indebtedness and further align our asset base with our business strategy. We also have announced the launch of a new $1.3 billion credit facility. The new facility is intended to replace our current $1.1 billion revolving credit facility, which is scheduled to mature in February 2005. We expect that the new facility will have a term loan component as well as a revolving credit component, with respect to which we have received $625 million in aggregate commitments from the lead arrangers. The increased size of the new facility, which is targeted to close in the second quarter 2004, would be used to repay existing higher-cost debt and for general corporate purposes.

Operationally, our first quarter 2004 performance reflected our continued sensitivity to commodity prices, particularly in our unregulated energy businesses. A significant decline in power prices negatively impacted our GEN business, more than offsetting an increase in volumes due primarily to additional run-time resulting from the dual-fuel capabilities of our Roseton facility in New York. In our NGL business, our restructured gas processing contract portfolio yielded higher field processing plant margins upstream despite lower natural gas prices. Downstream, our marketing results declined due primarily to less volatility in natural gas liquids prices quarter over quarter and a continued reduction in overall market liquidity. Please read “—Results of Operations” for further discussion of the comparative results of our reportable business segments.

LIQUIDITY AND CAPITAL RESOURCES

Overview

As of May 3, 2004, we had cash on hand of $438 million and available borrowing capacity of $887 million, for total liquidity of $1.3 billion. Our ability to maintain our liquidity position in the future will depend on a number of factors, including our ability to consummate non-core asset sales, including 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. Please read “—Conclusion” for further discussion.

Debt Maturities

During the first quarter 2004, we used cash on hand, including proceeds from asset sales, to reduce our outstanding debt as follows:

•

$95 million in payments on a series of maturing Illinova senior notes;

•

$22 million in payments on Illinois Power’s transitional funding trust notes;

•

$19 million in payments on the ABG Gas Supply financing; and

•

$1 million in principal payments on the ChevronTexaco junior notes.

Our aggregate maturities for long-term debt as of March 31, 2004, including the current portion, were approximately $6.1 billion, approximately $1.9 billion of which was Illinois Power debt. If the Ameren transaction closes as expected before the end of 2004, Ameren will assume Illinois Power’s then outstanding debt at closing. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt Maturities” beginning on page 7 of our Form 10-K/A for a schedule of our aggregate debt maturities, including Illinois Power’s debt maturities, through 2008 and thereafter.

Through our restructuring efforts we have extended a substantial portion of our debt maturities to 2008 and beyond. 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, as of May 3, 2004, we had $189 million in letters of credit issued under the facility in support of our collateral obligations. 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. Please read “—Revolver Capacity” for further discussion of this facility and our ongoing efforts to restructure it in advance of its scheduled maturity.

Our restructuring efforts have also resulted in significantly increased cash and financial interest expenses, as further described below under “—Results of Operations—Interest Expense.” These increased interest expenses will continue to impact our financial condition and liquidity position until the related debt obligations are

satisfied. We also are subject to the more restrictive covenants that are contained in the related transaction agreements, including covenants limiting our ability to incur additional debt and requiring that a significant portion of proceeds from specified asset sales and equity issuances be used to pay down outstanding indebtedness. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Debt Maturities” beginning on page 7 of our Form 10-K/A for a discussion of these covenants. We are currently in compliance with these restrictive covenants and, as further described in “—Revolver Capacity” below, anticipate more flexible covenants in the restructured credit facility that we are currently pursuing. Our future financial condition and results of operations could be materially adversely affected by our ability to execute our business and financial strategies within the confines of the restrictive covenants contained in our financing agreements.

Collateral Postings

We have substantially reduced our collateral postings since commencing our exit from the customer risk management business in late 2002. However, we continue to use a significant portion of our capital resources, in the form of cash and letters of credit, to satisfy counterparty collateral demands. The following table summarizes our consolidated collateral postings to third parties by operating division at May 3, 2004, March 31, 2004 and December 31, 2003:


	May 3, 2004		March 31, 2004		December 31, 2003
	(in millions)
GEN	$	156	$	155	$	136
CRM		188		164		121
NGL		141		159		179
REG		27		25		38
Other		7		9		8

Total	$	519	$	512	$	482

The increase in collateral postings during the first quarter 2004 was due primarily to $22.5 million in cash collateral posted in connection with an existing CRM gas transaction, as well as changes in commodity prices. The increase in collateral postings since the end of the first quarter 2004 relates primarily to the CRM segment, as we are now posting approximately $17 million in additional collateral to support fuel purchases relating to the Sithe tolling arrangement and a legacy gas transaction in our Canadian CRM business. We anticipate that these additional collateral requirements could continue through the end of 2004.

Going forward, we expect counterparties’ collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views 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 remainder of 2004. Over the longer term, we expect to achieve incremental reductions associated with the completion of our exit from the CRM business. Please see “—Results of Operations—2004 Outlook—CRM Outlook” below for a discussion of the expected collateral roll-off from this business.

Disclosure of Contractual Obligations and Contingent Financial Commitments

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

Our contractual obligations and contingent financial commitments have changed since December 31, 2003, with respect to which information is included in our Form 10-K/A. In February 2004, we terminated our conditional purchase obligation related to 14 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, was provided as consideration for the termination. Therefore, our conditional purchase obligations of $766 million as reported on page 11 of our Form 10-K/A have been reduced by approximately $5 million in 2004, $144 million in 2005, $193 million in 2006, $113 million in 2007 and $24 million in 2008. There were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2003.

Dividends on Preferred and Common Stock

Dividend payments on our common stock are at the discretion of our Board of Directors. We did not declare or pay a dividend for the first quarter 2004 and 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 of our Form 10-K/A for a discussion of the dividend restrictions contained in our financing agreements.

We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. 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—Series C Convertible Preferred Stock beginning on page F-53 of our Form 10-K/A 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 $167 million in the three months ended March 31, 2004. Please read “—Results of Operations—Operating Income” and “—Cash Flow Disclosures” for a discussion of the primary factors impacting these operating cash flows.

As described above, much of our restructuring work has extended our significant debt maturities to 2008 and beyond, positioning us to benefit from the 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 our NGL business. Please read Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Form 10-K for a discussion of our current views on supply and demand in the regions where our power generation business operates. Please also read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Internal Liquidity Sources—Cash Flows from Operations” beginning on page 16 of our Form 10-K/A for a discussion of our expectations regarding the financial impact of the expected recovery.

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 power purchase agreement. With respect to costs, in January 2004 we entered into a new rail transportation contract that we anticipate will reduce the fees associated with fuel procurement at our coal-fired generation facilities; however, in the first quarter 2004, these fee reductions were substantially offset by increased coal prices and higher costs associated with the purchase of emission credits. Our ability to achieve fuel-related and other targeted cost savings from our previously disclosed

value creation project, a company-wide initiative focused on identifying opportunities to improve our operational efficiencies, in the face of industry-wide increases in labor and benefits costs, together with changes in commodity prices, 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. We are actively pursuing a renewal or replacement of this agreement; however, we cannot make any assurances that an agreement can be reached on the same or similar terms, if at all. If we are unable to renew or replace this agreement, we will seek to sell the associated energy and capacity through other long-term arrangements or into the open market, where our operating cash flows would be dependent on then prevailing market prices and the market for capacity in California. Because we expect that the generating facilities supporting the CDWR contract would be significantly less profitable as merchant facilities, we may consider other alternatives if we are unable to enter into a renewal or replacement agreement, including shutting down one or more units if we no longer consider them commercially viable. Please read “—Results of Operations—2004 Outlook—GEN Outlook” for further discussion of the CDWR agreement and the anticipated impairments relating to its scheduled expiration.

Cash on Hand. At May 3, 2004 and March 31, 2004, we had cash on hand of $438 million and $464 million, respectively. We intend to continue our disciplined cash management practices in an attempt to maintain our cash position. However, unforeseen events such as legal judgments or regulatory requirements, as well as litigation settlements or contract terminations, could negatively impact our ability to continue 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 May 3, 2004, we had $189 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. In May 2004, we announced the launch of a new $1.3 billion credit facility. The new facility is intended to replace our current $1.1 billion revolving credit facility, which is scheduled to mature in February 2005. We expect that the new facility will have a term loan component as well as a revolving credit component, with respect to which we have received $625 million in aggregate commitments from the lead arrangers. The increased size of the new facility, which is targeted to close in the second quarter 2004, would be used to repay existing higher-cost debt and for general corporate purposes. We expect that the new facility would provide more flexible covenants, lower interest costs and a longer maturity than our current facility. However, changes in market conditions or other factors beyond our control could prevent us from closing on the new facility within the timeframe, at the level and on the terms and conditions expected, if at all.

Current Liquidity. The following table summarizes our consolidated credit capacity and liquidity position at May 3, 2004, March 31, 2004 and December 31, 2003:


	May 3, 2004			March 31, 2004			December 31, 2003
	(in millions)
Total Revolver Capacity	$	1,076	(1)	$	1,088	(1)	$	1,100
Outstanding Loans		—			—			—
Outstanding Letters of Credit Under Revolving Credit Facility		(189	)		(208	)		(188	)

Unused Revolver Capacity		887			880			912
Cash (2)		438	(3)		464	(3)		477

Total Available Liquidity	$	1,325	(4)	$	1,344	(4)	$	1,389

(1)	The May 3, 2004 and March 31, 2004 amounts reflect $24 million and $12 million, respectively, of mandatory reductions of our revolving credit facility related to asset sales and dividend payments on the Series C preferred stock.

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

(3)	The May 3, 2004 and March 31, 2004 amounts include approximately $48 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.

(4)	Includes approximately $125 million and $97 million, respectively, of liquidity at Illinois Power. Please read Item 1. Business—Regulation beginning on page 21 of our Form 10-K for a discussion of ICC regulations that restrict our ability to receive cash dividends from Illinois Power.

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. 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 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 approvals and other closing conditions, we would receive approximately $400 million in cash, subject to working capital adjustments, and Ameren would deposit $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 Events beginning on page F-86 of our Form 10-K/A for further discussion of this transaction.

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 domestic and international power generation facilities, which domestic facilities are detailed in Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Form 10-K, as well as our minority ownership interests in one or more upstream or downstream NGL facilities. Since December 31, 2003, we have sold or entered into definitive agreements to sell the following assets:

•

In January 2004, we sold our interest in a 74 MW power generating facility located in Jamaica for approximately $5.5 million in net aggregate cash proceeds.

•

In March 2004, we sold our remaining financial interest in the Hackberry LNG project for approximately $17 million in net cash proceeds.

•

In April 2004, we sold our interest in the Indian Basin Gas Processing Plant for approximately $48 million in net cash proceeds.

•

In April 2004, we sold our interest in a 20 MW wind-powered electric power generation facility located in Costa Rica for approximately $11 million in net cash proceeds.

•

In February 2004, we entered into definitive agreements to sell our 50% interests in the 424 MW Oyster Creek power generating facility and the 123 MW Michigan Power power generating facility. The two transactions are expected to generate aggregate net cash proceeds of approximately $103 million and are targeted to close in the second quarter 2004, in each case subject to receipt of required lender and counterparty consents and other closing conditions.

Generally, the aggregate projected loss of earnings in 2004 associated with these assets is not considered material and is expected to be more than offset by net gains on sale in 2004.

Our desire or ability to effect these or any other non-core asset sales is subject to a number of factors, many of which are beyond our control, including the market for the assets and investments being considered, the receipt of any regulatory and other approvals that may be required and the willingness of lenders and other counterparties to consent to a proposed transaction. Accordingly, we cannot guarantee that the pending sales or any other sales will be consummated or that the expected proceeds will be received. In addition, if the sales are consummated, we are required to use the proceeds in accordance with the restrictive covenants contained in our financing agreements. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—External Liquidity Sources—Asset Sale Proceeds” beginning on page 18 of our Form 10-K/A for a discussion of the required use of proceeds under our current financing agreements.

We discuss and evaluate merger and acquisition activities as part of our ongoing business strategy. In the power generation industry, in particular, we believe that consolidation is likely to occur in the next several years. We further believe that our efficient and scalable operations platform, together with our multi-fuel capabilities and multi-region presence, position us to benefit from opportunities that might arise in connection with any consolidation transactions. However, as indicated above, our desire or ability to participate in any such transactions is subject to a number of factors beyond our control. As such, we cannot guarantee that any such transactions will occur, nor can we predict with any degree of certainty the impact of any such transactions on our financial condition or results of operations.

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, each of which is subject to cyclical changes in commodity prices, we have previously indicated our intent to explore additional capital-raising transactions both in the near- and long-term. These transactions may 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 by these factors 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 contained in our financing agreements. Please read Note 12—Debt—DHI Credit Facility beginning on page F-42 of our Form 10-K/A for further discussion.

Conclusion

For the rest of 2004, 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. However, we believe that our cash on hand, together with proceeds from anticipated asset sales and capacity under our revolving credit facility, will be sufficient to discharge 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. 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.

Our liquidity position and financial condition will be materially affected by a number of factors, including our ability to consummate non-core asset sales, including 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 and

commercial obligations, including increased 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. Additionally, although depressed frac spreads (i.e., the relationship between prices for natural gas and natural gas liquids) 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 adversely 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.

FACTORS AFFECTING FUTURE RESULTS OF OPERATIONS

In “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview” beginning on page 4 of our Form 10-K/A, we detailed the primary factors that have impacted, and are expected to continue to impact, the earnings and cash flows from our business segments and other operations. Our results of operations during the remainder of 2004 and beyond may be significantly affected by any or all of these factors, including the following factors in particular:

•

Changes in commodity prices, including the relationships between prices for power and natural gas or other power generating fuels, commonly referred to as the “spark spread” or “dark spread” depending on the fuel type, and the frac spread;

•

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;

•

The impact of reduced market liquidity and counterparty collateral demands on our ability to sell our energy products through forward sales or similar transactions;

•

Our ability to address the substantial long-term payment obligations associated with our four remaining power tolling arrangements, the restructuring or termination of one or more of which likely would require a significant cash payment; and

•

The impact of increased interest expense primarily attributable to our recent restructuring and refinancing transactions and our non-investment grade credit ratings.

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

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 the three-month periods ended March 31, 2004 and 2003. At the end of this section, we have included our 2004 outlook for each segment.

We report our operations in the following segments: GEN, NGL, REG and CRM. Other reported results include corporate overhead and our discontinued communications business. All direct general and administrative expenses incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred. Other income (expense) items incurred by us on behalf of our subsidiaries are charged directly to the four segments.

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for the three-month periods ended March 31, 2004 and 2003, respectively. This financial data has been restated to reflect the impact of the items described in the Explanatory Note to the unaudited condensed consolidated financial statements. The restatements relate to increased and additional impairments 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.

Quarter Ended March 31, 2004


	GEN		NGL			REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	53	$	67		$	54	$	(13	)	$	(53	)	$	108
Earnings from unconsolidated investments		38		2			—		—			—			40
Other items, net		—		(4	)		1		3			11			11
Interest expense															(132	)

Income from continuing operations before taxes															27
Income tax benefit															29

Income from continuing operations															56
Income from discontinued operations, net of taxes															14

Net income														$	70


Quarter Ended March 31, 2003

	GEN		NGL			REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	83	$	51		$	59	$	38		$	(44	)	$	187
Earnings from unconsolidated investments		39		3			—		11			—			53
Other items, net		3		(5	)		—		26			(3	)		21
Interest expense															(110	)

Income from continuing operations before taxes															151
Income tax expense															(56	)

Income from continuing operations															95
Loss on discontinued operations, net of taxes															(3	)
Cumulative effect of change in accounting principles, net of taxes															55

Net income														$	147

The following table provides summary segmented operating statistics for the three months ended March 31, 2004 and 2003, respectively:


	Quarter Ended March 31,
	2004		2003
Power Generation
Million megawatt hours generated—gross		10.6		9.9
Million megawatt hours generated—net		10.1		9.4
Average natural gas price—Henry Hub ($/MMbtu) (1)	$	5.61	$	6.30
Average on-peak market power prices ($/MW hour)
Cinergy	$	42	$	50
Commonwealth Edison	$	41	$	48
Southern	$	43	$	49
New York—Zone G	$	64	$	75
ERCOT	$	41	$	47

Natural Gas Liquids
Gross NGL production (MBbls/d):
Field plants		57.9		56.0
Straddle plants		23.9		26.8

Total gross NGL production		81.8		82.8

Natural gas (residue) sales (Bbtu/d)		217.1		209.5

Natural gas inlet volumes (MMCFD):
Field plants		566.4		567.6
Straddle plants		867.4		1,394.2

Total natural gas inlet volumes		1,433.8		1,961.8

Fractionation volumes (MBbls/d)		185.0		175.5
Natural gas liquids sold (MBbls/d)		301.4		364.3
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	34.77	$	34.43
Natural gas—Henry Hub ($/MMbtu) (2)	$	5.69	$	6.61
Natural gas liquids ($/Gal)	$	0.62	$	0.62
Fractionation spread ($/MMBtu)—daily	$	1.39	$	0.67

Regulated Energy Delivery
Electric sales in KWH (millions)
Residential		1,455		1,433
Commercial		1,054		1,058
Industrial		1,320		1,405
Transportation of customer-owned electricity		629		549
Other		98		99

Total electric sales		4,556		4,544

Gas sales in Therms (millions)
Residential		160		185
Commercial		58		72
Industrial		19		23
Transportation of customer-owned gas		69		65

Total gas delivered		306		345

Heating degree days—Actual (3)		2,708		2,935
Heating degree days—10-year rolling average		2,678		2,587

(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 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 2004 tax item, affecting net income for the periods presented.


	Quarter Ended March 31, 2004
	GEN		NGL		REG			CRM			Other			Total
	(in millions)
Discontinued operations	$	—	$	—	$	—		$	17		$	3		$	20
Gain on sale of Hackberry LNG		—		17		—			—			—			17
Loss on anticipated sale of Illinois Power		—		—		(21	)		—			—			(21	)
Legal and severance reserves		2		—		(2	)		—			(15	)		(15	)
Taxes		—		—		—			—			39			39

Total	$	2	$	17	$	(23	)	$	17		$	27		$	40


	Quarter Ended March 31, 2003
	GEN		NGL		REG			CRM			Other			Total
	(in millions)
Discontinued operations	$	—	$	—	$	—		$	(15	)	$	2		$	(13	)
Cumulative effect of change in accounting principles		47		—		(3	)		43			—			87

Total	$	47	$	—	$	(3	)	$	28		$	2		$	74

Operating Income

Operating income was $108 million for the quarter ended March 31, 2004, compared to $187 million for the quarter ended March 31, 2003.

GEN. Operating income for the GEN segment was $53 million for the quarter ended March 31, 2004, compared to $83 million for the quarter ended March 31, 2003. Operating income in 2004 included a $26.5 million decrease related to pricing and a $14.9 million increase due to generated volumes versus 2003. The decrease related to pricing includes the mark-to-market effects of changes in the fair value of derivative contracts not accounted for as hedges, as further discussed below. Higher demand in the Midwest and Northeast regions because of colder than normal weather conditions during the first quarter 2003 that did not re-occur in the first quarter of this year resulted in significantly lower average prices in 2004. Average on-peak prices in the Midwest and Northeast regions during the first quarter 2004 decreased 13 percent and 15 percent, respectively. The earnings from our peaking generation facilities, which include both capacity and energy sales, continued to be unfavorably impacted by compressed natural gas spark spreads and overcapacity in the generation marketplace in the first quarter 2004.

Aggregate volumes were 8% higher quarter over quarter. The net MWh generated in the Midwest during the first quarter 2004 remained flat relative to the same period in 2003 at 5.5 million MWh. However, the Northeast produced 2.3 million MWh in 2004 compared to 1.4 million MWh in 2003. Higher volumes in the Northeast resulted primarily from Roseton’s dual fuel capability and increased run time due to the favorable spread between fuel oil and natural gas prices.

The decrease in operating income in the first quarter 2004 also reflects the loss of approximately $6 million of capacity revenues in the Southeast region related to a contract that expired at the end of 2003. Depreciation and amortization expense increased approximately $6 million quarter over quarter, largely due to the completion of the Rolling Hills facility in June 2003. Additionally, the first quarter 2004 includes an increase of approximately $5 million in operating expenses over the first quarter 2003 due to the timing of expenditures and an increase in generated volumes.

GEN’s reported operating income for the 2004 and 2003 periods includes approximately $3.5 million and $13.4 million, respectively, of mark-to-market income related to derivative contracts that did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market basis.

In March 2004, we tested our CoGen Lyondell facility for an impairment based on the identification of a triggering event as defined by SFAS No. 144. After performing the test, we concluded that no impairment was necessary as the estimated undiscounted cash flows exceeded the book value of the facility.

NGL. Operating income for the NGL segment was $67 million for the quarter ended March 31, 2004, compared to $51 million for the quarter ended March 31, 2003. Operating income for the first quarter 2004 included a $17 million gain associated with the sale of our remaining financial interest in the Hackberry LNG project; operating income for the first quarter 2003 included a $2.5 million gain associated with the expiration of an environmental guarantee. Please see Note 2—Dispositions and Discontinued Operations for further discussion. Also, please read Item 1. Business—Segment Discussion—Natural Gas Liquids beginning on page 7 of our Form 10-K for a detailed description of the NGL segment, including its contract portfolio.

While overall profitability of the NGL segment was relatively flat quarter over quarter, we experienced higher results in our gathering and gas processing assets and lower results in our wholesale marketing and marketing businesses as compared to 2003.

Gathering and processing experienced 14% lower absolute commodity prices for natural gas and approximately the same price for natural gas liquids in the first quarter 2004. Frac spreads increased quarter over quarter but continued to be lower than required to support liquids extraction under keep whole processing contracts. The shift from approximately 85% percentage of proceeds and 15% keep whole contracts to almost 98% percentage of proceeds contracts contributed to a 7% increase in processing plant margins at our field plants even in the current lower commodity price environment. Net natural gas liquids production declined and natural gas net to our account increased as compared to 2003 due to the difference in settlement terms between the two types of contracts. Gross natural gas liquids production for field plants increased by 3% quarter over quarter, primarily due to increased production in the highly active drilling area in North Texas.

Processing margins at our straddle plants were 33% lower and liquids volumes produced were 11% lower than in 2003. Frac spreads in 2004 increased to $1.39, up from $0.67 in 2003. Even at this higher frac spread, it is still not profitable to recover liquids in most cases. Straddle plant volumes declined year-on-year as fewer interstate pipelines enforced operational flow orders to control hydrocarbon quality specifications in 2004 compared to 2003.

In our downstream business, volumes available for fractionation increased slightly to 185.0 MBbls/d in 2004 versus 175.5 MBbls/d in 2003. Volumes increased at both our Mont Belvieu and Lake Charles plants. Higher import volumes benefited Mont Belvieu, and we saw more volume at our Lake Charles fractionator as a third-party processing plant that feeds our fractionator resumed processing.

In our wholesale marketing operations, results were materially the same quarter over quarter. We again experienced strong weather-driven propane sales in our market areas in the first quarter 2004 and comparable natural gas liquids commodity prices on contracts where we retain a percentage of the sales price as a fee for marketing natural gas liquids on behalf of others, such as in our refinery services agreements. Our marketing results declined from prior period levels as the same period of 2003 experienced high volatility and a strong and steady increase in natural gas liquids prices resulting in high margins throughout the quarter, while this year prices were relatively stable during the quarter. We continue to be impacted negatively due to reduced overall market liquidity. Marketed volumes declined from approximately 364.3 MBbls/d in the first quarter 2003 to approximately 301.4 MBbls/d in the first quarter 2004 due to our decision to curtail low margin sales and reduce inventory risk. This volumetric decline had little impact on our operating income.

REG. Operating income for the REG segment was $54 million for the quarter ended March 31, 2004, compared to $59 million for the quarter ended March 31, 2003. The 2004 period includes a $21 million charge related to the anticipated sale of Illinois Power. We also stopped depreciating our Illinois Power assets on February 1, 2004, as they are classified as held for sale, which resulted in a benefit to operating income of $20 million compared to the quarter ended March 31, 2003.

Operationally, this segment was negatively impacted in 2004 as compared to 2003 by warmer than normal winter weather, which resulted in reduced residential and commercial gas sales volumes. Electric sales were relatively flat as a reduction in commercial and industrial demand was offset by an increase in residential demand. Operating expenses in 2004 were negatively impacted by higher employee pension costs and costs associated with personal injury and other damage claims.

CRM. Operating income (loss) for the CRM segment was $(13) million for the quarter ended March 31, 2004, compared to $38 million for the quarter ended March 31, 2003. Results for 2004 primarily relate to fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold. Results for 2003 include approximately $61 million associated with sales of natural gas in storage which had previously been recorded at fair value (please read Note 1—Accounting Policies—Revenue Recognition for additional details) and gains in value of our remaining marketing and trading portfolio.

Other. Other operating loss was $53 million for the quarter ended March 31, 2004, compared to $44 million for the quarter ended March 31, 2003. Results for 2004 include approximately $15 million of expenses related to increased legal and severance reserves. The increased legal reserves resulted from additional activities during the quarter that affected management’s assessment of the probable and estimable loss associated with the applicable proceedings. Please read Note 3—Restructuring Charges for a discussion of the increased severance reserve. This increase was partially offset by lower compensation costs in the 2004 period.

Earnings from Unconsolidated Investments.

Our earnings from unconsolidated investments were approximately $40 million for the quarter ended March 31, 2004, compared to $53 million for the quarter ended March 31, 2003.

GEN. GEN’s earnings from unconsolidated investments were approximately $38 million for the quarter ended March 31, 2004, compared to $39 million for the quarter ended March 31, 2003. Earnings from our West Coast Power investment are the primary driver of results for each of these periods. West Coast Power provided equity earnings of approximately $35 million for the quarter ended March 31, 2004, compared to $29 million for the quarter ended March 31, 2003.

Earnings at West Coast Power were higher quarter over quarter due to higher realized margins resulting from forward hedges put in place in connection with the execution of the CDWR contract. Please read Item 1. Business—Segment Discussion—Power Generation—West region—Western Electricity Coordinating Council (WECC) beginning on page 6 of our Form 10-K for further discussion of the CDWR contract.

As described above under “—Liquidity and Capital Resources—External Liquidity Sources—Asset Sale Proceeds,” in January 2004, we sold our 17.55% interest in a 74 MW power generating facility located in Jamaica for $5.5 million in net aggregate proceeds. We did not recognize a gain or loss on the sale. In February 2004, we entered into a definitive agreement to sell our 50% interest in the 123 MW Michigan Power power generating facility. This transaction is targeted to close during the second quarter 2004, subject to the receipt of required lender and counterparty consents, and is expected to generate aggregate net cash proceeds of approximately $25 million. In the first quarter 2004, we recorded an impairment of approximately $7 million related to the anticipated sale of Michigan Power which offset our share of Michigan Power’s earnings for the quarter. The net loss related to Michigan Power recorded in the first quarter 2004 was $2.3 million. Please read Note 5—Unconsolidated Investments for further discussion of our accounting relating to this pending sale. We are continuing to pursue opportunities to sell our interests in other domestic and international projects, none of which are considered core to our power generation business.

NGL. NGL’s earnings from unconsolidated investments were approximately $2 million for the quarter ended March 31, 2004, compared to $3 million for the quarter ended March 31, 2003. Lower realized liquids prices at our VESCO partnership complex and lower fractionation fees at our Gulf Coast Fractionator investment contributed to this decline in earnings.

CRM. CRM’s earnings from unconsolidated investments were zero for the quarter ended March 31, 2004, compared to $11 million for the quarter ended March 31, 2003. As of December 31, 2003, CRM has no material unconsolidated investments. As such, 2004 and future results are expected to be de minimis. The earnings in 2003 primarily related to our Nicor Energy joint venture, the operations of which were sold in the first half of 2003.

Interest Expense

Interest expense totaled $132 million for the quarter ended March 31, 2004, compared to $110 million for the quarter ended March 31, 2003. The significant increase in 2004, as compared to 2003, is attributable to higher average interest rates on borrowings related to the new securities issued in connection with our August and October 2003 refinancings. This increase is slightly offset by lower average principal balances in the 2004 period compared to the 2003 period.

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 $11 million for the quarter ended March 31, 2004, compared to $21 million for the quarter ended March 31, 2003. The decrease in 2004, as compared to 2003, is due to lower minority interest income, partially offset by mark-to-market income recognized in the first quarter 2004 associated with interest rate swaps.

Income Tax Benefit / (Expense)

We reported an income tax benefit during the quarter ended March 31, 2004 of $29 million. The income tax benefit is the net of $10 million of income tax expense from continuing operations and a $39 million benefit associated with reducing a valuation allowance related to our significant capital loss carryforward, which primarily relates to our third quarter 2002 sale of Northern Natural Gas Company. We reduced the valuation allowance related to our capital loss carryforward as a result of capital gains expected to be recognized from anticipated non-core asset sales in 2004. Excluding this item, the 2004 effective tax rate would be 37%, compared to 37% in 2003. In general, differences between these 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 differences.

Discontinued Operations

Discontinued operations includes 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 gain of $20 million ($14 million after-tax) for the quarter ended March 31, 2004 is the U.K. CRM business, primarily due to translation gains recognized on the repatriation of cash from the U.K. The largest contributor to the pre-tax loss of $13 million ($3 million after-tax) for the quarter ended March 31, 2003 is the pre-tax loss from operations of our U.K. CRM operations.

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.

Please read Note 1—Accounting Policies for further discussion of our adoption of new accounting policies.

Preferred Stock Dividends

The $5 million preferred stock dividend recognized in the first quarter 2004 is related to our Series C convertible preferred stock, which accumulates dividends at an annual rate of 5.5%. The 2003 dividend of $83 million related to the Series B preferred stock that included an implied dividend of $660 million, which was amortized over a two-year period. Please read Note 15—Redeemable Preferred Securities beginning on page F-53 of our Form 10-K/A for a description of the August 2003 exchange of the Series B preferred stock for, among other things, the Series C preferred stock, and the impact on the associated dividends.

2004 Outlook

The following summarizes our outlook for the remainder of 2004 for our four reportable segments.

GEN Outlook. This segment’s future financial results will continue to reflect a sensitivity to power prices and weather conditions. 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 Form 10-K, 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, the fair value of our investment in West Coast Power 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 during the remainder of 2004. Please read Note 9—Commitments and Contingencies—Summary of Material Legal Proceedings— Western Long-Term Contract Complaints for further discussion of the legal challenges to the CDWR contract. Please also read “—Liquidity and Capital Resources—Internal Liquidity Sources—Cash Flows from Operations” for a discussion of our efforts to seek a renewal or replacement of the CDWR contract.

The current power purchase agreement between DMG and Illinois Power will terminate on December 31, 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. However, in the event the sale of Illinois Power to Ameren does not close before the end of 2004, DPM and Illinois Power will enter into an interim power purchase agreement that would take effect once regulatory approval is obtained and only if the pending sale is not completed by December 31, 2004. This interim power purchase agreement would remain in effect only until the earlier of the closing of the pending sale or December 31, 2006, which latter date coincides with the expiration of the retail electric rate freeze in the State of Illinois. The interim power purchase agreement, which would provide for capacity and energy to serve Illinois Power’s customers through 2006 if the pending sale is not consummated, contains terms and conditions, including pricing terms, substantially similar to those contained in the Ameren power purchase agreement.

We recently executed agreements to sell our 50% interests in the 424 MW Oyster Creek power generating facility and the 123 MW Michigan Power power generating facility. Additionally, we are continuing to pursue

sales of our interests in a number of other similar facilities that we consider non-strategic to this business, including the Commonwealth, Black Mountain, Hartwell and Panama facilities. We hold ownership interests of 50% in each of these projects, which aggregate less than 500 MWs of net generating capacity. These investments contributed approximately $25 million in earnings to our full year 2003 results, exclusive of any impairment charges. Please read Note 5—Unconsolidated Investments—GEN Investments for further discussion of these investments. Additionally, the pending transaction with Ameren includes the sale of our 20% interest in the Joppa facility, which contributed approximately $3.3 million in earnings from unconsolidated investments in our full year 2003 results. 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, including the willingness of lenders and other counterparties to consent to a proposed transaction.

NGL Outlook. This segment’s financial results will continue to reflect sensitivity to natural gas and natural gas liquids prices, and we expect that the 2004 pricing environment will continue to be similar to what we experienced in 2003. Our upstream contract settlements under percentage of proceeds and percentage of liquids contracts will continue to benefit from these relatively high prices; our hybrid contracts, which are sensitive to frac spread, will generally revert from percentage of liquids settlements to fee settlements. Natural gas liquids production from both our own and third-party natural gas processing plants that are exposed to frac spread will continue to be reduced as frac spreads remain lower than that required to justify economic extraction of natural gas liquids in today’s natural gas price environment.

The impact of these lower processing volumes is an ongoing reduction of natural gas liquids supply to our and third parties’ fractionation, storage and distribution infrastructure, similar to 2003. Accordingly, aggressive competition exists between fractionators for available volumes, causing a reduction in fees paid for fractionation services.

Straddle plant gas processing in the Gulf of Mexico will continue to be negatively impacted by uncertainty surrounding the determination of gas quality specifications for liquefiable hydrocarbons. Over the past several years extraction economics have been generally poor, causing pipeline companies to become increasingly concerned about heavy hydrocarbons that have been left in the natural gas entering their systems instead of being extracted. These heavy hydrocarbons cause pipeline operational and safety concerns. As a result, many have used emergency powers (operational flow orders or critical notices) to force producers to extract heavy hydrocarbons by processing their gas. While industry stakeholders respond to recent FERC decisions directing pipeline companies to address this issue in their tariff, there is significant lack of clarity around when and where processing is required. The result is a patchwork of pipeline policies and practices, leaving producers and processors without clearly defined ground rules. As a result, contracting gas and planning straddle plant operations are difficult. Resolution of the issue is currently being pursued through the Natural Gas Council, FERC and other affected stakeholders.

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 in connection with many of our commercial relationships. On occasion, we have been unable to efficiently satisfy a potential new customer’s concerns about our credit ratings. We expect similar collateral requirements until such time as our credit ratings measurably improve. Our ability to hedge future natural gas liquids production during 2004 will again be limited by reduced market liquidity and our obligation to post collateral.

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 also intend to continue to review our asset portfolio to maximize return on investment. We have identified and sold a few assets that are not strategic to our core operations, including our interests in Hackberry LNG and Indian Basin. We may pursue sales of other 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” 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. Also, 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.

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. Please read “—2004 Outlook—GEN Outlook” above for a discussion of alternate arrangements being pursued relative to the closing of the pending sale to Ameren.

With no alternate suppliers certified by the ICC to provide residential electric service pursuant to the Customer Choice Law, Illinois Power does not expect to experience any residential customer switching in 2004. In the first quarter 2004, 0.12% and 31.1% of our commercial and industrial loads, respectively, were served by other energy providers. We anticipate that by the end of 2004, additional load representing 7% of industrial sales may switch from bundled and PPO service to alternate energy providers. We also anticipate that incremental switching to alternate energy providers by our commercial customers will be minimal. Actual switching will be influenced in part by market based energy prices, plus any delivery charges, relative to bundled and PPO offerings that Illinois Power is required to provide.

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 our remaining long-term power tolling arrangements as well as the related gas transportation agreements. 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 would 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 Form 10-K.

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 $164 million of collateral associated with this business. Approximately $15 million of this balance relates to our tolling arrangements. An additional $43 million relates to the ABG Gas Supply gas contract, which will expire in the first quarter of 2006. The remaining $106 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 condensed 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 condensed consolidated statements of operations:


	For the Quarter Ended March 31, 2004
	GEN			NGL			REG			CRM			Other & Eliminations			Consolidated
	(in millions)
Operating Cash Flows Before Changes in Working Capital	$	138		$	69		$	57		$	(43	)	$	(103	)	$	118
Changes in Working Capital		24			52			83			(42	)		(68	)		49

Net Cash Provided by (Used in) Operating Activities	$	162		$	121		$	140		$	(85	)	$	(171	)	$	167


	For the Quarter Ended March 31, 2003
	GEN			NGL			REG			CRM			Other & Eliminations			Consolidated
	(in millions)
Operating Cash Flows Before Changes in Working Capital	$	97		$	81		$	71		$	140		$	(124	)	$	265
Changes in Working Capital		(31	)		(39	)		(33	)		139			106			142

Net Cash Provided by (Used in) Operating Activities	$	66		$	42		$	38		$	279		$	(18	)	$	407

Operating Cash Flow. Our cash flow provided by operations totaled $167 million for the quarter ended March 31, 2004. During the quarter, our GEN, NGL and REG segments provided positive cash flow from operations. GEN provided cash flow from operations of $162 million due to positive earnings for the period; NGL provided cash flow from operations of $121 million primarily due to inventory decreases and positive earnings for the period; and REG provided cash flow from operations of $140 million primarily due to the withdrawals of gas in storage and positive earnings for the period. Our CRM segment used approximately $85 million in cash primarily due to fixed payments associated with the power tolling arrangements and the related gas transport agreements. Other and eliminations includes a use of approximately $171 million in cash primarily due to interest payments to service debt and general and administrative expenses.

Our cash flow provided by operations totaled $407 million for the quarter ended March 31, 2003. Cash provided in 2003 primarily relates to collateral returns, settlements of risk management assets and sales of natural gas in storage from our CRM business, a $110 million income tax refund and the operational performances of our GEN, NGL and REG segments. Our GEN segment provided cash flows of $66 million largely due to strong commodity prices. Similarly, our NGL segment contributed cash flows from operations of $42 million due to increasing commodity prices, which benefited our upstream and marketing businesses, offset by higher prepayments. Our REG segment contributed operating cash flows of $38 million, primarily from normal operating conditions and withdrawals of gas from storage. General and administrative costs and continued extinguishment of liabilities during our exit from our communications business partially offset these positive operational cash flows during the quarter ended March 31, 2003.

Capital Expenditures and Investing Activities. Cash used in investing activities during the quarter ended March 31, 2004 totaled $30 million. Capital spending of $53 million was primarily comprised of $14 million, $9 million and $28 million in the GEN, NGL and REG segments, respectively. The capital spending for the GEN segment primarily related to maintenance capital projects. Capital spending in our NGL segment primarily related to maintenance capital projects and wellconnects, as well as approximately $2 million on a gathering system expansion. Capital spending in our REG segment primarily related to projects intended to maintain system reliability and new business services. Proceeds from asset sales primarily included $17 million in

proceeds from the sale of our remaining financial interest in the Hackberry LNG project and approximately $5.5 million from the sale of our interest in a power generating facility located in Jamaica.

Cash used in investing activities during the quarter ended March 31, 2003 totaled $77 million. Capital spending of $84 million was principally comprised of $37 million, $12 million and $32 million in the GEN, NGL and REG segments, respectively, primarily representing improvements to our existing asset base. The capital spending for the GEN segment included approximately $17 million spent on the construction of Rolling Hills, with respect to which commercial operation began in June 2003. Proceeds from asset sales primarily included $20 million in proceeds from the sale of SouthStar offset by $13 million in cash outflows associated with the sale of our European communications business.

Financing Activities. Cash used in financing activities during the quarter ended March 31, 2004 totaled $149 million. Repayments of long-term debt totaled $137 million for the three months ended March 31, 2004 and consisted of the following: (1) payments of $95 million on a maturing series of Illinova senior notes; (2) payments of $22 million on Illinois Power’s transitional funding trust notes; (3) payments of $19 million under the ABG Gas Supply financing; and (4) payments of $1 million on the ChevronTexaco junior notes. Cash used in financing activities also includes a semi-annual dividend payment of $11 million on our Series C preferred stock.

Cash provided by financing activities during the quarter ended March 31, 2003 totaled $694 million. During the three months ended March 31, 2003, we borrowed $712 million, net, under our revolving credit facilities. Long-term debt proceeds, net of issuance costs, for the three months ended March 31, 2003 consisted of $142 million from the delayed issuance of $150 million in Illinois Power 11.5% Mortgage Bonds due 2010. Repayments of long-term debt totaled $158 million for the three months ended March 31, 2003 and consisted of the following: (1) payments of $94 million under the Renaissance and Rolling Hills interim financing; (2) payments of $22 million on Illinois Power’s transitional funding trust notes; (3) payments of $19 million under the Black Thunder secured financing; (4) payments of $18 million under the ABG Gas Supply financing; and (5) purchase of $5 million of Illinova senior notes on the open market.

RISK-MANAGEMENT DISCLOSURES

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


	As of and for the Quarter Ended March 31, 2004
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2004	$	(137	)
Risk-management gains recognized through the income statement in the period, net		16
Cash paid related to risk-management contracts settled in the period, net		26
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(92	)

Fair value of portfolio at March 31, 2004	$	(187	)

Income Statement Reconciliation
Risk-management gains recognized through the income statement in the period, net	$	16
Physical business recognized through the income statement in the period, net (3)		(21	)
Non-cash adjustments and other		(3	)

Net recognized operating loss	$	(8	)

Cash Flow Statement
Cash paid related to risk-management contracts settled in the period, net	$	(26	)
Estimated cash paid related to physical business settled in the period, net (3)		(21	)
Timing and other, net (4)		15

Cash paid during the period	$	(32	)

Risk-Management cash flow adjustment for the quarter ended March 31, 2004 (5)	$	(24	)

(1)	Our modeling methodology has been consistently applied.

(2)	This amount primarily consists of changes in value associated with cash flow hedges on forward power sales.

(3)	This amount includes capacity payments on our power tolling arrangements.

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

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

The net risk management liability of $187 million is the aggregate of the following line items on the condensed 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 tables depict the mark-to-market value and cash flow components of our net risk-management assets and liabilities at March 31, 2004 and December 31, 2003:

Mark-to-Market Value of Net Risk-Management Assets (1)


	Total			2004(2)			2005			2006			2007			2008			Thereafter
	(in millions)
March 31, 2004	$	(117	)	$	(15	)	$	(9	)	$	(14	)	$	(40	)	$	(13	)	$	(26	)
December 31, 2003		(144	)		(22	)		(17	)		(25	)		(39	)		(12	)		(29	)

Increase (decrease)	$	27		$	7		$	8		$	11		$	(1	)	$	(1	)	$	3

(1)

The table 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 March 31, 2004 of $187 million on the unaudited condensed consolidated balance sheets include the $117 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)	Amounts represent April 1 to December 31, 2004 values in the March 31, 2004 row and January 1 to December 31, 2004 values in the December 31, 2003 row.

Cash Flow Components of Net Risk-Management Asset


	Three Months Ended March 31, 2004			Nine Months Ended December 31, 2004			Total 2004			2005			2006			2007			2008			Thereafter
	(in millions)
March 31, 2004 (1)	$	(7	)	$	(11	)	$	(18	)	$	(7	)	$	(14	)	$	(43	)	$	(15	)	$	(33	)
December 31, 2003								(17	)		(14	)		(24	)		(43	)		(15	)		(39	)

Increase (Decrease)							$	(1	)	$	7		$	10		$	—		$	—		$	6

(1)

The cash flow values for 2004 reflect realized cash flows for the three months ended March 31, 2004 and anticipated 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 March 31, 2004, based on our valuation methodology.

Net Fair Value of Risk-Management Portfolio


	Total			2004			2005			2006			2007			2008			Thereafter
	(in millions)
Market Quotations (1)	$	(61	)	$	(15	)	$	(12	)	$	(3	)	$	(27	)	$	(2	)	$	(2	)
Prices Based on Models		(56	)		—			3			(11	)		(13	)		(11	)		(24	)

Total	$	(117	)	$	(15	)	$	(9	)	$	(14	)	$	(40	)	$	(13	)	$	(26	)

(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.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q/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 quarterly 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;

•

expectations regarding capital expenditures, interest expense and other payments;

•

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

•

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

•

our ability to issue public equity under our effective shelf registration statement;

•

our ability to address our substantial leverage;

•

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

•

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;

•

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

•

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, including the relationships between prices for power and natural gas or other power generating fuels, commonly referred to as the “spark spread” or “dark spread” depending on the fuel type, and the frac spread;

•

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

•

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

•

the condition of the capital markets generally, which will be affected by interest rates, foreign currency fluctuations and general economic conditions, and our ability to engage in capital-raising transactions;

•

our financial condition, including our ability to satisfy our significant debt maturities;

•

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

•

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

•

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-Q/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-Q/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-Q/A, except as otherwise required by applicable law.

RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us. Specifically, we adopted certain provisions of FIN No. 46R on March 31, 2004.

CRITICAL ACCOUNTING POLICIES

Please read “Critical Accounting Policies” beginning on page 40 of our Form 10-K/A for a complete description of our critical accounting policies, with respect to which there have been no material changes since the filing of our Form 10-K.

Item 4—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 first quarter 2004 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. In 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-Q/A, we have restated our unaudited condensed consolidated financial statements. For further information, please see the Explanatory Note beginning on page 9. 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.

DYNEGY INC.

PART II. OTHER INFORMATION

Item 6—EXHIBITS AND REPORTS ON FORM 8-K

(a) The following documents are included as exhibits to this Form 10-Q/A:


	3.3	Amended and Restated Bylaws of Dynegy Inc. (incorporated by reference to Exhibit 3.3 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).

	10.1	Amendment to the Dynegy Inc. 401(K) Savings Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K for the Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).

	10.2	Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan, effective January 1, 2004 (incorporated by reference to Exhibit 10.31 to the Annual Report on Form 10-K for the Year Ended December 31, 2003 of Dynegy Inc., File No. 1-15659).

	10.3	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).

	10.4	Amendment No. 1 to Stock Purchase Agreement dated March 23, 2004 among Dynegy Inc., Illinova Corporation, Illinova Generating Company and Ameren Corporation (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 25, 2004, File No. 1-15659).

	*10.5	Contract for Consulting Services dated March 19, 2004 between Dynegy Inc. and Daniel L. Dienstbier.

+	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.

+	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. filed during the first quarter 2004:

1. We filed a Current Report on Form 8-K on January 6, 2004. Items 5 and 7 were reported and no financial statements were filed.

2. We filed a Current Report on Form 8-K on January 21, 2004. Items 5 and 7 were reported and no financial statements were filed.

3. We filed a Current Report on Form 8-K on January 29, 2004. Items 7 and 12 were reported and no financial statements were filed.

4. We filed a Current Report on Form 8-K on February 3, 2004. Items 7 and 9 were reported and no financial statements were filed.

5. We filed a Current Report on Form 8-K on February 4, 2004. Items 5 and 7 were reported and no financial statements were filed.

6. We filed a Current Report on Form 8-K on February 11, 2004. Items 7 and 9 were reported and no financial statements were filed.

7. We filed a Current Report on Form 8-K on March 17, 2004. Items 5 and 7 were reported and no financial statements were filed.

8. We filed a Current Report on Form 8-K on March 24, 2004. Items 5 and 7 were reported and no financial statements were filed.

9. We filed a Current Report on Form 8-K on March 25, 2004. Items 5 and 7 were reported and no financial statements were filed.

10. We filed a Current Report on Form 8-K on March 31, 2004. Items 7 and 9 were reported and no financial statements were filed.

DYNEGY INC.

SIGNATURES

Pursuant to the requirements 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 19, 2005	By:	/s/ NICK J. CARUSO
		Nick J. Caruso Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)