Edgar Filing: DYNEGY INC /IL/

March 31,

2005 (1)

December 31,

2004

(in millions)

One Day VaR—95% Confidence Level

One Day VaR—99% Confidence Level

Average VaR for the Year-to-Date Period—95% Confidence Level

For the quarterly period ended March 31, 2005

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2005

¨	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, 284,688,181 shares outstanding as of May 5, 2005; Class B common stock, no par value per share, 96,891,014 shares outstanding as of May 5, 2005.

DYNEGY INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

	Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

	Condensed Consolidated Balance Sheets: March 31, 2005 and December 31, 2004	4
	Condensed Consolidated Statements of Operations: For the three months ended March 31, 2005 and 2004	5
	Condensed Consolidated Statements of Cash Flows: For the three months ended March 31, 2005 and 2004	6
	Condensed Consolidated Statements of Comprehensive Income (Loss): For the three months ended March 31, 2005 and 2004	7
	Notes to Condensed Consolidated Financial Statements	8

	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	35
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	57
	Item 4. CONTROLS AND PROCEDURES	58

PART II. OTHER INFORMATION

	Item 1. LEGAL PROCEEDINGS	60
	Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	60
	Item 6. EXHIBITS	60

DEFINITIONS

As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below. Additionally, the terms “Dynegy,” “we,” “us” and “our” refer to Dynegy Inc. and its subsidiaries, unless the context clearly indicates otherwise.


ARO		Asset retirement obligation
ARB		Accounting Research Bulletin
Bcf/d		Billion cubic feet 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 Chevron Corporation
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
DNE		Dynegy Northeast Generation
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
GAAP		Generally Accepted Accounting Principles of the United States of America
GEN		Our power generation business segment
GCF		Gulf Coast Fractionators
ISO		Independent System Operator
KW—yr		Kilowatt year
KWH		Kilowatt hour
LNG		Liquefied natural gas
LPG		Liquefied petroleum gas
MBbls/d		Thousands of barrels per day
Mcf		Thousand cubic feet
MISO		Midwest Independent Transmission Operator, Inc.
MMBtu		Millions of British thermal units
MMCFD		Million cubic feet per day
MW		Megawatts
MWh		Megawatt hour
NGL		Our natural gas liquids business segment
NOL		Net operating loss
NOV		Notice of Violation issued by the EPA
NYISO		New York Independent System Operator
POL		Percentage of liquids
POP		Percentage of proceeds
PRB		Powder River Basin coal
REG		Our regulated energy delivery business segment
RMR		Reliability Must Run
RTO		Regional Transmission Organization
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)


	March 31, 2005			December 31, 2004
ASSETS

Current Assets
Cash and cash equivalents	$	371		$	628
Restricted cash		61			—
Accounts receivable, net of allowance for doubtful accounts of $162 and $159, respectively		967			810
Accounts receivable, affiliates		11			14
Inventory		228			233
Assets from risk-management activities		764			565
Deferred income taxes		132			74
Prepayments and other current assets		484			428

Total Current Assets		3,018			2,752

Property, Plant and Equipment		8,250			7,822
Accumulated depreciation		(1,752	)		(1,692	)

Property, Plant and Equipment, Net		6,498			6,130

Other Assets
Unconsolidated investments		416			421
Restricted cash		49			—
Restricted investments		36			—
Assets from risk-management activities		299			313
Goodwill		15			15
Intangible assets		462			—
Deferred income taxes		13			12
Other long-term assets		179			209

Total Assets	$	10,985		$	9,852

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current Liabilities
Accounts payable	$	491		$	561
Accounts payable, affiliates		—			23
Accrued interest		138			118
Accrued liabilities and other current liabilities		780			450
Liabilities from risk-management activities		798			616
Notes payable and current portion of long-term debt		64			34

Total Current Liabilities		2,271			1,802

Long-term debt		4,862			4,132
Long-term debt to affiliates		200			200

Long-Term Debt		5,062			4,332
Other Liabilities
Liabilities from risk-management activities		348			395
Deferred income taxes		764			597
Other long-term liabilities		434			353

Total Liabilities		8,879			7,479

Minority Interest		107			106
Commitments and Contingencies (Note 9)
Redeemable Preferred Securities, redemption value of $400 at March 31, 2005 and December 31, 2004, respectively		400			400
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at March 31, 2005 and December 31, 2004; 286,186,244 and 285,012,203 shares issued and outstanding at March 31, 2005 and December 31, 2004, respectively		2,862			2,859
Class B Common Stock, no par value, 360,000,000 shares authorized at March 31, 2005 and December 31, 2004; 96,891,014 shares issued and outstanding at March 31, 2005 and December 31, 2004		1,006			1,006
Additional paid-in capital		43			41
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive loss, net of tax		(19	)		(13	)
Accumulated deficit		(2,217	)		(1,950	)
Treasury stock, at cost, 1,686,526 shares at March 31, 2005 and 1,679,183 shares at December 31, 2004		(68	)		(68	)

Total Stockholders’ Equity		1,599			1,867

Total Liabilities and Stockholders’ Equity	$	10,985		$	9,852

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Three Months Ended March 31,
	2005			2004
Revenues	$	1,499		$	1,657
Cost of sales, exclusive of depreciation shown separately below		(1,479	)		(1,378	)
Depreciation and amortization expense		(75	)		(88	)
Impairment and other charges		1			(16	)
Gain (loss) on sale of assets, net		(1	)		2
General and administrative expenses		(269	)		(69	)

Operating income (loss)		(324	)		108
Earnings from unconsolidated investments		4			40
Interest expense		(100	)		(132	)
Other income and expense, net		4			13
Minority interest expense		(6	)		(2	)

Income (loss) from continuing operations before income taxes		(422	)		27
Income tax benefit		157			29

Income (loss) from continuing operations		(265	)		56
Income from discontinued operations, net of tax expense of $1 and $6, respectively		3			14

Net income (loss)		(262	)		70
Less: preferred stock dividends		5			5

Net income (loss) applicable to common stockholders	$	(267	)	$	65

Earnings (Loss) Per Share (Note 8):
Basic earnings (loss) per share:
Earnings (loss) from continuing operations	$	(0.71	)	$	0.14
Earnings from discontinued operations		0.01			0.03

Basic earnings (loss) per share	$	(0.70	)	$	0.17

Diluted earnings (loss) per share:
Earnings (loss) from continuing operations	$	(0.71	)	$	0.11
Earnings from discontinued operations		0.01			0.03

Diluted earnings (loss) per share	$	(0.70	)	$	0.14

Basic shares outstanding		379			376
Diluted shares outstanding		505			502

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)


	Three Months Ended March 31,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(262	)	$	70
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		79			97
Impairment and other charges		(1	)		16
Earnings from unconsolidated investments, net of cash distributions		(1	)		(4	)
Risk-management activities		(11	)		(24	)
Loss (gain) on sale of assets, net		1			(2	)
Deferred income taxes		(156	)		(23	)
Legal and settlement charges		68			9
Independence toll settlement charge		183			—
Other		(5	)		(21	)
Changes in working capital:
Accounts receivable		(128	)		99
Inventory		26			83
Prepayments and other assets		29			(8	)
Accounts payable and accrued liabilities		131			(119	)
Changes in non-current assets		(1	)		(25	)
Changes in non-current liabilities		14			19

Net cash provided by (used in) operating activities		(34	)		167

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(54	)		(53	)
Proceeds from asset sales, net		(5	)		23
Business acquisitions, net of cash acquired		(120	)		—

Net cash used in investing activities		(179	)		(30	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of long-term borrowings		(19	)		(137	)
Proceeds from issuance of capital stock		2			4
Dividends and other distributions, net		(11	)		(11	)
Increase in restricted cash and restricted investments		(17	)		—
Other financing, net		1			(5	)

Net cash used in financing activities		(44	)		(149	)

Effect of exchange rate changes on cash		—			(1	)
Net decrease in cash and cash equivalents		(257	)		(13	)
Cash and cash equivalents, beginning of period		628			477
Less: Illinois Power cash classified as held for sale at end of period (Note 2)		—			(97	)

Cash and cash equivalents, end of period	$	371		$	367

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)


	Three Months Ended March 31,
	2005			2004
Net income (loss)	$	(262	)	$	70
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net		(18	)		(59	)
Reclassification of mark-to-market losses to earnings, net		12			12

Changes in cash flow hedging activities, net (net of tax benefit of $4 and $28, respectively)		(6	)		(47	)
Foreign currency translation adjustments		—			(15	)
Minimum pension liability (net of tax expense of zero and $1, respectively)		—			2

Other comprehensive loss, net of tax		(6	)		(60	)

Comprehensive income (loss)	$	(268	)	$	10

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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 consolidated 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 consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2004, which we refer to as our “Form 10-K.”

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. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period, however, due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. These estimates and judgments also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are primarily used in (1) developing fair value assumptions, including estimates of future cash flows and discount 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, guarantees and indemnifications and (6) estimating various factors used to value our pension assets and liabilities. 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.

Asset Retirement Obligations. At December 31, 2004, our ARO liabilities were $35 million for our GEN segment and $11 million for our NGL 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. We continue to follow the provisions for disclosure and accounting for these AROs under SFAS No. 143, “Asset Retirement Obligations.” During the three-months ended March 31, 2005 and 2004, there were no material additional AROs recorded or settled, and our accretion expenses and revisions to estimated cash flows were not material. At March 31, 2005, our ARO liabilities were $36 million for our GEN segment and $10 million for our NGL segment.

Employee Stock Options. 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-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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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 (loss) and basic and diluted earnings (loss) per share amounts would have approximated the following pro forma amounts for the three-month periods ended March 31, 2005 and 2004, respectively.


	Three Months Ended March 31,
	2005			2004
	(in millions, except per share data)
Net income (loss) as reported	$	(262	)	$	70
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		(1	)		(9	)

Pro forma net income (loss)	$	(262	)	$	62

Earnings (loss) per share:
Basic—as reported	$	(0.70	)	$	0.17
Basic—pro forma	$	(0.70	)	$	0.15
Diluted—as reported	$	(0.70	)	$	0.14
Diluted—pro forma	$	(0.70	)	$	0.12

Accounting Principle Adopted

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.

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 and California, 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 facilities ranges from 165 MW to 902 MW. As a result of various contractual arrangements into which these entities have entered,

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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 $325 million at March 31, 2005, and one of our affiliates has a loan outstanding to one of these entities, which totaled $20 million at March 31, 2005.

On January 31, 2005, we completed the acquisition of ExRes SHC, Inc., the parent company of Sithe Energies, Inc., which we refer to as “Sithe Energies,” and Sithe/Independence Power Partners, L.P., which we refer to as “Independence.” ExRes SHC, Inc., which we refer to as “ExRes,” owns through its subsidiaries four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. The entities owning these facilities meet the definition of VIEs. In accordance with the purchase agreement, Exelon has the sole and exclusive right to direct our efforts to decommission, sell, or otherwise dispose of the hydroelectric facilities owned through the VIE entities. Exelon is obligated to reimburse ExRes for all costs, liabilities, and obligations of the entities owning these facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities. As a result, we are not the primary beneficiary of the entities, and have not consolidated them in accordance with the provisions of FIN No. 46R.

With regard to the four natural gas-fired merchant facilities, we have the option to elect to decommission any or all of these facilities within a 180-day period after the January 31, 2005 closing date. If we elect to decommission any of these assets, Exelon will be entitled to direct the decommissioning, sale, or other disposal of the facility. Further, Exelon is obligated to indemnify ExRes with respect to the past and present assets and operations of the entity owning such facility, and must provide written consent for any payments or actions outside the ordinary course of operations. Effective April 1, 2005, we have elected to decommission three of these four natural gas-fired facilities owned by these entities. We will continue to evaluate our involvement with the remaining entity. As a result of the rights retained by Exelon with respect to these facilities, we are not the primary beneficiary of these VIE’s, and have not consolidated them in accordance with the provisions of FIN No. 46R. Please see Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies for further discussion regarding this acquisition.

These hydroelectric generation facilities have commitments and obligations that are off-balance sheet with respect to Dynegy arising under operating leases for equipment and long-term power purchase agreements with local utilities. As of March 31, 2005, the equipment leases have remaining terms from two to sixteen years and involve a maximum aggregate obligation of $137 million over the terms of the leases. Additionally, each of these facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account, which we refer to as a “Tracking Account,” was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. Two of the four hydroelectric facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of March 31, 2005, was approximately $281 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts will make the continued sale of electricity from the facilities uneconomical. As discussed above, the obligations of the four hydroelectric facilities are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of these facilities.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Accounting Principles Not Yet Adopted

SFAS No. 123(R). In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment,” which revises SFAS No. 123. For public entities such as us, SFAS No. 123(R) is effective for annual periods beginning after June 15, 2005. SFAS No. 123(R) requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. The fair value for these awards is calculated on the grant date in accordance with SFAS 123 for either recognition in our statement of operations or through our pro forma disclosures. This expense will be recognized over the period during which an employee is required to provide services in exchange for the award. SFAS 123(R) describes several transition methods, and we expect to apply the modified prospective method of adoption. Under this method, compensation expense will be recognized for the remaining portion of outstanding, unvested awards at January 1, 2006.

As noted in “Employee Stock Options” above, we transitioned to a fair value based method of accounting for stock-based compensation in the first quarter 2003. Our share-based payments primarily consist of stock options and restricted stock awards. For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model. For restricted stock awards, we consider the fair value to be the closing price of the stock on the grant date. We recognize the fair value of our share based payments over the vesting periods of the awards, which is typically a three-year service period.

Prior to the issuance of SFAS No. 123(R), we adopted the prospective method for expensing the fair value of stock options and restricted stock awards granted after January 1, 2003. As such, under the modified prospective method of adoption under SFAS

123(R), three option grants made in September 2002 and October 2002 would require recognition of expense over the remaining vesting periods of these outstanding awards. We do not expect this incremental expense to be material.

FIN No. 47. In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” which is an interpretation of SFAS No. 143. FIN No. 47 clarifies the term “conditional asset retirement obligation,” which refers to legal obligations for which companies must perform asset retirement activity for which the timing and/or method of settlement are conditional upon future events that may or may not be within the control of the entity. However, the obligation to perform the asset retirement is unconditional, despite the uncertainty that exists surrounding the timing and method of settlement. Uncertainty about the timing and method of settlement for a conditional ARO should be considered in estimating the ARO when sufficient information exists. FIN No. 47 clarifies when sufficient information exists to reasonably estimate the fair value of an ARO. FIN No. 47 is effective no later than the end of the first fiscal year ending after December 15, 2005, and early adoption is encouraged.

As noted in “Asset Retirement Obligations” above, we currently record AROs for our GEN and NGL segments. These AROs involve significant judgment regarding future cash flows and the ultimate timing of these cash flows, some of which include the probability of future events occurring such as the timing and method of settlement. As such, we are in the process of evaluating the impact of FIN No. 47.

Note 2—Acquisitions, Dispositions and Discontinued Operations

Acquisitions

Sithe Energies. On January 31, 2005, we acquired 100 percent of the outstanding common shares of ExRes, the parent company of Sithe Energies and Independence. The results of the operations of ExRes have been included

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

in our consolidated financial statements since that date. Through this acquisition, we acquired the 1,021 MW Independence power generation facility located near Scriba, New York, as well as four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. We have not consolidated the entities that own these four natural gas-fired facilities and four hydroelectric generation facilities, in accordance with the provisions of FIN No. 46R. See Note 1—Accounting Policies—Accounting Principles Adopted—FIN No. 46R for additional discussion of these facilities. In addition to these power plants, we acquired the 750-MW firm capacity sales agreement between Independence and Con Edison, a subsidiary of Consolidated Edison, Inc. This agreement, which runs through 2014, will provide us with annual cash receipts of $100 million, subject to the restrictions on distribution under Independence’s indebtedness. Independence holds power tolling, financial swap and other contracts with other Dynegy subsidiaries. As a result of the acquisition, these contracts have become intercompany agreements, and their financial statement impact has been substantially eliminated. This transaction enabled us to address one of our outstanding power tolling arrangements, and to expand our generation capacity in a market where we have an existing presence.

The aggregate purchase price was comprised of (i) $135 million cash, which was reduced by a purchase price adjustment of approximately $2 million; (ii) transaction costs of approximately $16 million, approximately $3 million of which were paid in 2004, and (iii) the assumption of $919 million of face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005. Please read Note 6—Debt—Independence Debt for additional information regarding the debt assumed.

The allocation of purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques. The allocation is still preliminary at this time; however, we do not expect material changes. We anticipate finalizing our allocation of purchase price in 2005, once the final tax basis of the assets and liabilities acquired has been determined and physical inventory counts are finalized. The acquisition resulted in an excess of the fair value of assets acquired over cost of the acquisition. This excess was then allocated to property plant and equipment and intangible assets acquired, including intangibles arising from contracts with us, on a pro-rata basis.

The following table summarizes the preliminary fair values of the assets and liabilities acquired at the date of acquisition, January 31, 2005 (in millions):


Other current assets	$	87
Restricted cash and investments		132
Property, plant, and equipment		380
Assets from risk-management activities		62
Intangible assets		709

Total assets acquired		1,370

Current liabilities		(96	)
Deferred income taxes		(269	)
Other long-term liabilities		(59	)
Long-term debt		(797	)

Total liabilities assumed		(1,221	)

Net assets acquired	$	149

Included in the assets acquired are restricted cash and investments of approximately $132 million. The restricted investments include Federal Home Loan Bank Bonds, U.S. Treasury Bonds, and high-grade short-term

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

commercial paper. The restricted cash and investments are related to a sinking fund required by Independence debt instruments, including a major overhaul reserve, a debt service reserve, a principal payment reserve, an interest reserve and a project restoration reserve. Restrictions on the cash and investments are scheduled to be lifted at the end of the project financing term in 2014. For further discussion, please see Note 6—Debt—Independence Debt.

Of the $709 million of acquired intangible assets, $526 million was allocated to the firm capacity sales agreement with Con Edison. This asset will be amortized on a straight-line basis over the ten-year remaining life of the contract, through October 2014. In addition, Independence holds a power tolling contract, valued at $166 million, and a gas supply agreement, valued at $17 million, with another of our subsidiaries. Upon completion of our purchase of Independence, this power tolling agreement and gas supply agreement were effectively settled, which resulted in a first quarter 2005 charge equal to their fair values, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination.” We recorded a first quarter 2005 pre-tax charge of $183 million, which is included in cost of sales on our unaudited condensed consolidated statements of operations.

Effective April 1, 2005, we exercised our right to require Exelon to decommission, sell, or otherwise dispose of three of the four natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon will direct the disposition of these facilities, and will indemnify us with respect to all past and present operations. We will continue to evaluate our involvement with the remaining natural gas-fired merchant facility, as we retain our right for a 180-day period following the January 31, 2005 purchase date to determine whether to continue operating the asset. Further, Exelon is entitled to cause us to decommission, sell, or bankrupt any or all of the four hydroelectric facilities owned by ExRes, for which we have been indemnified for any losses.

Dispositions

Sale of Illinois Power. On September 30, 2004, we sold all of our outstanding common and preferred shares of Illinois Power Company, which formerly comprised our REG segment, as well as our 20% interest in the Joppa power generation facility, to Ameren Corporation for $2.3 billion. The $2.3 billion sale price consisted of Ameren’s assumption of $1.8 billion of Illinois Power’s debt and preferred stock obligations, cash proceeds of approximately $375 million and an additional $100 million of cash placed in escrow. At March 31, 2005 and December 31, 2004, we reflected the balance held in escrow in prepayments and other current assets on our unaudited condensed consolidated balance sheets. Under the escrow agreement, which we filed as an exhibit to our third quarter 2004 Form 10-Q, the $100 million deposited by Ameren will be released to us upon the satisfaction of one of three conditions including the occurrence of specified events relating to contingent environmental liabilities associated with Illinois Power’s former generating facilities (currently owned by DMG). Once approved by the Illinois federal district court, we believe that the Baldwin consent decree announced in March 2005 will satisfy this condition and entitle us to receive the $100 million in escrowed funds. We expect this consent decree to receive such approval in the second quarter 2005. Please read Note 9—Commitments and Contingencies—Baldwin Station Litigation for further discussion of this consent decree. During the time that these funds remain in escrow, we will receive quarterly payments equivalent to the interest income earned on such funds.

During the first quarter 2005 we paid approximately $5 million to Ameren for a final working capital purchase price adjustment.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Also on September 30, 2004, we entered into a two-year power purchase agreement with Illinois Power. Under the terms of this new agreement, which became effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48.00 per KW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. 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 of $16 per KW-yr with an option to purchase energy at market-based prices.

During the first quarter 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale on September 30, 2004. SFAS No. 144 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. Depreciation and amortization expense related to Illinois Power totaled $10 million in the three months ended March 31, 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 (loss) 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 our unaudited condensed consolidated statements of operations.

Further, 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 loss from discontinued operations, net of taxes, on our 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 EITF Issue 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, 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 beginning in January 2005. Consequently, because we still have significant continuing involvement with Illinois Power, we will continue to include the historical results of Illinois Power’s operations as part of our continuing operations. Additionally, power sales to Illinois Power occurring subsequent to the disposition will be reported in our consolidated statements of operations as third party sales. Approximately $75 million of revenues, derived from power sales to Illinois Power occurring subsequent to the disposition, are reflected in our continuing operations for the period ending March 31, 2005.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Had the results of Illinois Power been excluded from our comparative results as though the sale had occurred on January 1, 2004, our revenues, net income applicable to common stockholders, and associated basic and diluted earnings (loss) per share would have approximated the following pro forma amounts for the period ended March 31, 2004 (in millions, except per share data):


Revenues:
As reported	$	1,657
Pro forma		1,335

Net income applicable to common stockholders:
As reported	$	65
Pro forma		57

Earnings per share—Net income applicable to common stockholders:
Basic—as reported	$	0.17
Basic—pro forma	$	0.15
Diluted—as reported	$	0.14
Diluted—pro forma	$	0.13

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 our unaudited condensed consolidated statements of operations.

Capital Loss Valuation Allowance. As a result of the transactions discussed above, as well as other transactions that, at the time, we 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 on our unaudited condensed consolidated statements of operations.

Discontinued Operations

As part of our restructuring plan, we sold or liquidated some of our operations during 2003, including 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, 2005
Income from operations before taxes	$	4	$	—		$	4
Income (loss) from operations after taxes		4		(1	)		3

Three Months Ended March 31, 2004
Income from operations before taxes	$	17	$	3		$	20
Income from operations after taxes		12		2			14

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

In the first quarter 2005, we recognized $4 million of pre-tax income associated with U.K. CRM’s receipt of $4 million from a third party bankruptcy settlement.

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 discussion. 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 2005 activity for the liabilities recorded in connection with this restructuring:


	Severance		Cancellation Fees and Operating Leases			Total
	(in millions)
Balance at December 31, 2004	$	3	$	25		$	28
2005 adjustments to liability		—		(1	)		(1	)
Cash payments		—		(2	)		(2	)

Balance at March 31, 2005	$	3	$	22		$	25

We expect the $22 million accrual as of March 31, 2005 associated with cancellation fees and operating leases to be paid by the end of 2007 when the leases expire.

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-33 of our Form 10-K.

Cash Flow Hedges. We enter into financial derivative instruments that qualify as cash flow hedges. Instruments related to our GEN and NGL businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin. Interest rate swaps have been used to convert floating interest-rate obligations to fixed-rate obligations.

During the three months ended March 31, 2005, we recorded a $4 million charge related to 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, 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, 2005 and 2004, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

The balance in cash flow hedging activities, net at March 31, 2005 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 $25 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 2006. 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 floating-rate debt. During the three months ended March 31, 2005 and 2004, 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, 2005 and 2004, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

Net Investment Hedges in Foreign Operations. Although we have exited a substantial amount of our foreign operations, we continue to 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, 2005, we had no net investment hedges in place.

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


	March 31, 2005			December 31, 2004
	(in millions)
Cash flow hedging activities, net	$	(22	)	$	(16	)
Foreign currency translation adjustment		16			16
Minimum pension liability		(13	)		(13	)

Accumulated other comprehensive loss, net of tax	$	(19	)	$	(13	)

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 had accumulated in stockholders’ equity.

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:


	March 31, 2005		December 31, 2004
	(in millions)
Equity affiliates:
GEN investments	$	339	$	337
NGL investments		77		78

Total equity affiliates		416		415
Other affiliates, at cost		—		6

Total unconsolidated investments	$	416	$	421

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Summarized aggregate financial information for our unconsolidated equity investment in West Coast Power and our equity share thereof was:


	Three Months Ended March 31,
	2005				2004
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	86	$	43	$	167	$	83
Operating income		—		—		70		35
Net income		2		1		70		35

Summarized aggregate financial information for unconsolidated equity investments, exclusive of our investment in West Coast Power, and our equity share thereof was:


	Three Months Ended March 31,
	2005				2004
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	90	$	29	$	202	$	76
Operating income		13		4		42		18
Net income		12		3		26		12

Earnings from unconsolidated investments of $4 million for the three months ended March 31, 2005, include the $3 million above and $1 million from West Coast Power. Earnings from unconsolidated investments of $40 million for the three months ended March 31, 2004 include the $12 million above and $35 million from West Coast Power, offset by a $7 million impairment of our Michigan Power equity investment discussed below.

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 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 sale price.

Note 6—Debt

Revolving Credit Facility. During the three-month period ended March 31, 2005, we increased letters of credit under our $700 million revolving credit facility by $9 million in the aggregate, resulting in a total of $103 million outstanding at March 31, 2005. As of March 31, 2005, there were no borrowings outstanding under this facility. During the period from March 31, 2005 through May 5, 2005, we increased our outstanding letters of credit under this facility by $143 million.

Repayments. In the first quarter 2005, we paid the outstanding $18 million balance on our 8.125% senior notes, which matured in March 2005. We also made payments of $1 million related to the DHI May 2004 term loan.

Independence Debt. On January 31, 2005, we completed the acquisition of ExRes, the parent company of Sithe Energies and Independence. Upon the closing, we consolidated $919 million in face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005, for which certain of the entities acquired are obligated. Please see Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies for further discussion of this transaction.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Long-term debt consolidated upon completion of the Sithe Energies acquisition consisted of the following as of January 31, 2005:


	Face Value		Premium / (Discount)			Fair Value
	(in millions)
Subordinated Debt, 7.0% due 2034	$	419	$	(167	)	$	252
Senior Notes, 8.5% due 2007		91		3			94
Senior Notes, 9.0% due 2013		409		42			451

Total Independence Debt	$	919	$	(122	)	$	797

Principal payments on the Independence senior notes, which we refer to as the “senior debt,” are due semiannually through 2013 and principal payments on the subordinated debt begin in 2015. Annual maturities of the Independence debt are as follows: 2005—$34 million; 2006—$37 million; 2007—$40 million; 2008—$44 million; 2009—$57 million; and thereafter—$707 million. The senior debt and subordinated debt are secured by substantially all of the assets of Independence, but are not guaranteed by Dynegy or DHI.

The terms of the indenture governing the senior debt, among other things, prohibit cash distributions by Independence to its affiliates, including Dynegy, unless certain project reserve accounts are funded to specified levels and the required debt service coverage ratio is met. The indenture also includes other covenants and restrictions, relating to, among other things, prohibitions on asset dispositions and fundamental changes, reporting requirements and maintenance of insurance. As of March 31, 2005, Independence had current restricted cash of $61 million and non-current restricted cash of $49 million as reflected on our unaudited condensed consolidated balance sheets. As of March 31, 2005, Independence had short-term and long-term restricted investment balances of $3 million and $36 million, respectively. The balances are included in prepayments and other current assets and restricted investments, respectively, on our unaudited condensed consolidated balance sheets.

Note 7—Related Party Transactions

We engage in transactions with Chevron Corporation, which we refer to as “Chevron,” 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 12—Related Party Transactions—Transactions with ChevronTexaco beginning on page F-47 of our Form 10-K for further discussion.

Series C Convertible Preferred Stock. As discussed in Note 14—Redeemable Preferred Stock—Series C Convertible Preferred Stock beginning on page F-54 of our Form 10-K, in August 2003, we issued to CUSA 8 million shares of our Series C convertible preferred stock due 2033, which we refer to as our “Series C preferred stock.” We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. We made a semi-annual dividend payment of $11 million in February 2005.

Note 8—Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

outstanding during the period. The reconciliation of basic earnings (loss) per share from continuing operations to diluted earnings (loss) per share from continuing operations is shown in the following table:


	Three Months Ended March 31,
	2005			2004
	(in millions, except per share amounts)
Income (loss) from continuing operations	$	(265	)	$	56
Preferred stock dividends		(5	)		(5	)

Income (loss) from continuing operations for basic earnings per share		(270	)		51
Effect of dilutive securities:
Interest on convertible subordinated debentures		2			1
Dividends on Series C preferred stock		5			5

Income (loss) from continuing operations for diluted earnings per share	$	(263	)	$	57

Basic weighted-average shares		379			376
Effect of dilutive securities:
Stock options and restricted stock		2			2
Convertible subordinated debentures		55			55
Series C preferred stock		69			69

Diluted weighted-average shares		505			502

Earnings (loss) per share from continuing operations
Basic	$	(0.71	)	$	0.14

Diluted (1)	$	(0.71	)	$	0.11

(1)

When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share,” prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2005.

Note 9—Commitments and Contingencies

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.

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—Contingencies, Commitments, Guarantees and Indemnifications beginning on page F-16 of our Form 10-K 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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 filing of our Form 10-K:

•

In April 2005, we reached a settlement in our shareholder class action litigation. As part of the settlement, we will make an aggregate settlement payment of $468 million (including $150 million funded by insurance proceeds and the issuance of $68 million in Class A common stock) and cause the resignation and replacement of two members of the Dynegy board of directors who are defendants in the litigation with two new directors from a list of candidates proposed by the lead plaintiff. This settlement is subject to court approval, which is expected in the second half of 2005.

•

Also in April 2005, we reached a settlement in the shareholder derivative litigation pending in state court. Under this settlement, which is subject to court approval, we have agreed to pay approximately $5 million in attorneys fees and expenses and to effect certain corporate governance changes, many of which were previously implemented since the initiation of the litigation. Court approval is also expected in the second half of 2005.

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.

Shareholder Litigation. In April 2005, we settled, subject to court approval, 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 as filed principally alleged 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 are lead plaintiff and Lerach Coughlin Stoia & Robbins, LLP is class counsel.

In October 2004, in response to our March 2004 motions to dismiss, the judge entered an order dismissing all of plaintiff’s claims under (i) the Securities Act of 1933, except those relating to Dynegy’s March 2001 note offering and December 2001 common stock offering, and (ii) the Securities Exchange Act of 1934, except those dealing with Project Alpha and two alleged round-trip trades. Further, the judge scheduled the trial to commence in May 2005. Also in October 2004, the plaintiff voluntarily dismissed its claim under the Securities Act relating to our March 2001 note offering. The parties filed motions on the class certification issue in the fourth quarter 2004. In December 2004, the court issued an order identifying the class period for the Exchange Act claims as June 21, 2001 through July 22, 2002, and the class period for the Securities Act claims to begin December 20, 2001.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

In April 2005, following mediation, the parties to the shareholder class action litigation reached a comprehensive settlement agreement which is subject to approval by the court and provides for the following:

•

An aggregate settlement payment by Dynegy of $468 million, comprised of a $150 million cash payment to be funded by insurance proceeds, a $250 million cash payment by DHI, and the issuance to the plaintiffs of $68 million in, or approximately 17.5 million shares of, Dynegy’s Class A common stock. The number of shares to be issued is based on a calculation using a volume weighted average stock price for the 20 trading days ending April 15, 2005. We are required to make two payments totaling $250 million during 2005, consisting of an initial payment of $175 million, which we paid in May 2005, followed by a second payment of $75 million upon court approval, which we expect during the second half of 2005. We will also issue the shares of Class A common stock following court approval.

•

The resignation of two members of the Dynegy board of directors who are defendants in the litigation, with the vacancies resulting from such resignations to be filled by two new directors from a list of at least five qualified candidates submitted by the lead plaintiff. We will also nominate such directors for election at our next meeting of shareholders at which directors are elected following our 2005 annual meeting of shareholders scheduled for May 19, 2005.

We filed the settlement agreement with the court on May 9, 2005, and we are awaiting preliminary approval of the agreement and the scheduling of a fairness hearing. We cannot predict with certainty whether the court will approve the settlement or, in the event the settlement is ultimately rejected, whether we will incur any liability in connection with this litigation absent the proposed settlement. An adverse result in this litigation absent the proposed settlement could have a material adverse effect on our financial condition, results of operations and cash flows. Reserves have been provided in connection with this litigation.

In addition, we were named as 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 Texas state court. In February 2005, the plaintiffs voluntarily dismissed the federal derivative matter. In April 2005, the parties to the shareholder derivative litigation pending in Texas state court reached a settlement, and the related settlement agreement was filed with the court on May 10, 2005. A hearing on our settlement agreement has been scheduled for May 11, 2005. Under this settlement agreement, which is also subject to court approval, Dynegy has agreed to effect certain corporate governance changes, many of which were implemented since the claim was originally filed, and to pay related attorney fees and expenses incurred by the plaintiffs in the aggregate amount of approximately $5 million. The ongoing corporate changes relate to director qualifications, the involvement of a lead independent director, the structure and function of certain Board committees and other governance enhancements.

Dynegy and the other defendants did not admit any liability in connection with either of the proposed settlements described above, and there were no findings of any violations of the federal securities laws. We recorded a first quarter pre-tax charge of $222 million ($156 million after-tax) related to these settlements and associated legal expenses. This pre-tax charge is reflected in general and administrative expenses on our unaudited condensed consolidated statements of operations.

ERISA/Illinois Power 401(k) Litigation. In January 2005, three Illinois Power employees participating in the Illinois Power Company Incentive Savings Plan For Employees Covered Under a Collective Bargaining Agreement, which we refer to as the “Illinois Power 401(k) Plan,” purporting to represent all Illinois Power employees who held Dynegy common stock through the Illinois Power 401(k) Plan during the period from February 2000 through September 2004, filed a lawsuit in federal court in the Southern District of Illinois against us, Illinois

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Power, DMG and several individual defendants. The complaint alleges violations of ERISA in connection with the Illinois Power 401(k) Plan that are similar to the claims made in the ERISA litigation settled in December 2004, including claims that certain of our former and current officers (who are past and present members of our Benefit Plans Committee) 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 gas price index reporting. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorney’s fees and other costs. We do not believe that any liability which might be incurred by Dynegy as a result of this litigation would have a material adverse effect on our financial condition, results of operations or cash flows.

Baldwin Station Litigation. Since November 1999, DMG has been the subject of an NOV from the EPA and a complaint filed by the EPA and the DOJ in federal district court alleging violations of the Clean Air Act and related federal and Illinois regulations related to certain maintenance, repair and replacement activities at our Baldwin generating station. We have reached agreement with the EPA, the DOJ, the State of Illinois and the environmental group intervenors on terms to settle the litigation. A consent decree was signed by all parties and lodged with the U.S. District Court for the Southern District of Illinois on March 7, 2005. As required by the Clean Air Act, the consent decree was posted in the Federal Register and the period for public comment on the terms thereof has expired. The Court set a hearing on the consent decree for late May 2005. We expect the consent decree to be entered and approved by the Court in the second quarter 2005. The consent decree provides for our payment of a civil penalty of $9 million and for our funding of several environmental projects in the additional aggregate amount of $15 million. It also requires us to install additional emission controls at our Baldwin, Vermilion and Havana plants. Under the terms of the settlement, we will invest $321 million in emission control projects through 2010, including the previously planned conversion of our Vermilion facility to low-sulfur PRB coal, with an additional $224 million in emission control projects in the 2011-2012 timeframe. The decree settles all claims in the litigation, as well as similar claims that might have been brought related to maintenance, repair and replacement activities at other DMG plants including Vermilion, Wood River, Hennepin and Havana.

Reserves have been provided in an aggregate amount adequate to cover the civil penalties and the environmental projects provided for under the consent decree.

The EPA previously requested information, which we provided, concerning maintenance, repair and replacement activities at our Danskammer and Roseton plants. The consent decree does not cover any activities at the Danskammer and Roseton plants. Although the EPA could eventually commence enforcement actions based on activities at these plants, we are unable to assess the likelihood of any such additional EPA enforcement actions.

California Market Litigation. We and numerous other power generators and marketers are defendants in numerous lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis and seeking unspecified treble damages. The cases included: Pamela R. Gordon v. Reliant Energy Inc., et al.; Ruth Hendricks v. Dynegy Power Marketing, et al.; The People of the State of California v. Dynegy Power Marketing, et al.; Sweetwater Authority v. Dynegy Inc., et al.; People of the State of California ex rel. Bill Lockyer, Attorney General v. Dynegy Inc., et al.; Public Utility District No. 1 of Sonomish County v. Dynegy Power Marketing, et al.; and Bustamante [I] v. Dynegy Inc., et al. Eventually, these cases were coordinated before a single federal judge, who dismissed two of them, Lockyer and Sonomish County, in the first quarter 2003 on the grounds of FERC preemption and the filed rate doctrine. The Ninth Circuit Court of Appeals affirmed these dismissals in June 2004 and September 2004, respectively. In Lockyer, plaintiffs’ Petition for Writ of Certiorari to the U.S. Supreme Court was denied in April 2005. Plaintiffs in Sonomish County filed a Petition for Writ of Certiorari to the U.S. Supreme Court in November 2004. The five remaining coordinated cases were ultimately remanded to California state court, where we intend to file a motion to dismiss as soon as practicable.

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Between April and October 2002, the following nine additional 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: Pier 23 Restaurant v. PG&E Energy Trading, et al.; Bronco Don Holdings v. Duke Energy Trading and Marketing, LLC, et al.; T&E Pastorino Nursery v. Duke Energy Trading and Marketing LLC, et al.; Century Theaters, Inc. v. Allegheny Energy Supply Company, et al.; J&M Karsant Family Ltd. Partnership v. Duke Energy Trading and Marketing, LLC, et al.; Leo’s Day & Night Pharmacy v. Duke Energy Trading and Marketing, LLC, et al.; El Super Burrito v. Allegheny Energy Supply Company, LLC, et al.; RDJ Farms, Inc. v. Allegheny Energy Supply Company, et al.; and Millar v. Allegheny Energy Supply Company, LLC, et al. The complaints allege unfair, unlawful and deceptive practices in violation of the California Unfair Business Practices Act and seek injunctive relief, restitution and unspecified damages. Although some of the allegations in these lawsuits are similar to those in the seven cases referenced above, these lawsuits include additional allegations relating to, among other things, the validity of the contracts between these power generators and the CDWR. Following removal of these cases, the federal court dismissed eight of the nine actions and plaintiffs appealed. In February 2005, the Ninth Circuit affirmed the dismissals. The remaining case, Millar, was ultimately remanded to state court, where we intend to file a motion to dismiss as soon as practicable.

In December 2002, two additional actions were filed on behalf of consumers and businesses in Oregon, Washington, Utah, Nevada, Idaho, New Mexico, Arizona and Montana that purchased energy from the California market, alleging violations of the Cartwright Act and unfair business practices. These cases were subsequently dismissed and refiled in California Superior Court as one class action complaint styled Jerry Egger v. Dynegy Inc., et al. We 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. Plaintiffs challenged the removal, however, and the federal court stayed its ruling pending a decision by the Ninth Circuit on the five coordinated cases referenced above. Although the Ninth Circuit issued a decision remanding those cases, no ruling has been made with respect to Egger.

In May and June 2004, two additional lawsuits, Wah Chang v. Avista Corporation, et al. and City of Tacoma v. American Electric Power Service Corporation, et al., were filed in Oregon and Washington federal courts against several energy companies, including Dynegy Power Marketing, Inc., seeking more than $30 million in compensatory damages resulting from alleged manipulation of the California wholesale power markets. In February 2005, the respective federal courts granted our motions to dismiss. Shortly thereafter, plaintiffs in both cases filed notices of appeal to the Ninth Circuit.

In October 2004, Preferred Energy Services, an independent electric services provider in California, filed suit against us and several other defendants alleging that the defendants, in violation of the California anti-trust and unfair business practices statutes, engaged in unfair, unlawful and deceptive practices in the California wholesale energy market from May 2000 through December 2001. Plaintiff, which formerly sold electricity generated from renewable sources in the California market, claims to have been forced out of business by the defendants’ conduct and is seeking $5 million in compensatory damages, as well as treble damages. In March 2005, we were served with the suit. We removed the action to federal court in April 2005.

We believe that we have meritorious defenses to these claims and intend to defend vigorously against them. We cannot predict with certainty whether we will incur any liability 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.

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FERC and Related Regulatory Investigations—Requests for Refunds. In October 2004, the FERC approved in all respects the agreement announced by Dynegy and West Coast Power in April 2004 which provided for the settlement of FERC claims relating to western energy market transactions that occurred from January 2000 through June 2001. Market participants (other than the parties to the settlement) were permitted to opt into this settlement and share in the distribution of the settlement proceeds, and most of these other market participants have done so. The entitlement to refund and/or the liability of each non-settling market participant will be determined by the Cal ISO. Under the terms of the settlement, we will have no further liability to these non-settling parties. The settlement further provides that we are entitled to pursue claims for reimbursement of fuel costs against various non-settling market participants. We are currently pursuing these claims but are unable to predict the amounts that may be recovered from such parties.

The settlement does 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 does not apply to 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.

Enron Trade Credit Litigation. Shortly before their bankruptcy filing in the fourth quarter 2001, we determined that 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 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 some dispute. We have 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 ongoing refinement of the values of past transactions, we reduced the $84 million amount that we originally believed we were owed by Enron to approximately $57 million, including the liabilities under the gas transportation agreement related to the Sithe Independence power tolling arrangement. This change in value had no impact on our results, as the net receivable was fully reserved in the fourth quarter 2001. In the event that Enron is victorious in its position that the master netting agreement is unenforceable, our exposure to Enron would be approximately $216 million, with as much as $220 million in unsecured Dynegy claims remaining to enforce against the bankruptcy estate. 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

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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. The appellate court denied our appeal as interlocutory in November 2004. We also filed a motion with the Bankruptcy Court seeking to withdraw from mediation to enable us to proceed to discovery and eventually trial to determine the enforceability of the master netting agreement under the U.S. Bankruptcy Code. The Bankruptcy Court denied our motion and ordered us to resume mediation. The parties engaged in a second court-ordered mediation in November 2004, which was followed by further discussions between the parties, but no settlement has been reached.

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 claims. Reserves have been provided in an aggregate amount we consider reasonable with respect to Enron’s claims. 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.

Severance Arbitrations. Our former CEO, Chuck Watson, former President, Steve Bergstrom, and former CFO, Rob Doty, each filed for arbitration pursuant to the terms of their employment/severance agreements. These former officers made arbitration claims seeking payments of up to approximately $28.7 million, $10.4 million and $3.4 million, respectively. In addition, each claimed additional amounts related to long-term incentive payments. In May 2004, pursuant to the decision of the arbitration panel, we paid Mr. Bergstrom $10.4 million plus attorneys’ fees, costs and interest. Shortly after the panel’s decisions in the Bergstrom matter, we elected to enter into mediation with Mr. Watson. Through mediation, we agreed to pay Mr. Watson $22 million to settle his severance claims. We recorded an expense in the second quarter 2004 in the amount of the difference between this settlement amount and our severance accrual for this matter. Please read Note 4—Restructuring and Impairment Charges—Severance and Other Restructuring Costs beginning on page F-31 of our Form 10-K for further discussion regarding the accrual relating to these former executive officers.

The arbitration with respect to Mr. Doty is currently scheduled to commence in September 2005. Mr. Doty’s agreement is subject to interpretation, and we maintain that the amount owed is substantially lower than the amount sought. We recorded a severance accrual we consider reasonable relating to this proceeding.

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 plaintiff’s petition, as amended, alleges (i) excessive field losses of natural gas from wells owned by the plaintiff, (ii) that Versado engaged in “sham” transactions with affiliates, resulting in Versado not receiving fair market value when it sells gas and liquids, and (iii) 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 plaintiff’s claim with respect to the alleged “sham” transactions and index manipulation, among others, were severed by the court and abated for a future trial, and the jury found in favor of the plaintiff on the remaining lost gas claim, awarding approximately $1.6 million in damages. In May 2004, our motion to set aside this judgment was granted by the court and the jury’s award to the plaintiff was vacated. The plaintiff filed its notice of appeal with the court in October 2004 and its appellate brief in December 2004. The parties attended mediation in February 2005, but did not reach a settlement. Settlement discussions continue outside of mediation. Barring settlement, we expect to file our response to the plaintiff’s appellate briefs in the second quarter 2005. 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.

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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: ABAG v. Sempra Energy et al. (filed in state court in November 2004); Ableman Art Glass v. Encana Corporation et al. (class action filed in federal court in December 2004); Benschiedt (class action filed in state court in February 2004); Bustamante v. The McGraw Hill Companies et al. (class action filed in state court in November 2002); City and County of San Francisco v. Dynegy Inc. et al. (filed in state court in July 2004); County of San Diego v. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al. (filed in state court in July 2004); County of San Mateov. Sempra Energy et al. (filed in state court in December 2004); County of Santa Clarav. Dynegy Inc., Dynegy Marketing and Trade, West Coast Power, et al. (filed in state court in July 2004); Fairhaven Power Company v. Encana Corp. et al. (class action filed in federal court in September 2004); In re Natural Gas Commodity Litigation (class action filed in federal court in January 2004); Leggett v. Duke Energy et al. (class action filed in state court in January 2005); Multiut v. Dynegy Inc. (filed in federal court in December 2004); Nelson Brothers LLC v. Cherokee Nitrogen v. Dynegy Marketing and Trade and Dynegy Inc. (filed in state court in April 2003); Nurserymen’s Exchange v. Sempra Energy et al. (filed in state court in October 2004); Older v. Dynegy Inc. et al. (filed in federal court in September 2004); Owens-Brockway v. Sempra Energy at al. (filed in state court in January 2005); People of the State of Montana et al. v. Williams Energy Marketing et al. (filed in federal court in July 2003); Sacramento Municipal Utility District (SMUD) v. Reliant Energy Services, et al. (filed in state court in November 2004); School Project for Utility Rate Reduction v. Sempra Energy et al. (filed in state court in November 2004); Sierra Pacific Resources and Nevada Power Company v. El Paso Corp. et al. (filed in federal court in April 2003); Tamco v. Dynegy Inc. et al. (filed in state court in December 2004); Texas-Ohio Energy, Inc. v. CenterPoint Energy Inc., et al. (class action filed in federal court in November 2003); and Utility Savings& Refund v. Reliant Energy Services, et al. (class action filed in federal court in November 2004). 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. We have not been served in the Montana case.

Pursuant to various motions filed by the parties to the litigation described above, the gas index pricing lawsuits pending in state court (except for Nelson Brothers) have been consolidated before a single judge in state court in San Diego. These cases are now entitled the “Judicial Counsel Coordinated Proceeding (JCCP) 4221, 4224, 4226, and 4228, the Natural Gas Anti-Trust Cases, I, II, III, & IV,” which we refer to as the “Coordinated Gas Index Cases.” The parties are presently engaged in discovery. The Nelson Brothers lawsuit involves an alleged breach of a gas purchase contract and is pending in Alabama state court. The parties are presently engaged in discovery. In March 2005, we moved to compel the matter to arbitration. The trial court denied the motion, and in April 2005 we appealed the decision to the Alabama Supreme Court.

As to the gas index pricing lawsuits filed in federal court, the Sierra Pacific case was dismissed in December 2004 on defendants’ motion. In Texas-Ohio, the defendants filed a motion to dismiss in May 2004, which the court granted in April 2005. In the In re Natural Gas Commodity Litigation matter, pending in New York federal court, the parties are actively engaged in discovery following denial of the appeal of the previous denial of defendants’ motion to dismiss. In April 2005, defendants filed a joint opposition to the motion for class certification filed by the plaintiffs earlier in the year. The Multiut case involves a counterclaim filed by the defendant, Multiut, against whom we have a pending breach of gas purchase contract claim. That case is proceeding in federal court in Illinois. The remaining federal court cases (Abelman, Fairhaven Power, Utility Savings and Leggett) are pending transfer, or have already been transferred, to the federal judge in Nevada who presided over the Texas-Ohio matter.

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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 in 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.

Stand Energy Litigation (formerly Atlantigas Corp. Litigation). In November 2003, Atlantigas Corporation filed suit in Maryland against us and several other defendants alleging certain conspiracies between natural gas shippers and storage facilities. The complaint alleged that the interstate pipelines provided preferential storage and transportation services to their own unregulated marketing affiliate in return for percentages of the profits reaped by the marketing affiliate and that such conduct violated applicable FERC regulations and the federal antitrust laws and constituted common law tortious interference with contractual and business relations. In addition, the complaint claimed we conspired with the other defendants to receive preferential natural gas storage and transportation services at off-tariff prices. The complaint sought unspecified compensatory and punitive damages. In January 2004, the defendants filed motions to dismiss the plaintiff’s claims. In July 2004, prior to the Court’s ruling on the defendants’ motions, the plaintiff voluntarily dismissed the Maryland federal court action against all defendants. Shortly thereafter, plaintiff filed a class action lawsuit in a West Virginia state court against several defendants, excluding us, on similar grounds to the previous Maryland federal action. In October 2004, the plaintiff filed an amended class action complaint naming us as a defendant in the litigation. In response, Columbia, the primary defendant, filed a motion to strike the amended pleading as untimely. In January 2005, the Court denied Columbia’s motion to strike and retroactively granted the plaintiff leave to amend. Shortly thereafter, the newly added defendants filed motions to dismiss on various grounds. Oral argument on some of the pending motions occurred in April 2005. We are analyzing these claims and intend to defend against them vigorously. We cannot predict with certainty whether we will incur any liability in 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.

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 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 one of its liquidators admitted, for purposes of the liquidation, the plaintiffs’ claims in the amount of $30 million. Although this lawsuit was initially stayed pending the Austrian insolvency proceeding, the stay was lifted and we filed our answer in May 2004. The parties are actively engaged in discovery. In December 2004, the plaintiffs filed a motion for partial summary judgment on issues of liability. Our response was filed in March 2005, and the plaintiffs’ reply is due in May 2005.

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, results of operations or cash flows. Reserves have been provided in connection with this litigation.

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Alleged Marketing Contract Defaults. We have posted collateral to support a portion of our obligations in our CRM business, including our obligations under one of our 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 generally 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 defendant has appealed the court’s rulings regarding the dismissed and reinstated charges. The Fifth Circuit Court of Appeals heard argument on these matters in October 2004, and reinstated all of the charges against the defendant in December 2004. A trial date has not yet been set on this indictment. In addition, in December 2004, a second indictment was filed against this same former employee and other individuals alleging conspiracy to falsely report gas prices to various index publications. That indictment is scheduled for trial in October 2005.

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 pled guilty to conspiracy to commit securities fraud. These two former employees have not been sentenced pending the completion of the government’s investigation. Trial on the indictment against the third employee was held in November 2003. The defendant was convicted on all charges and, in March 2004, sentenced to a term of approximately 24 years in federal prison.

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 issued a Grand Jury subpoena requesting information related to our activities in the California energy markets in November 2002. We

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continue to cooperate 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 cooperated with the Department of Labor throughout this investigation, which 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. In February 2005, we received a letter from the Department of Labor indicating that, as a result of our recent settlement in the ERISA litigation, it intended to take no further action with respect to its investigation of the Dynegy Inc. 401(k) Plan. However, its investigation is ongoing as it relates to the Illinois Power 401(k) Plans, and the recent litigation relating to those plans described above.

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.

Danskammer Water Permit. Our wastewater discharges are permitted under the Clean Water Act and analogous state laws. These permits are subject to review every five years. The state-issued water discharge permits associated with the DNE facilities expired in 1992. However, under New York State law, the authorization arising under these permits remains in effect and allows for continued operation under the terms of the original permit, provided that a timely and sufficient application requesting renewal has been filed as required. In May 1992, the then owner of the Danskammer facility filed a renewal application which we believe was timely and sufficient. In November 2002, several environmental groups filed suit in the Supreme Court of the State of New York seeking, among other things, a declaratory judgment that the Danskammer water intake and discharge permit expired because of alleged deficiencies in the renewal application process. In September 2004, the Court ruled that the water intake and discharge permit for our Danskammer facility is void, but stayed the enforcement of the decision pending further review by the Court or by the Appellate Division.

In October 2004, we filed our appeal of the Court’s decision with the Appellate Division, and we intend to pursue vigorously our challenge to the Court’s ruling voiding our permit. We will also continue to seek renewal of the water intake and discharge permit in proceedings before the New York State Department of Environmental Conservation. If our appeal is ultimately unsuccessful, we may be required to suspend operations at our Danskammer facility pending receipt of final approval of the renewal of our water intake and discharge permit. We cannot predict with any certainty the outcome of these proceedings; however, an adverse outcome, particularly a requirement that we suspend operations at our Danskammer facility for any period of time, could have a material adverse effect on our financial condition, results of operations and cash flows.

FERC Market-Based Rate Authority. The FERC’s market-based rate authority allows the sale of power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic

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(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

re-review. In April 2004, the FERC issued an order concerning the ability of companies to sell electricity at market-based rates. In this order, the FERC adopted two new tests for assessing generation market power. If an applicant for market-based rate authority is found to possess generation market power under these tests and is unsuccessful in challenging that finding, the applicant may either propose mitigation measures or adopt cost-based rates. If the FERC finds that the proposed mitigation measures fail to eliminate the ability to exercise market power, the applicant’s market-based rate authority will be revoked and the applicant will be subject to cost-based default rates, or other cost-based rates proposed by the applicant and approved by the FERC. The FERC issued a follow up order in May 2004, which it upheld in July 2004, (i) addressing the implementation process for pending and new market-based rate applications and (ii) establishing a timeline for entities with FERC market-based rate authority to provide the FERC with their market power assessment. These orders required entities that were previously granted market-based rate authority by the FERC, including entities with pending applications for re-review, to resubmit their applications in accordance with the new directive. Consequently, our entities with applications pending since February 2002, as well as the entities we acquired in January 2005 in connection with the Sithe Energies acquisition, timely resubmitted their applications to the FERC.

In December 2004, the FERC ruled that once the MISO became a single market and performed functions such as single central commitment and dispatch with FERC-approved market monitoring and mitigation, the MISO would be considered to have a single geographic market for purposes of assessing generation market power. This condition was satisfied in April 2005 when the MISO formally launched its Midwest Energy Markets under a tariff approved by the FERC in August 2004. This ruling has enlarged the geographic area in which our DMG facilities will be evaluated for generation market power for the relevant period. Although we cannot predict with any certainty whether our applications to renew our market-based rate authority will be approved or the loss of revenues that would result from the imposition of cost-based rates, an adverse outcome with respect to these applications, and the resulting requirement that we charge cost-based rates, could have a material adverse effect on our financial condition, results of operations and cash flows.

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 19—Employee Compensation, Savings and Pension Plans beginning on page F-73 of our Form 10-K.

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


	Pension Benefits						Other Benefits
	Quarter Ended March 31,
	2005			2004			2005		2004
	(in millions)
Service cost benefits earned during period	$	3		$	6		$	1	$	1
Interest cost on projected benefit obligation		2			10			1		3
Expected return on plan assets		(2	)		(12	)		—		(1	)
Recognized net actuarial loss		1			4			—		1

Total net periodic benefit cost	$	4		$	8		$	2	$	4

Contributions. In our Form 10-K, we reported that we expected to contribute approximately $28 million to our pension plans, $18 million of which we expect to pay in September 2005, and $0.3 million to our other postretirement benefit plans in 2005. As of March 31, 2005, we made $3 million in contributions.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

Sale of Illinois Power. As a result of the sale of Illinois Power to Ameren, the number of participants in our various defined benefit pension plans and post-retirement benefit plans was reduced substantially. Consequently, our 2005 net periodic benefit cost is substantially lower than the cost for 2004. In addition, in connection with the sale, we agreed to transfer a portion of the assets in certain of our defined benefit plans to other plans maintained by Ameren. An initial asset transfer of $411 million was made in November 2004, and an additional transfer of approximately $67 million was made in the first quarter 2005.

Medicare Prescription Drug, Improvement and Modernization Act of 2003. As discussed in Note 19—Employee Compensation, Savings and Pension Plans—Medicare Prescription Drug, Improvement and Modernization Act of 2003, beginning on page F-78 of our Form 10-K, we anticipate that the amount of benefits we will pay after 2005 will be lower as a result of the new Medicare provisions described under this Act.

Note 12—Segment Information

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 our 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)

For the Interim Periods Ended March 31, 2005 and 2004

Reportable segment information for the three-month periods ended March 31, 2005 and 2004 is presented below.

Dynegy’s Segment Data for the Quarter Ended March 31, 2005

(in millions)


	GEN			NGL			REG		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	445		$	971		$	—	$	129		$	—		$	1,545
Other		—			—			—		(46	)		—			(46	)

		445			971			—		83			—			1,499
Intersegment revenues		(6	)		75			—		(57	)		(12	)		—

Total revenues	$	439		$	1,046		$	—	$	26		$	(12	)	$	1,499

Depreciation and amortization	$	(47	)	$	(21	)	$	—	$	—		$	(7	)	$	(75	)
Operating income (loss)	$	60		$	59		$	—	$	(192	)	$	(251	)	$	(324	)
Earnings from unconsolidated investments		2			2			—		—			—			4
Other items, net		—			(5	)		—		1			2			(2	)
Interest expense																(100	)

Loss from continuing operations before taxes																(422	)
Income tax benefit																157

Loss from continuing operations																(265	)
Income from discontinued operations, net of taxes																3

Net loss															$	(262	)

Total assets:
Domestic	$	7,700		$	1,596		$	16	$	1,245		$	200		$	10,757
Other		5			—			—		223			—			228

Total	$	7,705		$	1,596		$	16	$	1,468		$	200		$	10,985

Unconsolidated investments	$	339		$	77		$	—	$	—		$	—		$	416
Capital expenditures	$	(40	)	$	(10	)	$	—	$	—		$	(4	)	$	(54	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2005 and 2004

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

Total 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	)

Note 13—Subsequent Events

On April 15, 2005, we announced the comprehensive settlement of our shareholder class action litigation. For further discussion, please read Note 9—Commitments and Contingencies—Shareholder Litigation.

On May 9, 2005, we announced that we are evaluating strategic opportunities for our NGL business. We have launched a process to consider alternatives for this business. We would evaluate alternative uses for the proceeds from any such transaction, which proceeds would enable us to reduce our outstanding debt or other obligations to further deleverage our capital structure or to position our GEN business favorably in relation to future combination or consolidation opportunities. Any taxable gains from a potential divestiture would be largely offset by net operating losses, capital loss carry-forwards and tax credits.

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended March 31, 2005 and 2004

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.

GENERAL

Summary

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily in two areas of the energy industry: power generation and natural gas liquids. 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 CRM business, which primarily consists of our three remaining power tolling arrangements (excluding the Independence toll, which is now part of our GEN segment) as well as our gas transportation contracts and 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.

Operationally, our first quarter 2005 performance reflected our continued sensitivity to commodity prices. The results for our GEN segment were positively impacted by increased power prices, more than offset by (i) reduced volumes in the Northeast region resulting from an increase in the cost of fuel oil and emission allowances in relation to power prices, (ii) a scheduled outage at our Baldwin facility, and (iii) reduced equity earnings from West Coast Power as a result of the expiration of the CDWR contract. Our NGL segment’s results quarter over quarter, exclusive of gains from asset sales in 2004, improved significantly as a result of substantially higher natural gas and natural gas liquids prices, a 6% increase in the volume of natural gas liquids produced, as well as a moderately favorable fractionation, or “frac,” spread in the first quarter 2005 under which natural gas liquids recovery was profitable, as compared to an unfavorable frac spread during the same quarter in 2004. Please read “—Results of Operations” for further discussion of the comparative results of our reportable business segments.

Recent Events

In April 2005, we entered into a comprehensive settlement agreement related to the shareholder class action litigation brought by the Regents of the University of California which alleged violation of securities laws primarily related to “Project Alpha,” a structured natural gas transaction entered into by us in 2001, and which included claims for damages on behalf of a class of purchasers of Dynegy Class A common stock during the period of June 2001 to July 2002. Under the settlement agreement, which is subject to court approval, we are required to (i) make an aggregate settlement payment of $468 million, comprised of a $150 million cash payment to be funded by insurance proceeds, a $250 million cash payment, and the issuance to the plaintiffs of $68 million in (or approximately 17.5 million shares of) Dynegy’s Class A common stock and (ii) cause the resignation and replacement of two members of the Dynegy board of directors who are defendants in the litigation with two individuals from a list of at least five qualified candidates proposed by the Regents as lead plaintiff.

Also in April 2005, we entered into a settlement agreement with respect to the shareholder derivative litigation pending in Texas state court. Under this settlement agreement, which is also subject to court approval, we have agreed to effect certain corporate governance changes, many of which were implemented since the claim was originally filed, and to pay related attorney fees and expenses incurred by the plaintiffs in the aggregate amount of approximately $5 million.

We recorded a first quarter pre-tax charge of $222 million ($156 million after-tax) related to these settlements and associated legal expenses. Please read Note 9—Commitments and Contingencies—Shareholder Litigation for further discussion of these settlements. As the number of shares being issued in the settlement is fixed, this charge will fluctuate until the shares are issued.

If the proceeds from any such transaction were used to further reduce our debt and other obligations, our GEN business could achieve a capital structure approaching 50 percent net debt-to-capital, improving our ability to participate in the expected consolidation of the power sector. Additionally, any taxable gains from a potential divestiture would be largely offset by net operating losses, capital loss carry-forwards and tax credits.

We cannot make any assurances that we will enter into any such transaction, and our desire or ability to pursue any such transaction is subject to a number of factors beyond our control. Additionally, our board of directors has not committed to a plan to divest our NGL business. Any such transaction involving our NGL business would be subject to satisfactory completion of due diligence, negotiation and execution of a definitive agreement setting forth mutually agreeable structure and terms, receipt of board of directors and required regulatory approvals, and other customary conditions. References in this Management’s Discussion and Analysis of Financial Condition and Results of Operations to expected results, cash flows or financial condition for our company or any segment thereof that refer to or include results from our NGL business assume that no such transaction will occur, unless specifically stated otherwise.

Strategic Growth Opportunities

We have addressed substantially all of our significant legacy matters, and are focusing our company’s resources on operating our energy businesses safely, reliably and efficiently in order to manage the costs across our organization and to deliver value to our investors. We are also continuing to focus on identifying and evaluating strategic growth opportunities, particularly organic or “bolt-on” projects, such as the conversion of our Havana power generating facility to lower-cost and lower-emission PRB coal, to improve the operational performance and efficiency of certain assets, enabling us to realize costs savings and to capture even more of the benefit of increases in commodity prices.

Such opportunities may also include merger and acquisition activities, which we discuss and evaluate as part of our ongoing business strategy. For example, in January 2005 we completed the purchase from Exelon Corporation of all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies, Inc., which we refer to as “Sithe Energies,” and Sithe/Independence Power Partners, L.P., which we refer to as “Independence.” The financial terms of the acquisition included our payment of $120 million, net of transaction costs and cash acquired, and our consolidation of $919 million in face value project debt, which we recorded on the balance sheet at a fair value of $797 million. Through this acquisition, we acquired the 1,021 MW combined-cycle Independence power generation facility located near Scriba, NY, four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. We have not consolidated the natural gas-fired merchant facilities and the hydroelectric generation facilities under the provisions of FIN No. 46R. See Note 1—Accounting Policies—Accounting Principles Adopted—FIN No. 46R for further discussion of the facilities. Independence holds power tolling, financial swap and other contracts with other of our subsidiaries. As a result of the acquisition, these contracts have become intercompany agreements and their financial statement impact has been substantially eliminated. Although it did not change our obligations under the toll, this transaction enabled us to address one of our outstanding power tolling arrangements, and to expand our generation capacity in a market where we have an existing presence.

In the power generation industry, in particular, we believe that consolidation is likely to occur within 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 acquisition or consolidation transactions. In addition, we are evaluating strategic opportunities for our NGL business, and we have launched a process to consider alternatives for this business. The proceeds from any such transaction could be used to position our GEN business favorably for participation in the expected consolidation of the power sector.

However, our desire or ability to pursue any such opportunities is subject to a number of factors beyond our control. As such, we cannot guarantee that any such opportunities will be available to us, nor can we predict with any degree of certainty the impact of any such opportunities on our financial condition or results of operations.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we provide updates related to our liquidity and capital requirements and our internal and external liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures, regulatory and legal settlements and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas, coal and natural gas liquids, facility maintenance costs (including required environmental expenditures) and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, asset sale proceeds and proceeds from capital market transactions to the extent we engage in these activities.

Debt Obligations

During the first quarter 2005, we used cash on hand to reduce our outstanding debt as follows:

•

$18 million repayment of 8.125% senior notes that matured in March 2005; and

•

$1 million quarterly payment for our May 2004 term loan.

Our aggregate maturities for long-term debt, including the current portion and excluding our Central Hudson leveraged lease and our Series C preferred stock, as of March 31, 2005, were approximately $5.3 billion. This includes approximately $919 million in face value project debt associated with our newly acquired Independence facility. Please see Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies and Note 6—Debt—Independence Debt for further discussion of this transaction.

Collateral Postings

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. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. The following table summarizes our consolidated collateral postings to third parties by segment at May 5, 2005, March 31, 2005 and December 31, 2004:


	May 5, 2005		March 31, 2005		December 31, 2004
	(in millions)
By Segment:
GEN	$	221	$	201	$	192
CRM		75		80		94
NGL		168		184		167
REG		—		10		10
Other		6		8		7

Total	$	470	$	483	$	470

By Type:
Cash	$	224	$	380	$	376
Letters of Credit		246		103		94

Total	$	470	$	483	$	470

The segment changes in collateral postings since December 31, 2004, relate to $29 million of additional collateral posted in support of GEN, primarily as a result of increases in commodity prices and the volume of fuel purchased, as well as the reclassification of the Independence tolling arrangement and related collateral obligations from CRM to GEN. This was offset by a $19 million decrease in collateral posted in support of CRM resulting primarily from the reclassification of the Independence tolling arrangement and related collateral obligations from CRM to GEN and the rolloff of NYMEX positions. Finally, the remaining $10 million in collateral postings at our REG segment was eliminated.

We are transitioning counterparty collateral demands from cash collateral to letters of credit in order to replenish our cash balances following (i) the closing of the Sithe Energies acquisition in January 2005, for which we paid $120 million, net of transaction costs and cash acquired, and (ii) our payment of $175 million in May 2005 in connection with the settlement of the shareholder class action litigation, and in anticipation of our payment of an additional $75 million following court approval of the settlement. As of December 31, 2004, approximately 80% of the aggregate collateral posted (or approximately $376 million) consisted of cash, compared to approximately 79% cash collateral (or approximately $380 million) as of March 31, 2005 and 48% cash collateral (or approximately $224 million) as of May 5, 2005.

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. Considering current commodity price estimates, our credit ratings, the timing of contract settlements, the anticipated level of new capacity sales agreements and forward hedging transactions, we believe that collateral requirements will be approximately $400 million at year-end 2005. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for at least the next twelve months. Over the longer term, we expect to achieve incremental reductions associated with the completion of our exit from the CRM business. Additionally, in the event that the strategic opportunity we pursue with respect to our NGL business were to involve its disposition, our collateral obligations would be significantly reduced. Please read Note 13—Subsequent Events for further discussion.

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, 2004, with respect to which information is included in our Form 10-K. As a result of the Sithe Energies acquisition, we have effectively eliminated the financial statement impact of commitments associated with the power tolling agreement and derivative contract held by Independence, which totaled $747 million as of December 31, 2004. Subsequent to the acquisition, these contracts have become intercompany agreements.

However, we have assumed additional contractual obligations as a result of the Sithe Energies acquisition, including (i) two additional gas supply agreements under which we are obligated for $191 million through 2015 (ii) $919 million of face value project debt, which was recorded at its fair value of $797 million, and (iii) an operating lease related to the Sithe Energies New York City office space, which extends through 2011. We expect our future payments of $37 million under this lease to be partially offset by $19 million in future sublease rentals. Please see Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies and Note 6—Debt—Independence Debt for further discussion.

Additionally, as a result of the acquisition, we acquired four hydroelectric generation facilities in Pennsylvania. These facilities are subject to certain off-balance sheet commitments arising under operating leases for equipment and project tracking accounts related to the sale of power.

As of March 31, 2005, the equipment leases have remaining terms from two to sixteen years and involve a maximum aggregate obligation of $137 million over the terms of the leases. Each of the hydroelectric generation facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account, which we refer to as a “Tracking Account,” was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. Two of the four facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of March 31, 2005 was approximately $281 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts will make the continued sale of electricity from the facilities uneconomical.

The obligations of the four facilities described in the preceding paragraph are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of the facilities. The facilities will not be consolidated by Dynegy for GAAP financial reporting purposes under the provisions of FASB Interpretation No. 46R.

There were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2004.

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 2005 and do not foresee a declaration of dividends in the near term, particularly given our financial condition and 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. These 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. If the holders of the Series C preferred stock do not receive the full dividends to which they are entitled on any specified dividend payment date, then such unpaid dividends will be deferred, will cumulate and will accrue additional dividends at the rate of 5.5% per annum. In February 2005, we made our semi-annual dividend payment of $11 million. Please read Note 14—Redeemable Preferred Securities—Series C Convertible Preferred Stock beginning on page F-54 of our Form 10-K for further discussion.

Pursuant to the indenture governing DHI’s second priority senior secured notes, following the August 2005 expiration of the two year grace period provided therein, we are permitted to pay dividends on the Series C preferred stock only if we meet or exceed the fixed charge coverage ratio specified in such indenture. Since August 2003, our fixed charge coverage ratio was below the threshold specified in the indenture, and we do not anticipate that such ratio will meet or exceed such threshold in August 2005 upon the expiration of the grace period. As a result, we will be required to defer payment of dividends on the Series C preferred stock beginning in August 2005 and continuing until such ratio meets or exceeds the specified threshold.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our $700 million revolving credit facility, which is scheduled to mature in May 2007.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at May 5, 2005, March 31, 2005 and December 31, 2004:


	May 5, 2005			March 31, 2005			December 31, 2004
	(in millions)
Total Revolver Capacity	$	700		$	700		$	700
Outstanding Letters of Credit Under Revolving Credit Facility		(246	)		(103	)		(94	)

Unused Revolver Capacity		454			597			606
Cash		388	(1)		371	(1)		628

Total Available Liquidity	$	842	(2)	$	968	(2)	$	1,234

(1)	The May 5, 2005 and March 31, 2005 amounts include approximately $31 million and $30 million, respectively, 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.

(2)	The reduction in available liquidity from March 31, 2005 to May 5, 2005 primarily relates to our $175 million payment associated with the class action litigation settlement.

Cash Flows from Operations. We had operating cash outflows of $34 million in the three months ended March 31, 2005. This consisted of $160 million in operating cash flows from our GEN and NGL segments, reflecting positive earnings for the period. The cash flows from our operating segments were more than offset by $194 million of cash outflows relating to our CRM business and corporate-level expenses. Please read “—Results of Operations—Operating Income (Loss)” and “—Cash Flow Disclosures” for further discussion of factors impacting our operating cash flows for the periods presented.

For 2005, we have projected operating cash flows of $12 to $27 million. This projection, which is subject to change based on a number of factors, many of which are beyond our control, reflects $790 to $800 million in forecasted operating cash flows from our GEN and NGL business segments, offset by projected cash outflows of $31 million from our CRM business segment and $747 to $742 million in corporate-level expenses, including interest.

Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs, including costs for fuel and maintenance. With respect to fuel costs, in January 2004, we entered into a new rail transportation contract that reduced the fees associated with fuel procurement at our coal-fired generation facilities in the Midwest; however, these fee reductions were substantially offset by continued high fuel prices in the Northeast and higher costs associated with the purchase of emission credits. Our ability to achieve fuel-related and other targeted cost savings 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. Please read “—Results of Operations—2005 Outlook—GEN Outlook” for further discussion.

In addition, our CDWR power purchase agreement expired by its terms in December 2004. Please read Item 1.—Business Segment Discussion—Power Generation beginning on page 2 of our Form 10-K for a discussion of West Coast Power’s current contractual arrangements. Our share of West Coast Power’s earnings during 2004 totaled $165 million, excluding impairments of $85 million, approximately 70% of which was derived from the CDWR agreement. Although we received a cash distribution of $52 million in April 2005, as the partnership distributed cash in excess of its operating requirements, we expect future cash distributions from West Coast Power to be significantly less. In California’s current energy market, the West Coast Power generating facilities which previously supported the CDWR contract are significantly less profitable under the RMR contracts or as merchant facilities, and we may consider other alternatives if necessary, including shutting down units if we no longer consider them commercially viable. For instance, we determined that it was not economically feasible to continue operating our Long Beach generation facility beyond the expiration of the CDWR contract so, we retired the asset effective January 1, 2005.

Cash on Hand. At May 5, 2005 and March 31, 2005, we had cash on hand of $388 million and $371 million, respectively, as compared to $628 million at the end of 2004. This decrease in cash on hand as compared to the end of 2004 is primarily attributable to (i) the closing of the Sithe Energies acquisition in January 2005, for which we paid $120 million, net of business acquisition costs and cash acquired and (ii) our payment of $175 million in May 2005 in connection with the settlement of the shareholder class action litigation, partially offset by the return of cash collateral as a result of our transition to letters of credit.

Revolver Capacity. In May 2004, DHI entered into a new $1.3 billion credit facility, consisting of a $600 million term loan and a $700 million revolving credit facility. This $700 million revolving credit facility, which is scheduled to mature in May 2007, is our primary credit facility. We currently have no drawn amounts under this facility, although as of May 5, 2005, we had $246 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 to our liquidity and financial condition, particularly if we are unable to generate operating cash flows relative to our substantial debt obligations and ongoing operating requirements. Please read Note 11—Debt—DHI Term Loan and Credit Facility beginning on page F-43 of our Form 10-K for further discussion of our credit facility.

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. In an effort to maximize our return on investment and to further clarify our business strategy, we have sold assets that we do not consider core to our operations. The aggregate loss of earnings in 2004 associated with these assets (other than Illinois Power) was not material and was more than offset by net gains on sale in 2004. However, beginning in 2005, the lost earnings of approximately $15 million, before consideration of interest savings, on an annual basis from such assets will no longer be offset by gains on sale.

On May 9, 2005, we announced that we are evaluating strategic opportunities for our NGL business. We would evaluate alternative uses for the proceeds from any such transaction, which proceeds would enable us to reduce our outstanding debt or other obligations to further deleverage our capital structure or to position our GEN business favorably in relation to future combination or consolidation opportunities. Please read Note 13—Subsequent Events for further discussion.

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 are continuing to explore additional capital-raising transactions both in the near- and long-term. The timing of any capital-raising transaction may be impacted by unforeseen events, such as strategic growth opportunities, legal judgments or regulatory requirements, which would necessitate additional capital in the near-term.

These transactions may include capital markets transactions. Our ability to issue public securities is enhanced by our effective shelf registration statement, under which we have approximately $430 million in remaining availability. We do not anticipate that this availability will be reduced by the issuance of $68 million in Dynegy Class A common stock pursuant to the settlement of the shareholder class action litigation, as we expect that such issuance will be exempt from registration under the Securities Act of 1933. The receptiveness of the capital markets to a public offering 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. Any issuance of equity would likely have other effects as well, including shareholder dilution. Further, our ability to issue debt securities is limited by our financing agreements, including our credit facility. Please read Note 11—Debt—DHI Term Loan and Credit Facility beginning on page F-43 of our Form 10-K for further discussion.

Conclusion

For the rest of 2005, assuming continuation of the current commodity pricing environment, we expect that our operating cash flows will be positive, but insufficient to satisfy our capital expenditures, debt maturities and interest expenses. However, we believe that our cash on hand and the $100 million deposited into escrow in connection with the sale of Illinois Power, which we expect to receive following court approval of the Baldwin consent decree announced in March 2005, together with capacity under our $700 million revolving credit facility, will be sufficient to discharge these obligations.

Over the longer term and through the anticipated recovery of the U.S. power markets, we expect to maintain sufficient liquidity to satisfy our substantial debt and commercial obligations and provide collateral support through operating cash flows, capacity under our revolving credit facility (or any refinancing thereof), as well as proceeds from anticipated refinancings of debt maturities. Additionally, proceeds from any strategic opportunity involving our NGL business may be used to reduce our outstanding debt or other obligations to further deleverage our capital structure. Our substantial debt and commercial obligations include increased interest expense, the fixed payment obligations associated with our remaining power tolling arrangements in our GEN and CRM businesses (which we expect will continue to reduce our operating cash flows absent early termination or settlement) and counterparty collateral requirements, as well as our significant potential payment obligations relating to our remaining legal and regulatory matters. As expected, our liquidity position has trended downward as we have addressed these obligations, particularly the payments made in connection with the restructuring of the Independence tolling arrangement (through the consummation of the Sithe Energies acquisition) and the settlement of our shareholder class action litigation.

Our ability to generate operating cash flows 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, particularly fuel requirements, and capital expenditures. Our ability to refinance our substantial debt maturities is primarily dependant upon our ability to generate operating cash flows,

which is subject to the factors described in the preceding sentence. 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 our restructuring work has extended our significant debt maturities to 2007 and beyond, positioning us to benefit from earnings and growth opportunities associated with an expected recovery in the U.S. power markets. Additionally, our NGL business is currently operating in a highly 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, prolonged pricing deterioration below price levels experienced over the last few years in our NGL segment.

Our longer term liquidity position and financial condition will also be significantly impacted by the availability of, and our ability to pursue, strategic growth opportunities, which may include organic or “bolt-on” projects, as well as industry consolidation. In addition, we are evaluating strategic opportunities for our NGL business, and we have launched a process to consider alternatives for this business. The proceeds from any such transaction could position our GEN business favorably for participation in the expected consolidation of the power sector. However, as indicated above, our desire or ability to pursue any such opportunities is subject to a number of factors beyond our control. As such, we cannot guarantee that any such opportunities will be available to us, nor can we predict with any degree of certainty the impact of any such opportunities on our financial condition or results of operations.

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 37 of our Form 10-K, 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 2005 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,” and the “frac spread” which represents the relationship between prices for natural gas liquids and natural gas;

•

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 remaining unrestructured power tolling arrangement, excluding the Gregory tolling arrangement which expires in July 2005, the restructuring or termination of which likely would require a significant cash payment;

•

The effects of a potential strategic transaction involving our NGL business;

•

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

•

Our ability to achieve our financial and operational goals associated with the Sithe Energies acquisition.

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 2005. At the end of this section, we have included our 2005 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 and other income (expense) items incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred.

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, 2005 and 2004, respectively:

Quarter Ended March 31, 2005


	GEN		NGL			REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	60	$	59		$	—	$	(192	)	$	(251	)	$	(324	)
Earnings from unconsolidated investments		2		2			—		—			—			4
Other items, net		—		(5	)		—		1			2			(2	)
Interest expense															(100	)

Loss from continuing operations before taxes															(422	)
Income tax benefit															157

Loss from continuing operations															(265	)
Income from discontinued operations, net of taxes															3

Net loss														$	(262	)

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

The following table provides summary segmented operating statistics for the three months ended March 31, 2005 and 2004, respectively:


	Quarter Ended March 31,
	2005		2004
Power Generation
Million megawatt hours generated—gross		8.8		10.6
Million megawatt hours generated—net		8.4		10.1
Average natural gas price—Henry Hub ($/Mmbtu) (1)	$	6.39	$	5.61
Average on-peak market power prices ($/MW hour)
Cinergy	$	49	$	42
Commonwealth Edison	$	49	$	41
Southern	$	49	$	43
New York—Zone G	$	70	$	64
New York—Zone A	$	58	$	56
ERCOT	$	51	$	41
SP-15	$	56	$	48

Natural Gas Liquids
Gross NGL production (MBbls/d):
Field plants		55.5		57.9
Straddle plants		30.8		23.9

Total gross NGL production		86.3		81.8

Natural gas (residue) sales (Bbtu/d)		184.1		217.1

Natural gas inlet volumes (MMCFD):
Field plants		518.1		566.4
Straddle plants		1,340.1		867.4

Total natural gas inlet volumes		1,858.2		1,433.8

Fractionation volumes (MBbls/d)		160.6		185.0
Natural gas liquids sold (MBbls/d)		294.5		301.4
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	47.93	$	34.77
Natural gas—Henry Hub ($/MMbtu) (2)	$	6.27	$	5.69
Natural gas liquids ($/Gal)	$	0.78	$	0.62
Fractionation spread ($/MMBtu)—daily	$	2.33	$	1.39

Regulated Energy Delivery (3)
Electric sales in KWH (millions)
Residential		—		1,455
Commercial		—		1,054
Industrial		—		1,320
Transportation of customer-owned electricity		—		629
Other		—		98

Total electric sales		—		4,556

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

Total gas delivered		—		306

Heating degree days—Actual (4)		—		2,708
Heating degree days—10-year rolling average		—		2,678

(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)	We sold Illinois Power, our regulated utility, to Ameren on September 30, 2004.

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

The following tables summarize significant items on a pre-tax basis, with the exception of the 2004 tax item, affecting net income (loss) for the periods presented.


	Quarter Ended March 31, 2005
	GEN		NGL		REG		CRM			Other			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—	$	—		$	(222	)	$	(222	)
Independence toll settlement charge		—		—		—		(183	)		—			(183	)

Total	$	—	$	—	$	—	$	(183	)	$	(222	)	$	(405	)


	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 sale of IP		—		—		(21	)		—		—			(21	)
Legal and settlement charges		2		—		(2	)		—		(15	)		(15	)
Taxes		—		—		—			—		39			39

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

Operating Income (Loss)

Operating loss was $324 million for the quarter ended March 31, 2005, compared to operating income of $108 million for the quarter ended March 31, 2004.

GEN. Operating income for our GEN segment was $60 million for the three months ended March 31, 2005, compared to $53 million for the three months ended March 31, 2004.

In the Midwest-MAIN region, where we produce approximately 60% of our generated volumes, results increased $8 million year over year, from $100 million for the first quarter 2004 to $108 million for the first quarter 2005. Improved prices in the region were the primary driver of the increase in operating income. Higher prices contributed an additional $13 million for 2005 compared to 2004, as average on-peak prices increased from $41/MWh for the first quarter 2004 to $49/MWh for the first quarter 2005. However, volumes were down nine percent, from 5.5 million MWh for the first quarter 2004 to 5.0 million MWh for the first quarter 2005. This decrease in volumes was primarily due to a scheduled outage at our Baldwin facility.

Results for our peaking facilities in the Midwest-ECAR region were improved by $3 million, from a loss of $4 million for the first quarter 2004 to a loss of $1 million for 2005. This improvement was a result of both favorable pricing and an increase in volumes. Results in our Southeast region improved by $1 million, from a loss of $1 million for the first quarter 2004 to zero for 2005, as a result of increased demand driven by cooler weather. Results in our Texas region improved by $2 million, from a loss of $6 million for the first quarter 2004 to a loss of $4 million for the first quarter 2005. Although natural gas prices have remained high, we were able to partially mitigate the negative impact on earnings by providing additional services to the market.

Improved earnings in the Midwest, Southeast, and Texas regions were offset in the Northeast region, where results decreased from $19 million for the three months ended March 31, 2004 to $15 million for the same period in 2005. Beginning in February 2005, our Northeast region’s results include earnings from the Independence facility.

See Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies for further discussion of the acquisition of Independence. Decreased results in the Northeast were primarily the result of increased operating expense and decreased volumes at our Roseton facility. Volumes at Roseton decreased 0.8 MWh, primarily due to compressed margins resulting from an increase in the price of fuel oil and the cost of emissions allowances in relation to the price of generated power. Total operating expense for the region increased $9 million for the first quarter 2005, compared with the first quarter 2004 as a result of a $4 million increase at our existing facilities, primarily related to maintenance at Roseton, as well as $5 million of operating expense associated with our newly acquired Independence facility. Total volumes for the region inclusive of our Independence facility were down slightly, from 2.3 MWh in the first quarter 2004 to 2.2 MWh for the same period in 2005, as additional volumes resulting from the acquisition of the Independence facility were offset by the decrease at the Roseton facility. Additionally, we realized $4 million less revenue in the first quarter 2005 due to the expiration of a transitional power purchase agreement in October 2004. The decrease in generated volumes and increase in operating expense were partially mitigated as average on-peak prices were up 9% in the market served by our Danskammer and Roseton facilities.

General and administrative expense increased from $14 million for the three months ended March 31, 2004 to $17 million for the same period in 2005. The increase is primarily the result of expense associated with the New York City office we acquired in our Sithe Energies acquisition. Depreciation expense decreased slightly, from $48 million for the first quarter 2004 to $47 million for the first quarter 2005.

GEN’s first quarter 2004 earnings included $2 million from a wind powered power plant located in Costa Rica. We sold this facility in the second quarter 2004, as part of our effort to focus on our core businesses.

GEN’s reported operating income for the three-month periods ended March 31, 2005 and 2004 also includes approximately $8 million and $4 million, respectively, of mark-to-market income related to purchases and sales that did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market basis.

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 our NGL segment was $59 million for the first quarter 2005, compared to $67 million in the first quarter 2004. Operating income for the first quarter 2004 included a $17 million gain on the sale of our remaining financial interest in the Hackberry LNG project.

Excluding the Hackberry gain, the significant improvement in operating income was driven by natural gas and natural gas liquids prices, which increased dramatically quarter over quarter, as well as a 6% increase in the volume of natural gas liquids produced. Additionally, the frac spread was sufficiently high to make natural gas liquids recovery profitable under all contract settlements for the first quarter 2005, while the frac spread was unprofitable for the first quarter 2004. The current quarter was marked by exceptionally high run time experienced across our facilities.

Gathering and processing operating results increased by $11 million for the quarter ended March 31, 2005 compared to the quarter ended March 31, 2004, primarily benefiting from 10% higher absolute commodity prices for natural gas and 26% higher absolute commodity prices for natural gas liquids year over year. At our field plants, results increased $6.4 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from higher prices. Offsetting these increases, operating results for the quarter ended March 31, 2004 included $5.2 million in operating margin from our non-operating joint interest in the Indian Basin plant and from our Sherman plant which were sold in April 2004 and in November 2004, respectively. At our straddle plants, operating results increased $4.2 million, due largely to the impact of higher natural gas liquids prices under our POL contract settlements. Also during the quarter ended March 31, 2005, higher frac spreads made it profitable to recover liquids under KW agreements and caused hybrid contracts to switch from fee to POL settlements. The Stingray facility, our only plant that settles under a KW contract structure, operated during the first quarter 2005 while it was idled during the same quarter in 2004. Offsetting these increases, we continue to have reduced producers’ volumes through our straddle plants caused by the impact of last summer’s Hurricane Ivan on natural gas producers.

Results of our fractionation, storage and terminalling and transportation and logistics businesses decreased $1 million for the first quarter 2005 compared to the first quarter 2004. Overall fractionation volumes decreased period over period due to the loss of a fractionation customer at the end of September 2004 at our Cedar Bayou fractionator, partially offset by increased fractionation volumes at our Lake Charles fractionator caused by industry-wide increased liquids production primarily resulting from higher frac spreads. The results for our natural gas liquids storage and transportation business increased period over period, partially offsetting fractionation impacts.

Wholesale marketing results decreased by $2 million for the first quarter 2005 compared to the first quarter ended 2004, primarily as a result of milder than usual weather and the loss of a refinery services contract. This was partially offset by higher natural gas liquids prices on our net back refinery services contracts and a $2 million contract termination payment received in March 2005 in connection with our agreement to terminate an additional refinery services contract.

Results for our distribution and marketing services business increased approximately $2 million for the first quarter 2005 compared to the first quarter 2004. Increasing natural gas liquids prices during the quarter ended March 31, 2005 contributed to higher marketing margins.

REG. Operating income for the REG segment was zero for the quarter ended March 31, 2005, compared to $54 million for the quarter ended March 31, 2004. We sold Illinois Power to Ameren on September 30, 2004. The 2004 period includes a $21 million charge related to the sale of Illinois Power.

CRM. Operating loss for the CRM segment was $192 million for the quarter ended March 31, 2005, compared to a loss of $13 million in 2004.

Results for 2005 were negatively impacted by a $183 million charge associated with the Sithe Energies acquisition. Prior to the acquisition, Independence held a power tolling contract and a gas supply agreement with our CRM segment. Upon completion of the purchase, these contracts became intercompany agreements under our GEN segment, and were effectively eliminated on a consolidated basis, resulting in the $183 million charge upon completion of the acquisition.

Additionally, this segment’s results for 2004 and 2005 reflect the impact of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold.

Other. Other operating loss was $251 million for the quarter ended March 31, 2005, compared to $53 million for the quarter ended March 31, 2004. Results for 2005 include a $222 million charge associated with the recent settlement of our shareholder class action litigation. For more information, please read Note 9—Commitment and Contingencies—Shareholder Litigation. 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.

Earnings from Unconsolidated Investments.

Our earnings from unconsolidated investments were approximately $4 million for the quarter ended March 31, 2005, compared to $40 million for the quarter ended March 31, 2004. Our West Coast Power investment was the primary driver of the decrease. Total earnings from this investment were approximately $1 million for the three months ended March 31, 2005, compared to $35 million for 2004. The decrease in earnings is primarily the result of the expiration of West Coast Power’s CDWR contract. Please read Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Form 10-K for a discussion of West Coast Power’s current contractual arrangements. First quarter 2004 earnings also included an aggregate net $1 million from our Oyster Creek, Michigan Power, Joppa, Hartwell, Commonwealth and Jamaica investments, all of which were sold during 2004.

Interest Expense

Interest expense totaled $100 million for the quarter ended March 31, 2005, compared to $132 million for the quarter ended March 31, 2004. The significant decrease in 2005 is primarily attributable to the sale of Illinois Power in September 2004.

Other Items, Net

Other items, net consists of other income and expense items, net, and minority interest income (expense). Other items, net totaled $2 million of expense for the quarter ended March 31, 2005, compared to $11 million of income for the quarter ended March 31, 2004. The decrease is primarily a result of mark-to-market income recognized in the first quarter 2004 associated with interest rate swaps. In addition, minority interest expense increased from $2 million to $6 million.

Income Tax Benefit

We reported an income tax benefit during the quarter ended March 31, 2005 of $157 million compared to $29 million for the quarter ended March 31, 2004. The income tax benefit in 2004 is the difference between $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 2005. 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 U.K. CRM business in our CRM segment and our communications business in Other and Eliminations. In the first quarter 2005, we recognized $4 million of pre-tax income associated with U.K. CRM’s receipt of a third party bankruptcy settlement. 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.

2005 Outlook

The following summarizes our outlook for the remainder of 2005 for our three reportable segments.

GEN Outlook. We expect that this segment’s future financial results will continue to reflect sensitivity to commodity prices, including the cost of emission allowances, 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, including through forward sales and related transactions, consistent with our views on market recovery in the regions we serve. Our sensitivity to commodity 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. Additionally, because we may seek to manage price risk through forward sales and related transactions, at times we may be unable to capture opportunities presented by rising prices.

The operation of our generation facilities is highly dependent on our ability to procure coal as a fuel. Power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. Our long-term supply and transportation agreements for our Midwest fleet

mitigate these concerns. In the Northeast, we have accumulated sufficient inventories to allow us to operate our assets. While we believe our physical inventories and contractual commitments provide us with a stable fuel supply, we are subject to physical delivery risks outside of our control.

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. During 2004 and 2005, we have seen increases in the market for capacity-related products from our peaking and intermediate generation facilities.

Throughout 2004, a substantial portion of our operating margin and earnings from unconsolidated investments was under contract or hedged. The primary contracts included the CDWR contract held by West Coast Power and the Illinois Power power purchase agreement, both of which terminated in December 2004. Our future results of operations will be significantly impacted by the expiration of the CDWR contract. West Coast Power, whose equity earnings were primarily derived from the CDWR contract, has been our largest contributor to earnings from unconsolidated investments. As a result of the expiration of the CDWR contract, future earnings from the investment will be substantially reduced. Please read Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Form 10-K for a discussion of West Coast Power’s current contractual arrangements. Based on our ongoing evaluation of strategic alternatives for our West Coast Power assets, we determined that it was not economically feasible to continue to operate our Long Beach generation facility beyond the expiration of the CDWR contract. Therefore, we retired the asset as of January 1, 2005. Please read “—Liquidity and Capital Resources—Internal Liquidity Sources—Cash Flows from Operations” for a discussion of our efforts to replace the CDWR contract.

Our former power purchase agreement between DMG and Illinois Power terminated in December 2004. In September 2004, in connection with the sale of Illinois Power to Ameren, DPM entered into a new two-year power purchase agreement with Illinois Power with expected volumes comparable to the former agreement. Under the terms of this new agreement, which became effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48.00 per kW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. Under the new agreement, we are no longer the provider of last resort for Illinois Power, which exposed us to volume and price uncertainties under the former agreement. Under the former agreement, we received contract revenues based on a higher fixed capacity payment and lower variable energy payments. Accordingly, GEN’s operating income under the new agreement will be impacted more significantly by deviations from expected energy purchases by Illinois Power. We expect that any reduction in operating income under this new agreement will be mitigated by no longer serving as the provider of last resort.

During 2004, we sold our 50% interests in the Oyster Creek, Michigan Power, Hartwell, and Commonwealth facilities, as well as our 20% interest in the Joppa facility. Additionally, we sold our 100% interest in Plantas Eolicas, S.A. de C.V. (Costa Rica) and 17.55% interest in Jamaica Energy Partners. Our 2004 results include an aggregate $99 million of earnings from these investments, including $82 million of net gains on sales. However, beginning in 2005, the lost earnings from these assets will no longer be offset by gains on sale.

On January 31, 2005, in connection with the Sithe Energies acquisition, we acquired the 1,021 MW, combined-cycle Independence power generation facility, four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. GEN’s 2005 results will include the results of this acquisition, including general and administrative costs associated with Sithe Energies’ New York City office, until such time as those costs can be mitigated. Please read Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies for further discussion of this transaction.

NGL Outlook. The financial outlook for our NGL segment is sensitive to natural gas and natural gas liquids prices. The pricing environment for 2005 is expected to be strong with high volatility for commodities driving our market, similar to 2004, when we experienced high volatility in both natural gas and natural gas liquids prices. Provided the strong pricing environment persists throughout 2005, our upstream contract settlements under POP and POL contracts will continue to benefit. However, increased natural gas prices without a comparable increase in natural gas liquids prices would reduce frac spreads to levels where it is no longer profitable to extract natural gas

liquids. If frac spreads are reduced to unprofitable levels, our hybrid contracts, sensitive to frac spreads, will switch from POL settlements to fee settlements, which would negatively impact our earnings in such a high natural gas liquids price environment. Frac spread volatility will impact natural gas liquids volumes produced from our and third party natural gas processing plants depending upon whether frac spread economics at a given time support natural gas liquids extraction. In 2005, the U.S. and world economies are expected to grow, though not as rapidly as 2004. We expect this growth to continue supporting demand for products from the petrochemical industry, which experienced a dramatic improvement in 2004. The industry’s improvement was due in part to strong global ethylene and propylene demand, driving higher natural gas liquids feedstock consumption, and helping to improve frac spreads. We expect this increased demand for natural gas liquids feedstocks to continue benefiting our results.

There is currently a belief among many in the industry that, long-term, natural gas prices will remain high enough relative to natural gas liquids prices to depress the frac spread below levels required for liquids extraction, reducing natural gas liquid volumes requiring fractionation. As a result, there remains aggressive competition between fractionators for available volumes, driving fees paid for fractionation services to historic lows. In October 2004, we lost a substantial fractionation customer at our Mont Belvieu fractionator when the previous contract reached the end of its primary term. The customer had committed the volumes to a competitor as part of a larger asset sale. We continue to compete aggressively for replacement volumes, albeit in a highly competitive market.

Straddle plant gas processing will continue to be impacted by uncertainty surrounding natural gas quality specifications for liquefiable hydrocarbons. Other than occasional short-term periods of favorable natural gas liquids extraction economics, market conditions for straddle plant gas processing have been generally poor since late 2000. Pipeline companies have operational and safety concerns related to the heavier natural gas liquids, like butane and natural gasoline, that are left in the natural gas entering their systems instead of being extracted. While industry stakeholders respond to recent FERC decisions indicating that gas quality standards are practices of the pipelines and operational conditions and must be included in the pipelines’ tariffs, there remains a lack of clarity around when and where processing is required, especially during periods of poor extraction economics. The result is a patchwork of pipeline policies and practices that leave producers and processors without clearly defined gas quality standards, increasing the difficulty associated with contracting for gas supply and planning straddle plant operations. Resolution of the issue is currently being pursued through the Natural Gas Council, FERC and with other affected stakeholders.

Drilling for natural gas throughout our core processing areas in New Mexico, West Texas, North Texas and offshore Louisiana continues to increase, consistent with natural gas prices that have averaged $6/MMBtu. Continued exploration and production at these commodity price levels will benefit our upstream business by providing additional volumes for gathering and processing. In the Permian, continued property sales by major exploration and production companies to smaller independent producers will contribute to increased activity and exploration. If natural gas prices were to decline significantly in the future, resulting in reduced drilling activities, this segment’s results could be materially 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 satisfy efficiently a potential new customer’s concerns about our credit ratings. We expect similar collateral requirements until such time as our credit ratings measurably improve.

At this time it is our strategy to not sell forward future natural gas liquids production; however, any change in this strategy resulting in a desire to hedge future natural gas liquids production during 2005 may again be limited by reduced market liquidity and our obligation to post collateral. As commodity prices rise, we are required by counterparties to post additional collateral.

We intend to continue prudently expanding our North Texas gathering system, working collaboratively with our producer customers. Additional compression and pipeline reach along with plant debottlenecking are expected to add volumes to our expanded Chico gas processing plant. In addition, we continue to review our asset portfolio to maximize return on investment. We may pursue sale 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.

Additionally, on May 9, 2005, we announced that we are evaluating strategic opportunities for our NGL business. We have launched a process to consider alternatives for this business. There is no assurance that we will enter into a transaction, but in the event that such a transaction is consummated, our consolidated financial position, results of operations and cash flows would be significantly impacted. Please read Note 13—Subsequent Events for further discussion. The discussion of NGL’s outlook above assumes that no such transaction will occur.

CRM Outlook. Our CRM business’ future results of operations will be significantly impacted by our ability to complete our exit from this business. During 2004, we were successful in reaching agreements to exit four of our natural gas transportation agreements. In November 2004, we entered into a “back-to-back” power purchase agreement with a subsidiary of Constellation, under which we will receive $161 million in payments through November 2008 to offset our fixed payment obligations under our Kendall tolling arrangement, while positioning us to take advantage of the market recovery expected in 2008 and beyond. In January 2005, we completed the purchase from Exelon Corporation of all of the outstanding capital stock of ExRes SHC, Inc., the parent company of Sithe Energies and Independence. Please read Note 2—Acquisitions, Dispositions and Discontinued Operations—Acquisitions—Sithe Energies for further discussion. As a result of this agreement, our Independence power tolling arrangement has been transformed into an intercompany agreement under our GEN segment, which now includes the Independence facility. This substantially eliminates its future financial statement impact. Our Gregory tolling arrangement expires by its terms in July 2005.

Our Sterlington tolling arrangement remains in place through 2017. We are exploring opportunities to assign or renegotiate the terms of this arrangement, but we cannot guarantee that we will be successful. If we do not renegotiate or terminate this remaining arrangement, it will continue to impact negatively our near- and long-term earnings and cash flows based on the current pricing environment. Any renegotiation or termination of this long-term contract would likely result in significant cash payments and a charge to earnings in the applicable period. For a discussion of our annual and long-term obligations under these arrangements, please read “Disclosure of Contractual Obligations and Contingent Financial Commitments” beginning on page 43 of our Form 10-K and Item 1. Business—Segment Discussion—Customer Risk Management beginning on page 18 of our Form 10-K.

Cash Flow Disclosures

The following tables include data from the operating section of our unaudited 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 our unaudited condensed consolidated statements of operations:


	GEN		NGL		REG		CRM			Other & Eliminations			Consolidated
	(in millions)
For the Quarter Ended March 31, 2005	$	91	$	69	$	—	$	(26	)	$	(168	)	$	(34	)

For the Quarter Ended March 31, 2004	$	162	$	121	$	140	$	(85	)	$	(171	)	$	167

Operating Cash Flow. Our cash flow used in operations totaled $34 million for the quarter ended March 31, 2005. During the quarter, our GEN and NGL segments provided positive cash flow from operations. GEN provided cash flow from operations of $91 million due to positive earnings for the period; and NGL provided cash flow from operations of $69 million primarily due to positive earnings for the period. Our CRM segment used approximately $26 million in cash primarily due to fixed payments associated with the power tolling arrangements and our final payment related to our exit from gas transportation contracts. Other and eliminations includes a use of approximately $168 million in cash primarily due to interest payments to service debt and general and administrative expenses.

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.

Capital Expenditures and Investing Activities. Cash used in investing activities during the quarter ended March 31, 2005 totaled $179 million. Capital spending of $54 million was primarily comprised of $40 million and $10 million in the GEN and NGL segments, respectively. The capital spending for the GEN segment primarily related to maintenance capital projects, as well as $10 million in development capital associated with the completion of the Havana PRB conversion. Capital spending in our NGL segment primarily related to maintenance capital projects and wellconnects. The cost to acquire Sithe Energies, net of cash proceeds, totaled $120 million. Proceeds from asset sales consisted of a $5 million payment to Ameren associated with the working capital adjustment related to the sale of Illinois Power.

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.

Financing Activities. Cash used in financing activities during the quarter ended March 31, 2005 totaled $44 million. Repayments of long-term debt totaled $19 million for the three months ended March 31, 2005 and consisted of the following: (1) payments of $18 million on a maturing series of DHI senior notes; and (2) payments of $1 million on DHI’s term loan. Cash used in financing activities also includes a semi-annual dividend payment of $11 million on our Series C preferred stock.

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 Chevron junior notes. Cash used in financing activities also includes a semi-annual dividend payment of $11 million on our Series C preferred stock.

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, 2005
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2005	$	(133	)
Risk-management gains recognized through the income statement in the period, net		1
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)		23

Fair value of portfolio at March 31, 2005	$	(83	)

Income Statement Reconciliation
Risk-management gains recognized through the income statement in the period, net	$	1
Physical business recognized through the income statement in the period, net (3)		(181	)
Non-cash adjustments and other		3

Net recognized operating loss	$	(177	)

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)		(181	)
Timing and other, net (4)		19

Cash paid during the period	$	(188	)

Risk-Management cash flow adjustment for the quarter ended March 31, 2005 (5)	$	(11	)

(1)	Our modeling methodology has been consistently applied.

(2)	This amount consists of changes in value associated with cash flow hedges on forward power sales and fair value hedges on debt, which were more than offset by the $62 million risk-management asset acquired in connection with the Sithe Energies transaction.

(3)	This amount includes capacity payments on our power tolling arrangements and the $183 million pre-tax charge for the Independence toll settlement.

(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 $83 million is the aggregate of the following line items on our 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, 2005 and December 31, 2004. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below:

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


	Total			2005(3)			2006			2007			2008			2009			Thereafter
	(in millions)
March 31, 2005 (2)	$	(21	)	$	12		$	15		$	(35	)	$	(12	)	$	(4	)	$	3
December 31, 2004		(96	)		(7	)		(8	)		(48	)		(21	)		(10	)		(2	)

Increase (4)	$	75		$	19		$	23		$	13		$	9		$	6		$	5

(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, 2005 of $83 million on the unaudited condensed consolidated balance sheets include the $21 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)

Our mark-to-market values at March 31, 2005 were derived solely from market quotations instead of the combination of long-term valuation models and market quotations used at December 31, 2004. Following our Sithe Energies acquisition and the resulting restructuring of the Independence toll, we no longer use long-term valuation models, as our risk-management portfolio can be fully valued based on market quotations.

(3)	Amounts represent April 1 to December 31, 2005 values in the March 31, 2005 row and January 1 to December 31, 2005 values in the December 31, 2004 row.

(4)	The increase relates primarily to our Sithe Energies acquisition and resulting restructuring of the Independence toll.

Cash Flow Components of Net Risk-Management Asset


	Three Months Ended March 31, 2005		Nine Months Ended December 31, 2005		Total 2005			2006			2007			2008			2009			Thereafter
	(in millions)
March 31, 2005 (1)	$	7	$	13	$	20		$	19		$	(36	)	$	(14	)	$	(5	)	$	4
December 31, 2004						(5	)		(7	)		(51	)		(23	)		(12	)		(1	)

Increase (2)					$	25		$	26		$	15		$	9		$	7		$	5

(1)

The cash flow values for 2005 reflect realized cash flows for the three months ended March 31, 2005 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.

(2)	The increase relates primarily to our Sithe Energies acquisition and resulting restructuring of the Independence toll.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q 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, including anticipated cash flows from operations;

•

expectations regarding capital expenditures, interest expense and other payments;

•

our ability to continue execution of 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;

•

our ability to access the capital markets as and when needed;

•

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 the approvals of the Baldwin consent decree and the settlement agreements relating to the shareholder class action and shareholder derivative litigation, as well as matters involving the western power and natural gas markets, master netting agreement matters, and the investigations primarily relating to Project Alpha and our past trading practices;

•

the effects of a potential strategic transaction involving our NGL business;

•

the effects of the Sithe Energies acquisition; 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,” and the “frac spread,” which represents the relationship between the prices for natural gas and natural gas liquids;

•

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

•

the availability of strategic opportunities for our NGL business and our ability to pursue any such opportunities;

•

our ability to achieve our financial and operational goals associated with the Sithe Energies acquisition;

•

our ability to fund the environmental and emission control projects mandated by the Baldwin consent decree following its approval by the Illinois federal district court, and the impact of those payments on our financial condition;

•

our ability to make the remaining settlement payments required by the settlement agreement relating to the shareholder class action litigation, including the issuance of $68 million in (or approximately 17.5 million shares of) our Class A common stock, and the impact of those payments on our financial condition;

•

the costs and effects of other 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 our CRM business and environmental liabilities that may not be covered by indemnity or insurance, as well as the U.S. Attorney and other similar investigations primarily surrounding Project Alpha and our past trading practices;

•

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 and debt service obligations;

•

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 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 restrictive covenants resulting from our non-investment grade credit rating;

•

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 effects of our efforts to improve our internal control structure, particularly with respect to the remediation of the deficiencies discussed under Item 9A—Controls and Procedures beginning on page 85 of our Form 10-K;

•

other North American regulatory or legislative developments that affect the demand and pricing for energy generally, that increase 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. 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 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, 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 74 of our Form 10-K 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 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 83 of our Form 10-K for a discussion of our exposure to commodity price variability and other markets risks, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of March 31, 2005.

Value at Risk (“VaR”). The following table sets forth the aggregate daily VaR of the mark-to-market portion of Dynegy’s risk-management portfolio primarily associated with the GEN and CRM segments.

Daily and Average VaR for Risk-Management Portfolio

(1)

VaR at March 31, 2005 is significantly lower than that reported for December 31, 2004 due to the acquisition and consolidation of ExRes and certain of its subsidiaries effective January 31, 2005, which essentially eliminated the risk of the Independence financial derivative instrument in our consolidated financial results.

Credit Risk. The following table represents our credit exposure at March 31, 2005 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary


	Investment Grade Quality		Non-Investment Grade Quality		Total
	(in millions)
Type of Business:
Financial Institutions	$	121	$	—	$	121
Commercial/Industrial/End Users		73		34		107
Utility and Power Generators		29		—		29
Oil and Gas Producers		5		—		5

Total	$	228	$	34	$	262

All of the $34 million in credit exposure to non-investment grade counterparties is collateralized or subject to other credit exposure protection.

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of March 31, 2005, our fixed rate debt instruments as a percentage of total debt instruments was approximately 72%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of March 31, 2005, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended March 31, 2006 would either decrease or increase income before taxes by approximately $15 million. Hedging instruments that impact such interest rate exposure are included in the sensitivity analysis. Over time, we may seek to reduce the percentage of fixed rate financial obligations in our debt portfolio through the use of swaps or other financial instruments.

Derivative Contracts. The notional financial contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts were as follows at March 31, 2005 and December 31, 2004, respectively:

Notional Contract Amounts


	March 31, 2005		December 31, 2004
Natural Gas (Trillion Cubic Feet)		0.886		1.084
Electricity (Million Megawatt Hours)		17.756		11.652
Net Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	525	$	525
Fixed Interest Rate Received on Swaps (Percent)		4.331		4.331
Net Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	25	$	25
Fixed Interest Rate Paid (Percent)		5.998		5.998

Item 4—CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Effective as of the end of the first quarter 2005, 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 the various processes carried out under the direction of our disclosure 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. This evaluation also considered the work completed as of the end of the first quarter 2005 relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002.

Based on this evaluation, our CEO and CFO concluded that, as of March 31, 2005, as a result of the material weakness identified as of December 31, 2004 and discussed below, our disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods. As we will be unable to confirm whether we have remediated this material weakness until preparation of our 2005 annual tax provision, we anticipate that such material weakness will continue to exist through the end of 2005. Due to the material weakness discussed above, in preparing our financial statements at and for the three-month period ended March 31, 2005, we performed additional procedures relating to the tax provision designed to ensure that such financial statements were fairly presented in all material respects in accordance with generally accepted accounting principles.

Remediation of Material Weakness. As discussed in Item 9A. Controls and Procedures–Management’s Report on Internal Control over Financial Reporting beginning on page 86 of our Form 10-K, as of December 31, 2004, there was a material weakness in our internal control over financial reporting related to our tax accounting and tax reconciliation processes, procedures and controls. In 2004, and through the date of this filing, we have taken the following steps to improve our internal controls around our tax accounting and tax reconciliation processes, procedures and controls:

•

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

•

Formalized processes, procedures and documentation standards relating to income tax provisions; and

•

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

We believe we have taken steps necessary to remediate this material weakness relating to our tax accounting and tax reconciliation processes, procedures and controls, however, certain of the corrective processes, procedures and controls relate to annual controls that cannot be tested until the preparation of our 2005 annual tax provision. Accordingly, we will continue to monitor vigorously the effectiveness of these processes, procedures and controls and will make any further changes management determines appropriate.

Changes in Internal Controls. Other than as noted above in this Item 4, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) identified in connection with the evaluation of our internal controls performed during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

DYNEGY INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

See Note 9 to the accompanying unaudited condensed consolidated financial statements for discussion of the material legal proceedings to which we are a party.

Item 2—UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Pursuant to the terms of the settlement agreement relating to the shareholder class action litigation, which was filed with the court on May 9, 2005, Dynegy agreed to issue, following final court approval of the settlement, $68 million in Dynegy’s Class A common stock, or approximately 17.5 million shares based on a calculation using a volume weighted average stock price for the 20 trading days ending April 15, 2005. Dynegy will issue these shares as partial consideration for the settlement of the shareholder class action litigation, and will not receive any cash proceeds in connection therewith. Dynegy intends to issue these shares in reliance on the exemption from registration pursuant to Section 3(a)(10) of the Securities Act of 1933, as amended. Please read Note 9—Commitments and Contingencies—Shareholder Litigation to the accompanying unaudited condensed consolidated financial statements for further discussion of this settlement agreement.

Item 6—EXHIBITS

The following documents are included as exhibits to this Form 10-Q:


4.1		Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.22 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc., File No. 1-15659).

4.2		First Supplemental Indenture dated as of January 1, 1993 to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.23 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc., File No. 1-15659).

4.3		Second Supplemental Indenture dated as of October 23, 2001 to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.24 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc., File No. 1-15659).

+4.4		Global Note representing the 8.50% Secured Bonds due 2007 of Sithe/Independence Power Partners, L.P.

+4.5		Global Note representing the 9.00% Secured Bonds due 2013 of Sithe/Independence Power Partners, L.P.

10.1		Amendment to Stock Purchase Agreement (Special Payroll Payment) dated as of January 28, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc., File No. 1-15659).

10.2		Amendment to Stock Purchase Agreement dated as of January 31, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc., File No. 1-15659).

10.3		Amendment to Stock Purchase Agreement (Luz Sale) dated as of January 31, 2005 among Dynegy New York Holdings Inc., Exelon SHC, Inc., Exelon New England Power Marketing, L.P. and ExRes SHC, Inc. (incorporated by reference to Exhibit 10.51 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc., File No. 1-15659).

10.4		Tenth Amendment to Amended and Restated Base Gas Sales Agreement, dated as of June 29, 2001, by and between Enron North America Corp. and Sithe/Independence Power Partners, L.P. (incorporated by reference to Exhibit 10.52 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc., File No. 1-15659).

+10.5		Form of Restricted Stock Award Agreement (2004 Performance Year).


+10.6		Form of Non-Qualified Stock Option Award Agreement (2004 Performance Year).

+10.7		Stipulation of Settlement dated May 2, 2005 (Shareholder Class Action Litigation).

+10.8		Stipulation of Settlement dated April 29, 2005 (Shareholder Derivative Litigation).

+ 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.

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.

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: May 10, 2005	By:	/S/ NICK J. CARUSO
		Nick J. Caruso Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)