Edgar Filing: DYNEGY INC /IL/

June 30,
2005

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

Form 10-Q

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 June 30, 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, 285,039,770 shares outstanding as of August 4, 2005; Class B common stock, no par value per share, 96,891,014 shares outstanding as of August 4, 2005.

DYNEGY INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

	Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS:

	Condensed Consolidated Balance Sheets: June 30, 2005 and December 31, 2004	5
	Condensed Consolidated Statements of Operations: For the three and six months ended June 30, 2005 and 2004	6
	Condensed Consolidated Statements of Cash Flows: For the six months ended June 30, 2005 and 2004	7
	Condensed Consolidated Statements of Comprehensive Income (Loss): For the three and six months ended June 30, 2005 and 2004	8
	Notes to Condensed Consolidated Financial Statements	9

	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	45
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	77
	Item 4. CONTROLS AND PROCEDURES	79

PART II. OTHER INFORMATION

	Item 1. LEGAL PROCEEDINGS	80
	Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	80
	Item 6. EXHIBITS	82

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.


ARB		Accounting Research Bulletin
ARO		Asset retirement obligation
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
DMSLP		Dynegy Midstream Services, Limited Partnership
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
GCF		Gulf Coast Fractionators
GEN		Our power generation business segment
ICC		Illinois Commerce Commission
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 System 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
NNG		Northern Natural Gas Company
NOL		Net operating loss
NOV		Notice of Violation issued by the EPA
NYISO		New York Independent System Operator
NYSDEC		New York State Department of Environmental Conservation


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
SPDES		State Pollutant Discharge Elimination System
SPE		Special Purpose Entity
SPN		Second Priority Notes
VaR		Value at Risk
VEBA		Voluntary Employees’ Benefit Association
VIE		Variable Interest Entity

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)


	June 30, 2005			December 31, 2004
ASSETS
Current Assets
Cash and cash equivalents	$	342		$	628
Restricted cash		38			—
Accounts receivable, net of allowance for doubtful accounts of $158 and $159, respectively		595			810
Accounts receivable, affiliates		11			14
Inventory		197			233
Assets from risk-management activities		640			565
Deferred income taxes		496			74
Prepayments and other current assets		298			428
Assets held for sale (Note 3)		369			—

Total Current Assets		2,986			2,752

Property, Plant and Equipment		6,459			7,822
Accumulated depreciation		(1,082	)		(1,692	)

Property, Plant and Equipment, Net		5,377			6,130
Other Assets
Unconsolidated investments		290			421
Restricted investments		84			—
Intangible assets		416			—
Assets from risk-management activities		272			313
Goodwill		—			15
Deferred income taxes		13			12
Other long-term assets		172			209
Assets held for sale (Note 3)		1,159			—

Total Assets	$	10,769		$	9,852

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	503		$	561
Accounts payable, affiliates		17			23
Accrued interest		146			118
Accrued liabilities and other current liabilities		384			450
Liabilities from risk-management activities		684			616
Notes payable and current portion of long-term debt		55			34
Liabilities held for sale (Note 3)		139			—

Total Current Liabilities		1,928			1,802

Long-term debt		4,864			4,132
Long-term debt to affiliates		200			200

Long-Term Debt		5,064			4,332
Other Liabilities
Liabilities from risk-management activities		313			395
Deferred income taxes		885			597
Other long-term liabilities		416			353
Liabilities held for sale (Note 3)		25			—

Total Liabilities		8,631			7,479

Minority Interest		107			106
Commitments and Contingencies (Note 10)
Redeemable Preferred Securities, redemption value of $400 at June 30, 2005 and December 31, 2004, respectively		400			400
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at June 30, 2005 and December 31, 2004; 286,670,174 and 285,012,203 shares issued and outstanding at June 30, 2005 and December 31, 2004, respectively		2,864			2,859
Class B Common Stock, no par value, 360,000,000 shares authorized at June 30, 2005 and December 31, 2004; 96,891,014 shares issued and outstanding at June 30, 2005 and December 31, 2004		1,006			1,006
Additional paid-in capital		45			41
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive loss, net of tax		(23	)		(13	)
Accumulated deficit		(2,185	)		(1,950	)
Treasury stock, at cost, 1,686,715 shares at June 30, 2005 and 1,679,183 shares at December 31, 2004		(68	)		(68	)

Total Stockholders’ Equity		1,631			1,867

Total Liabilities and Stockholders’ Equity	$	10,769		$	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 June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Revenues	$	459		$	689		$	921		$	1,456
Cost of sales, exclusive of depreciation shown separately below		(380	)		(423	)		(910	)		(989	)
Depreciation and amortization expense		(54	)		(57	)		(109	)		(125	)
Impairment and other charges		(7	)		(59	)		(6	)		(75	)
Loss on sale of assets, net		—			—			—			(15	)
General and administrative expenses		(82	)		(94	)		(345	)		(156	)

Operating income (loss)		(64	)		56			(449	)		96
Earnings from unconsolidated investments		4			50			7			88
Interest expense		(96	)		(141	)		(185	)		(271	)
Other income and expense, net		6			(6	)		9			7
Minority interest expense		—			(3	)		—			(1	)

Loss from continuing operations before income taxes		(150	)		(44	)		(618	)		(81	)
Income tax benefit (Note 13)		41			29			215			82

Income (loss) from continuing operations (Note 9)		(109	)		(15	)		(403	)		1
Income from discontinued operations, net of tax benefit (expense) of $111, $(48), $93 and $(78), respectively (Notes 3 and 13)		147			23			179			77

Net income (loss)		38			8			(224	)		78
Less: preferred stock dividends		6			6			11			11

Net income (loss) applicable to common stockholders	$	32		$	2		$	(235	)	$	67

Earnings (Loss) Per Share (Note 9):
Basic earnings (loss) per share:
Loss from continuing operations	$	(0.30	)	$	(0.06	)	$	(1.09	)	$	(0.03	)
Income from discontinued operations		0.38			0.07			0.47			0.20

Basic earnings (loss) per share	$	0.08		$	0.01		$	(0.62	)	$	0.17

Diluted earnings (loss) per share:
Loss from continuing operations	$	(0.30	)	$	(0.06	)	$	(1.09	)	$	(0.03	)
Income from discontinued operations		0.38			0.07			0.47			0.20

Diluted earnings (loss) per share	$	0.08		$	0.01		$	(0.62	)	$	0.17

Basic shares outstanding		380			378			379			377
Diluted shares outstanding		506			435			505			503

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)


	Six Months Ended June 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(224	)	$	78
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		151			196
Impairment and other charges		(1	)		80
Earnings from unconsolidated investments, net of cash distributions		47			(19	)
Risk-management activities		(1	)		(44	)
Gain on sale of assets, net		—			(38	)
Deferred income taxes		(306	)		(4	)
Liability associated with gas transportation contracts (Note 3)		—			(148	)
Legal and settlement charges		86			39
Independence toll settlement charge		170			—
Other		2			(34	)
Changes in working capital:
Accounts receivable		(24	)		84
Inventory		(9	)		12
Prepayments and other assets		180			(100	)
Accounts payable and accrued liabilities		(107	)		(49	)
Changes in non-current assets		(4	)		(24	)
Changes in non-current liabilities		31			32

Net cash provided by (used in) operating activities		(9	)		61

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(93	)		(151	)
Proceeds from asset sales, net		(5	)		81
Business acquisitions, net of cash acquired		(120	)		—

Net cash used in investing activities		(218	)		(70	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		—			581
Repayments of long-term borrowings		(38	)		(193	)
Proceeds from issuance of capital stock		2			5
Dividends and other distributions, net		(11	)		(11	)
Other financing, net		4			(12	)

Net cash provided by (used in) financing activities		(43	)		370

Effect of exchange rate changes on cash		—			(1	)
Net increase (decrease) in cash and cash equivalents		(270	)		360
Cash and cash equivalents, beginning of period		628			477
Less: Cash classified as held for sale at end of period (Note 3)		(16	)		(42	)

Cash and cash equivalents, end of period	$	342		$	795

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)


	Three Months Ended June 30,
	2005			2004
Net income	$	38		$	8
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net		(3	)		5
Reclassification of mark-to-market losses (gains) to earnings, net		(1	)		9

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $3 and $(8), respectively)		(4	)		14
Foreign currency translation adjustments		—			—

Other comprehensive income, net of tax		(4	)		14

Comprehensive income	$	34		$	22


	Six Months Ended June 30,
	2005			2004
Net income (loss)	$	(224	)	$	78
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net		(21	)		(53	)
Reclassification of mark-to-market losses to earnings, net		11			20

Changes in cash flow hedging activities, net (net of tax benefit of $7 and $20, respectively)		(10	)		(33	)
Foreign currency translation adjustments		—			(15	)
Minimum pension liability (net of tax expense of zero and $1, respectively)		—			2

Other comprehensive loss, net of tax		(10	)		(46	)

Comprehensive income (loss)	$	(234	)	$	32

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 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 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 statement 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 the publication of such financial statements. 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 and six months ended June 30, 2005 and 2004, no material additional AROs were recorded or settled, and our accretion expenses and revisions to estimated cash flows were not material. At June 30, 2005, our ARO liabilities were $37 million for our GEN segment and $10 million for our NGL segment. The $10 million ARO liabilities associated with our NGL segment have been reclassified to liabilities held for sale as a result of our anticipated sale of DMSLP. Please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion.

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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 January 1, 2003 and are using the prospective method of transition as described under SFAS No. 148.

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

Had compensation cost for all stock options granted prior to January 1, 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- and six-month periods ended June 30, 2005 and 2004, respectively.


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions, except per share data)
Net income (loss) as reported	$	38		$	8		$	(224	)	$	78
Add: Stock-based employee compensation expense included in reported net income (loss), net of related tax effects		1			1			2			2
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(1	)		(7	)		(2	)		(16	)

Pro forma net income (loss)	$	38		$	2		$	(224	)	$	64

Earnings (loss) per share:
Basic—as reported	$	0.08		$	0.01		$	(0.62	)	$	0.17
Basic—pro forma	$	0.08		$	(0.01	)	$	(0.62	)	$	0.14
Diluted—as reported	$	0.08		$	0.01		$	(0.62	)	$	0.17
Diluted—pro forma	$	0.08		$	(0.01	)	$	(0.62	)	$	0.14

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 that 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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, 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 $273 million at June 30, 2005, and one of our affiliates has a loan outstanding to one of these entities, which totaled $20 million at June 30, 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 Corporation, which we refer to as “Exelon,” has the sole and exclusive right to direct our efforts to decommission, sell, bankrupt, 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 hydroelectric generation 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 located in New York, we had the option to elect to decommission any or all of these facilities within a 180-day period after the January 31, 2005 closing date. Prior to expiration of the option period which ended on July 30, 2005, we elected to decommission all four of the natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon will direct the decommissioning, sale, or other disposal of the facilities. Further, Exelon is obligated to indemnify us with respect to all operations prior to February 1, 2005, and subsequent to our election to decommission or sell the facilities and must provide written consent for any payments or actions outside the ordinary course of operations. On June 8, 2005 and August 4, 2005, we entered into agreements, as directed by Exelon, to sell our ownership and operating interests in the four natural gas-fired power generation peaking facilities to Alliance Energy Group LLC. The sale, subject to approval by the FERC and review by the New York Public Service Commission, is expected to close by end of year 2005 and is expected to have no impact on our unaudited condensed consolidated financial statements, as Exelon will receive any proceeds from the sale. As a result of the rights retained by Exelon with respect to these facilities, we are not the primary beneficiary of these VIEs, and have not consolidated them in accordance with the provisions of FIN No. 46R. Please see Note 2—Acquisition—Sithe Energies for further discussion regarding this acquisition.

The 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 June 30, 2005, the equipment leases have remaining terms from two to sixteen years and involve a maximum aggregate obligation of $131 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 the “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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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, exclusive of lease or interest costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of June 30, 2005, was approximately $287 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 may cause the facilities to operate at a net cash deficit. 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.

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. SFAS No. 123(R) is effective for January 1, 2006 for all calendar year-end companies. SFAS No. 123(R) requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. We expect to adopt the provisions of SFAS No. 123(R) on January 1, 2006. SFAS No. 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 the date of adoption.

As noted in “Employee Stock Options” above, we adopted the prospective method for expensing the fair value of stock options and restricted stock awards granted after January 1, 2003, and, as such we do not expect the guidance under SFAS No. 123(R) to have a material impact on our consolidated statement of operations.

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 and expect to adopt FIN No. 47 in the first quarter of 2006.

Note 2—Acquisition

Sithe Energies. On January 31, 2005, we acquired 100% 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 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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 Principle 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 approximately $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 7—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 substantially complete at this time and we do not anticipate any material changes. We expect to finalize our allocation of the purchase price in 2005, once the final tax basis of the assets and liabilities acquired has been determined. 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 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		352
Assets from risk-management activities		62
Intangible assets		657

Total assets acquired	$	1,290

Current liabilities	$	(96	)
Deferred income taxes		(189	)
Other long-term liabilities		(59	)
Long-term debt		(797	)

Total liabilities assumed	$	(1,141	)

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 commercial paper. The restricted cash and investments are related to a sinking fund required by Independence’s 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 7—Debt—Independence Debt.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

Of the $657 million of acquired intangible assets, $487 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 as a reduction to revenue in our unaudited condensed consolidated statements of operations, through October 2014. In addition, Independence holds a power tolling contract, valued at $154 million, and a gas supply agreement, valued at $16 million, with another of our subsidiaries. Upon completion of our purchase of Independence, the power tolling agreement and the gas supply agreement were effectively settled, which resulted in a 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.” As a result, 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. In the second quarter 2005, we substantially completed the determination of the tax basis of the assets and liabilities acquired, and revised our purchase price allocation, resulting in additional excess of the fair value of the assets acquired over the cost of the acquisition. Accordingly, we reversed $13 million of the pre-tax charge recorded in the first quarter, resulting in a net pre-tax charge of $170 million in accordance with EITF Issue 04-01, as well as made additional revisions to our deferred income taxes ($80 million decrease to liability), intangible assets ($52 million decrease to asset), and property, plant and equipment balances ($28 million decrease to asset). Upon settlement of the power tolling and gas supply agreements, the firm capacity sales agreement with Con Edison is the only remaining intangible asset associated with the acquisition of ExRes, which is included in intangibles and prepaids and other current assets on our unaudited condensed consolidated balance sheets.

We have exercised our right to require Exelon to decommission, sell, or otherwise dispose of all 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. On June 8, 2005 and August 4, 2005, we entered into agreements, as directed by Exelon, to sell our ownership and operating interests in the four natural gas-fired power generation peaking facilities in upstate New York to Alliance Energy Group LLC, which includes our 80% interest in an 84 megawatt plant in Massena and our 85% interest in an 83 megawatt plant in Ogdensburg. The sale, subject to approval by the FERC and review by the New York Public Service Commission, is expected to close by end of year 2005 and is expected to have no impact on our unaudited condensed consolidated financial statements, as Exelon will receive any proceeds from the sale. 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.

Note 3— Discontinued Operations, Dispositions and Contract Terminations

Discontinued Operations

Natural Gas Liquids. On August 2, 2005, we entered into an agreement to sell our ownership interests in DMSLP, which comprises substantially all of the operations of our NGL segment, to Targa Resources, Inc. and two of its subsidiaries. We expect to receive $2.475 billion in cash proceeds from the sale, subject to purchase price adjustments, of which $2.35 billion will be paid by Targa at closing, and, based on current expectations, approximately $125 million, representing cash collateral, will be paid by Targa within 60 days of closing. In addition, we expect our responsibility for approximately $75 million in letters of credit to be eliminated at closing. The parties have made customary representations, warranties and covenants in the purchase agreement. The completion of the transaction is conditioned upon the expiration or termination of the Hart-Scott-Rodino waiting period and the fulfillment of other closing conditions as set forth in the purchase agreement, including the lack of a material adverse effect and other conditions that are customary in transactions of this type. The purchase agreement also contains customary termination rights, including termination rights by either party in the event the transaction has not been consummated by December 31, 2005. In certain circumstances (including

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

the failure by Targa to close the transaction when all conditions precedent to Targa’s obligation to close have been satisfied), the purchase agreement provides for Targa to pay to Dynegy liquidated damages of $65 million upon termination of the purchase agreement. Pending satisfaction of the conditions in the purchase agreement, the sale is expected to close in the fourth quarter 2005. Please see Note 7—Debt—Natural Gas Liquids for a discussion of our anticipated use of proceeds.

At June 1, 2005, NGL met the held for sale classification requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets and liabilities classified as assets held for sale or liabilities held for sale at June 30, 2005 are as follows (in millions):


Current Assets:
Cash	$	16
Accounts receivable, net of allowance for doubtful accounts of $2		266
Inventory		67
Other		20

Total Current Assets	$	369

Long-Term Assets:
Property, plant and equipment, net	$	1,063
Unconsolidated investments		78
Goodwill		15
Other		3

Total Long-Term Assets	$	1,159

Current Liabilities:
Accounts payable	$	65
Other		74

Total Current Liabilities	$	139

Long-Term Liabilities:
Other		25

Total Long-Term Liabilities	$	25

Additionally, the $107 million in minority interest and $1 million of accumulated other comprehensive loss at June 30, 2005 relate to NGL and will not be included in our unaudited condensed consolidated balance sheets subsequent to the sale. As a result of the anticipated sale of DMSLP, our expected realization of certain deferred tax assets has been accelerated. For further discussion, please read Note 13—Income Taxes—Balance Sheet Classification.

SFAS No. 144 also requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of NGL’s property, plant and equipment, effective June 1, 2005. Depreciation and amortization expense related to NGL totaled $15 million and $35 million in the three- and six-month periods ended June 30, 2005, compared to $25 million and $45 million in the three- and six-month periods ended June 30, 2004.

In addition, SFAS No. 144 requires a loss to be recognized if assets held for sale less liabilities held for sale are in excess of fair value less costs to sell. Because the fair value less costs to sell is greater than assets held for

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

sale less liabilities held for sale, we did not recognize a loss in the second quarter 2005. However, as a result of the anticipated sale of DMSLP, we reduced our deferred tax valuation allowance. For further discussion, please read Note 13—Income Taxes—Capital Loss Valuation Allowance. We expect to record a pre-tax gain of approximately $1.1 billion ($700 million after-tax) upon closing of the transaction.

Pursuant to SFAS No. 144, we are reporting the results of NGL’s operations as a discontinued operation. Accordingly, the results of operations of our NGL segment have been included in discontinued operations for all periods presented. EITF Issue 87-24, “Allocation of Interest to Discontinued Operations,” requires that interest expense on debt that is required to be repaid upon the sale of DMSLP should be reclassified to discontinued operations. Therefore, interest expense on our $594 million term loan scheduled to mature in 2010 and our $189 million generation facility debt scheduled to mature in 2007 has been allocated to discontinued operations, as the respective debt instruments are required to be paid upon the sale of DMSLP. Such interest expense totaled $14 million and $4 million for the three months ended June 30, 2005 and 2004, respectively, and $25 million and $6 million for the six months ended June 30, 2005 and 2004, respectively. For further information, please see Note 7—Debt—Natural Gas Liquids.

Additionally, results from NGL’s operations include revenues and cost of sales arising from intersegment transactions, which will cease after the sale of DMSLP. NGL processes natural gas and sells this natural gas to CRM for resale to third parties. NGL also purchases natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGL’s results were reclassified to discontinued operations, the effects of these intersegment transactions eliminated in consolidation, including the ultimate third party settlement, previously recorded in other segments, have also been reclassified to discontinued operations.

Other. 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 all of our discontinued operations, including the NGL operations discussed above:


	U.K. CRM			DGC		NGL		Total
	(in millions)
Three Months Ended June 30, 2005
Revenue	$	—		$	—	$	933	$	933
Income from operations before taxes		1			—		35		36
Income from operations after taxes		—			2		145		147

Three Months Ended June 30, 2004
Revenue	$	—		$	—	$	766	$	766
Income from operations before taxes		1			—		70		71
Income (loss) from operations after taxes		(19	)		—		42		23

Six Months Ended June 30, 2005
Revenue	$	—		$	—	$	1,979	$	1,979
Income from operations before taxes		5			—		81		86
Income from operations after taxes		5			—		174		179

Six Months Ended June 30, 2004
Revenue	$	—		$	—	$	1,667	$	1,667
Income from operations before taxes		18			3		134		155
Income (loss) from operations after taxes		(7	)		2		82		77

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

In the six months ending June 30, 2005, we recognized $5 million of pre-tax income primarily associated with U.K. CRM’s receipt 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 5—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. In the second quarter 2004, we recognized a tax expense of $20 million in U.K. CRM related to charges resulting from the conclusion of prior year tax audits. Please see Note 13—Income Taxes—Prior Year Tax Audits for further discussion.

Dispositions and Contract Terminations

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 June 30, 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 was to be released to us upon the occurrence of specified events relating to contingent environmental liabilities associated with Illinois Power’s former generating facilities (currently owned by DMG). The Baldwin consent decree, which was approved and entered by the Illinois federal district court on May 27, 2005, satisfied the condition for the release of the $100 million in escrowed funds. We received the funds on July 27, 2005. Please read Note 10—Commitments and Contingencies—Baldwin Station Litigation for further discussion of this consent decree. During the time that these funds remained in escrow, the escrow fund earned interest on a quarterly basis.

During the first quarter 2005, we paid approximately $5 million to Ameren for a final working capital purchase price adjustment. As a result of an adjustment to the contingent liabilities identified as part of the Illinois Power sale, we recorded a $12 million charge in the second quarter of 2005. On July 27, 2005, we paid $8 million in partial satisfaction of such contingent liabilities. For further discussion, please see Note 10—Commitments and Contingencies—Guarantees and Indemnification. The adjustment to the contingent liabilities resulted in an increase to our capital loss carryforward, and a corresponding increase to the deferred tax valuation allowance of $4 million.

Further, on September 30, 2004, we entered into a two-year power purchase agreement with Illinois Power, now known as AmerenIP. Under the terms of this agreement, which became effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48 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 MW of capacity in 2005 and 150 MW 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 six-month period ended June 30, 2004. In addition, SFAS No. 144 requires a loss to be recognized in the amount by which assets held for sale less liabilities held for sale are in excess of fair value less

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

costs to sell. Accordingly, for the three- and six-month periods ended June 30, 2004, we recorded pre-tax losses on the sale of $48 million and $69 million, respectively. The first quarter charge, which was primarily associated with the expected transaction costs and an impairment of assets, is reflected in loss on sale of assets, net, and impairment and other charges on the unaudited condensed consolidated statements of operations. The second quarter charge, an impairment of assets, 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 income from discontinued operations, net of taxes, on our unaudited condensed consolidated statements of operations, and prior periods would be required to be restated to conform to this presentation. To qualify for discontinued operations classification, SFAS No. 144 and subsequent interpretations, specifically 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 $108 million and $183 million of revenues, derived from power sales to Illinois Power occurring subsequent to the disposition, are reflected in our continuing operations for the three- and six-month periods ending June 30, 2005.

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 per share would have approximated the following pro forma amounts for the three- and six-month periods ended June 30, 2004:


	Three Months Ended		Six Months Ended
	June 30, 2004
	(in millions, except per share data)
Revenues:
As reported	$	689	$	1,456
Pro forma		480		925

Net income applicable to common stockholders:
As reported		2		67
Pro forma		15		72

Earnings per share—Net income applicable to common stockholders:
Basic—as reported	$	0.01	$	0.17
Basic—pro forma	$	0.04	$	0.19
Diluted—as reported	$	0.01	$	0.17
Diluted—pro forma	$	0.04	$	0.19

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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 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 income from discontinued operations on our unaudited condensed consolidated statements of operations.

Indian Basin. In April 2004, we sold our 16% interest in the Indian Basin Gas Processing Plant for approximately $48 million. In the second quarter 2004, we recognized a pre-tax gain on the sale of approximately $36 million. This gain is included in income from discontinued operations on our unaudited condensed consolidated statements of operations.

PESA. In April 2004, we sold our interest in the Plantas Eolicas, S.A. de R.L. 20 MW wind-powered electric generation facility located in Costa Rica for approximately $11 million. We recognized a pre-tax loss of approximately $1 million on the sale. This loss is included in loss on sale of assets, net, on our unaudited condensed consolidated statements of operations.

Gas Transportation Contracts. In June 2004, we agreed to exit four long-term natural gas transportation contracts whose purpose was to secure firm pipeline capacity through 2014 in support of our former third-party marketing and trading business. In exchange for exiting these obligations, we paid $20 million in June 2004, $16 million in December 2004 and $26 million in March 2005. This payment obligation was recorded at its fair value of $40 million and was accreted to $42 million over the period July 1, 2004 through March 31, 2005. Additionally, we reversed an aggregate liability of $148 million associated with the transportation contracts that was originally established in 2001 and recognized a pre-tax gain of $88 million related to these transactions. This gain is included in revenues on our unaudited condensed consolidated statements of operations and is included in the results of our CRM segment. This agreement eliminated our obligation to make approximately $295 million in aggregate fixed capacity payments from April 2005 through 2014.

Note 4—Restructuring Charges

In the three and six months ended June 30, 2004, we recorded pre-tax charges relating to our interest in Illinois Power totaling $48 million and $69 million, respectively. For further discussion, please read Note 3—Discontinued Operations, Dispositions and Contract Terminations—Dispositions and Contract Terminations—Sale of Illinois Power. In addition, in the three months ended June 30, 2004, we recorded a $5 million pre-tax charge related to the impairment of our midstream assets.

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		—		(5	)		(5	)

Balance at June 30, 2005	$	3	$	19		$	22

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

We expect the $19 million accrual as of June 30, 2005 associated with cancellation fees and operating leases to be paid by the end of 2007 when the leases expire.

Note 5—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.

During the three and six months ended June 30, 2005, we recorded a $2 million and $6 million charge, respectively, 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 and six months ended June 30, 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 and six months ended June 30, 2005 and 2004, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities, net at June 30, 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 $22 million are currently estimated to be reclassified into earnings over the 12-month period ending June 30, 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 and six months ended June 30, 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 and six months ended June 30, 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 June 30, 2005, we had no net investment hedges in place.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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:


	June 30, 2005			December 31, 2004
	(in millions)
Cash flow hedging activities, net	$	(26	)	$	(16	)
Foreign currency translation adjustment		16			16
Minimum pension liability		(13	)		(13	)

Accumulated other comprehensive loss, net of tax	$	(23	)	$	(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 6—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:


	June 30, 2005			December 31, 2004
	(in millions)
Equity affiliates:
GEN investments	$	290		$	337
NGL investments		78			78

Total equity affiliates		368			415
Other affiliates, at cost		—			6

		368			421
Less: Unconsolidated investments held for sale at end of period		(78	)		—

Total unconsolidated investments	$	290		$	421

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


	Six Months Ended June 30,
	2005				2004
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	158	$	79	$	352	$	176
Operating income		1		1		163		82
Net income		4		2		164		82

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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


	Six Months Ended June 30,
	2005				2004
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	190	$	63	$	428	$	161
Operating income		27		10		72		30
Net income		25		9		50		22

Earnings from unconsolidated investments of $7 million for the six months ended June 30, 2005, include the $9 million above and $2 million from West Coast Power offset by $4 million of earnings from NGL investments which are included in income from discontinued operations. Earnings from unconsolidated investments of $88 million for the six months ended June 30, 2004, include the $22 million above and $82 million from West Coast Power, offset by $4 million of earnings from NGL investments which are included in income from discontinued operations, an $8 million impairment of our Michigan Power equity investment discussed below and $4 million of amortization of the difference between the cost of our unconsolidated investments and our underlying equity in their net assets.

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. In the three- and six-month periods ended June 30, 2004, we recorded impairments on our investment in Michigan Power totaling $1 million and $8 million, respectively, to adjust our book value to the selling price.

Note 7—Debt

Revolving Credit Facility. During the three- and six-month periods ended June 30, 2005, we increased letters of credit under our $700 million revolving credit facility by $190 million and $199 million, respectively, in the aggregate, resulting in a total of $293 million outstanding at June 30, 2005. As of June 30, 2005, there were no borrowings outstanding under this facility. During the period from June 30, 2005 through August 4, 2005, we increased our outstanding letters of credit under this facility by $29 million.

Natural Gas Liquids. As further discussed in Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids, we have entered into an agreement to sell DMSLP. The terms of our credit facility and the SPN indenture and security agreements govern how we may use the proceeds from this sale. The credit facility requires repayment and termination upon the sale of DMSLP. We anticipate either (i) amending the current facility or (ii) replacing the current facility with a new cash collateralized credit facility concurrently with the closing of the sale.

Upon repayment of the credit facility ($594 million scheduled to mature in 2010), we must also repay the generation facility ($189 million scheduled to mature in 2007). We can elect to use the balance of the proceeds to (i) repay parity lien debt, provided that any offer to repay parity lien debt holders is made on a pro rata basis or (ii) make a capital expenditure or invest in various type of assets defined as Replacement Assets in the agreements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

Any net proceeds from a sale of DMSLP that are not applied or invested in the manner described above will constitute Excess Proceeds. If the Excess Proceeds exceed $50 million, we must make an Asset Sale Offer to holders of our SPNs within 365 days from closing of the sale. The offer price in the Asset Sale Offer shall be equal to 100% of the principal amount plus accrued and unpaid interest. If the SPN holders decline pro rata repayment at par, then the balance of the proceeds can be used for any other purposes not otherwise restricted by the SPN indenture.

Repayments. In the first half of 2005, we paid the outstanding $18 million balance on our 8.125% senior notes, which matured in March 2005. We also made payments of $17 million related to the Independence Senior Notes due 2007 and $3 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—Acquisition—Sithe Energies for further discussion of this transaction.

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 - $17 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 us 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 June 30, 2005, Independence had current restricted cash of $38 million as reflected on our unaudited condensed consolidated balance sheets. As of June 30, 2005, Independence had short-term and long-term restricted investment balances of $2 million and $84 million, respectively. The restricted investment balances are included in prepayments and other current assets and restricted investments, respectively, on our unaudited condensed consolidated balance sheets.

Note 8—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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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. In July 2005, we declared a dividend of $11 million to be paid on or before August 11, 2005.

Note 9—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 outstanding during the period.

The reconciliation of basic loss per share from continuing operations to diluted loss per share from continuing operations is shown in the following table:


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions, except per share amounts)
Income (loss) from continuing operations	$	(109	)	$	(15	)	$	(403	)	$	1
Preferred stock dividends		(6	)		(6	)		(11	)		(11	)

Loss from continuing operations for basic loss per share		(115	)		(21	)		(414	)		(10	)
Effect of dilutive securities:
Interest on convertible subordinated debentures		2			2			3			3
Dividends on Series C preferred stock (2)		6			—			11			11

Income (loss) from continuing operations for diluted loss per share	$	(107	)	$	(19	)	$	(400	)	$	4

Basic weighted-average shares		380			378			379			377
Effect of dilutive securities:
Stock options		2			2			2			2
Convertible subordinated debentures		55			55			55			55
Series C preferred stock (2)		69			—			69			69

Diluted weighted-average shares		506			435			505			503

Loss per share from continuing operations:
Basic	$	(0.30	)	$	(0.06	)	$	(1.09	)	$	(0.03	)

Diluted (1)	$	(0.30	)	$	(0.06	)	$	(1.09	)	$	(0.03	)

(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 and the loss from continuing operations for basic loss per share

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

amount to calculate both basic and diluted loss per share for the three and six months ended June 30, 2005 and 2004.

(2)

The diluted shares for the three months ended June 30, 2004 do not include the effect of the preferential conversion to Class B common stock of the Series C convertible preferred stock held by a Chevron subsidiary, as such inclusion would have been anti-dilutive when the calculation was performed in 2004.

Note 10—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.

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:

•

On May 27, 2005, the U.S. district court entered and approved the consent decree associated with our Baldwin Station litigation. The requisite appeal period expired on July 26, 2005, with no appeals being filed. 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.

•

In July 2005, the U.S. district court approved the comprehensive settlement agreement of the parties in our shareholder class action litigation. As part of the settlement, we agreed to make an aggregate settlement payment of $468 million (consisting of $150 million funded by insurance proceeds, two cash payments by DHI totaling $250 million, and the issuance of 17,578,781 shares of 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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

•

Also in July 2005, the state district court approved our settlement of the shareholder derivative litigation. Under this settlement, we 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.

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 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 were lead plaintiff and Lerach Coughlin Stoia & Robbins, LLP was class counsel. Reserves were provided in connection with this litigation.

In October 2004, in response to our June 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 for the Securities Act claims includes persons who purchased our stock, provided that the purchase is traceable to the December 20, 2001 offering of Class A common stock.

In July 2005, the court approved the comprehensive settlement agreement reached by the parties to the class action litigation in April 2005, which provided for the following:

•

An aggregate settlement payment by Dynegy of $468 million, comprised of a $150 million cash payment funded by insurance proceeds, a $250 million cash payment by DHI, and the issuance to the plaintiffs of $68 million in Dynegy’s Class A common stock, consisting of 17,578,781 shares based on a calculation using a volume weighted average stock price for the 20 trading days ending April 15, 2005. We were 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 plus interest upon court approval, which we paid in July 2005. As required by the settlement, we intend to issue the shares of Class A common stock promptly following expiration of the appeal period which occurred on August 8, 2005.

•

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.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

similar to those described above. These lawsuits were 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 court approved the settlement agreement in July 2005. Under this settlement agreement, Dynegy 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 settlements described above, and there were no findings of any violations of the federal securities laws. We recorded pre-tax charges of $18 million ($12 million after-tax) and $240 million ($168 million after-tax) in the three and six months ended June 30, 2005 and $31 million ($20 million after-tax) in the three and six months ended June 30, 2004, related to these settlements and associated legal expenses. The pre-tax charges are reflected in general and administrative expenses on our unaudited condensed consolidated statements of operations. The charge recorded in the three months ended June 30, 2005 is primarily a result of appreciation in our stock price from the date of the settlement through June 30, 2005. We expect to record another adjustment to income in the third quarter 2005, to the extent the closing stock price on the date of issuance differs from $4.86, the closing stock price on June 30, 2005.

ERISA/Illinois Power 401(k) Litigation. In January 2005, three DMG employees who are participants in the DMG 401(k) Savings Plan for employees covered under a collective Bargaining Agreement (formerly known as the Illinois Power Company Incentive Savings Plan For Employees Covered Under a Collective Bargaining Agreement), which we refer to as the “DMG 401(k) Plan,” purporting to represent all DMG and Illinois Power employees who held Dynegy common stock through the DMG 401(k) Plan during the period from February 2000 through the present, filed a lawsuit in federal court in the Southern District of Illinois against us, Illinois Power Company, DMG and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG 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 have filed motions to transfer this litigation to the Southern District of Texas and a ruling on these motions is expected in the third quarter. It is not possible to predict with certainty whether we will incur any liability or to estimate the range of possible loss, if any, that we might incur in connection with these lawsuits. However, 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.

Enron/NNG VEBA Litigation. Prior to our acquisition of NNG from Enron, NNG employees were participants in a post-retirement medical plan maintained by Enron. The plan’s assets were maintained in a VEBA trust, along with the assets of other Enron companies whose plans were included in the same VEBA trust (the “Enron VEBA”). Enron filed bankruptcy in December 2001. When we acquired NNG in January 2002, the assets of the Enron VEBA had not been distributed to its participant companies, though we and NNG made the appropriate requests for such a distribution. In July 2002, we estimated that approximately $25.4 million of the assets of the Enron VEBA were attributable to the NNG employees who participated in the post-retirement medical plan. On July 1, 2002, as part of our sale of NNG to Mid American Energy Holdings Company, NNG

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

established a separate VEBA trust solely for its plan participants (the “NNG VEBA”). As a condition of the sale agreement, we placed $25.4 million into escrow under terms providing that if Enron did not release NNG’s share of the VEBA assets by August 2004, NNG was entitled to the escrowed money to fund the NNG VEBA.

As Enron did not release the funds from the Enron VEBA as of August 2004, NNG placed our escrowed funds into the NNG VEBA. Pursuant to the escrow agreement, once the Enron VEBA releases NNG’s funds to the NNG VEBA, we will be entitled to be reimbursed an equivalent amount, up to $25.4 million.

In June 2005, in accordance with the terms of the escrow agreement, NNG, the NNG VEBA trustee, and the NNG VEBA participants as a class, filed a class action lawsuit in Nebraska federal court against various Enron related parties, including the individual members of the Enron Benefit Plan Committee, alleging a breach of fiduciary duty under ERISA and seeking immediate disbursement of the Enron VEBA assets. As we have a receivable recorded to reflect our rights to this distribution, an adverse outcome in this matter would impact us, even though we are not a party. We do not believe that an adverse result in 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 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. Following a public comment period and hearing, the Court entered and approved the consent decree on May 27, 2005. No appeals were filed prior to the expiration of the appeal period on July 26, 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. Based upon preliminary engineering estimates, the installation of these emission controls, including the previously planned conversion of our Vermilion facility to low-sulfur PRB coal, is expected to cost approximately $320 million through 2010, with an additional investment of approximately $225 million in the 2011-2012 timeframe. These estimates represent management’s reasonable judgment with respect to 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 the actual costs incurred with regard to these emission controls to differ materially from such estimates. 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.

The $9 million civil penalty pursuant to the consent decree was paid on June 17, 2005. Reserves have been provided in an amount adequate to cover 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; however, the EPA could eventually commence enforcement actions based on activities at these plants. At this time, we are unable to assess the likelihood of any such additional EPA enforcement actions.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

California Market Litigation. We and various 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 Snohomish County v. Dynegy Power Marketing, et al.; and Bustamante [I] v. Dynegy Inc., et al. These cases were coordinated before a single federal judge, who dismissed two of them, Lockyer and Snohomish County, in the first quarter of 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 Snohomish County filed a Petition for Writ of Certiorari to the U.S. Supreme Court in November 2004 that was denied in June 2005. The remaining coordinated cases were remanded to a California state court, where we filed a motion to dismiss in July 2005.

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 remanded to state court, and in May 2005, defendants filed a motion to dismiss. Plaintiffs filed their response in June 2005, and shortly thereafter, the defendants replied. The Court has not yet issued its ruling.

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 U.S. District Court for the Northern District of California. Plaintiffs challenged the removal and thus, 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 DPM, 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. We intend to file a motion for summary disposition to dismiss the appeal upon the filing of plaintiff’s brief in August 2005.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

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. We removed the action to federal court in June 2005.

We believe that we have meritorious defenses to these claims and intend to defend against such claims. 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.

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 Cal ISO will determine the entitlement to refund and/or the liability of each non-settling market participant. 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 dispute. Assuming the master netting agreement is enforceable, 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 had been fully reserved in the fourth quarter 2001. In the event that Enron prevails 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 have pursued resolution of this dispute through arbitration; however, we were unsuccessful in our efforts to arbitrate

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

because the Bankruptcy Court did not grant our motion, which was opposed by Enron, to permit arbitration with a non-bankrupt Enron entity. We then filed a motion with the Bankruptcy Court to allow us to proceed to discovery and trial in order 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 mediate the dispute with Enron. The parties participated in mediation in November 2004, and have had further discussions since that time, 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 that 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 because 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 third 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 that claim 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 Mateo v. Sempra Energy et al. (filed in state court in December 2004); County of Santa Clara v. 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 reports 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.” In April 2005, defendants moved to dismiss the Coordinated Gas Index Cases on preemption and filed rate grounds. The Court denied defendants’ motion in June 2005. 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. 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 of alleged index manipulation filed by the defendant, Multiut, against whom we have a pending breach of gas purchase contract claim. Multiut, along with the remaining federal court cases (Abelman, Fairhaven Power, Utility Savings and

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Leggett) are pending transfer, or have already been transferred, to the federal judge in Nevada who presided over the Texas-Ohio matter.

We are analyzing all of 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. 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.

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 July 2004, prior to the Court’s ruling on defendants’ motions to dismiss, the plaintiff voluntarily dismissed the Maryland federal court action against all defendants. Shortly thereafter, plaintiff filed a class action lawsuit in 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 January 2005, the newly added defendants filed motions to dismiss on various grounds. Oral argument on some of the pending motions occurred in April 2005. In June 2005, the Court denied defendants’ motions to dismiss on the following grounds: filed rate doctrine, field preemption, certain antitrust claims and unjust enrichment. However, the Court granted defendants’ motion to dismiss under antitrust law to the extent Plaintiffs’ claims are based on price fixing. In August 2005, the Court granted certain defendants’ (including Dynegy Inc.) motion to dismiss all antitrust claims on statute of limitations grounds. Our motion to dismiss for lack of personal jurisdiction remains pending before the Court. 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 this lawsuit, however, we believe that any liability incurred as a result of this litigation would not 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. All of the lawsuits pending in Austria have been stayed. 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. Oral argument on plaintiffs’ motion was held in June 2005. An order is expected in September 2005.

We continue to oppose these claims 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 – Texas (formerly U.S. Attorney Investigations). We are continuing to cooperate fully with the U.S. Attorney’s office in Houston in its ongoing investigation of the industry’s gas trade reporting practices. We do not believe these investigations will have a material adverse effect on our financial condition, results of operations or cash flows.

In January 2003, one of our former natural gas traders was indicted 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 December 2004, a second indictment was filed against this same individual and other individuals, not related to Dynegy, alleging conspiracy to falsely report gas prices to various index publications. A superceding indictment was returned in July 2005 recharging the original violations and adding additional charges. There is no trial date set for this indictment.

U.S. Attorney Investigations – California (formerly U.S. Attorney Investigations). The U.S. 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 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 record keeping, 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.

Guarantees and Indemnifications. We routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements,

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and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third-party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be extremely remote.

During 2003, as part of our sale of Northern Natural, the Rough and Hornsea gas storage facilities and certain natural gas liquids assets, we provided indemnities to third parties regarding environmental, tax, employee and other representations. Maximum recourse under these indemnities is limited to $209, $857 and $28 for the Northern Natural, Rough and Hornsea gas storage facilities and natural gas liquids assets, respectively. We also entered into similar indemnifications regarding environmental, tax, employee and other representations when completing other asset sales such as, but not limited to, Hackberry LNG Project, SouthStar Energy Services and various Canadian assets. We carry reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

As a condition of our 2004 sale of Illinois Power and our interest in Joppa, we provided indemnifications to third parties regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, we have indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased gas and investments in specified items. Although there is no limitation on our liability under this indemnity, our indemnity is limited to 50% of any such losses. Illinois Power had not sustained any material losses in recent years and, at the time of the sale of Illinois Power to Ameren, our management considered the probability of any material loss under this indemnity remote. Consequently, the value of the indemnification was initially deemed to be insignificant. In the second quarter of 2005, however, the ICC rejected an Administrative Law Judge’s proposed order and entered an order in one of the proceedings covered by the scope of this indemnification that disallowed items relating to one of Illinois Power’s gas storage fields, resulting in a negative revenue requirement impact to Ameren. On July 27, 2005, we made a payment of $8 million to Ameren in settlement of Ameren’s indemnification claims with respect to this ICC order. Although the ICC has not issued an order in any other cases, there are other cases in which it is now probable, based on this recent action by the ICC that some loss may occur and a liability can be reasonably estimated. As a result, in the second quarter 2005, we recognized a pre-tax charge of $12 million, which is included in general and administrative expense on our unaudited condensed consolidated statements of operations. Further disallowances and other events, which fall within the scope of the indemnity, may still occur; however, we are not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. We intend to contest any proposed disallowances.

We have also entered into various indemnifications regarding environmental, tax, employee and other representations when completing other asset sales such as, but not limited to Michigan Power, Oyster Creek, Hartwell, Commonwealth, Sherman, Indian Basin and PESA. We carry reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

During 2004, as part of entering into a “back-to-back” power purchase agreement with Constellation, under which Constellation effectively received our rights to purchase approximately 570 MW of capacity and energy arising under our Kendall tolling contract, we guaranteed Constellation an aggregate $3.5 million in reactive power revenues over the four year term of the power purchase agreement. We established a liability of $0.3 million reflecting the fair value of this guarantee, but have made no payments or incurred any other expense relating to this guarantee.

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For the Interim Periods Ended June 30, 2005 and 2004

Note 11—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 U.S. Congress, as well as various state legislative bodies, are considering a number of bills that could impact current 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.

Roseton State Pollutant Discharge Elimination System Permit. Roseton’s SPDES Permit was issued for a five-year term in 1987. Prior to expiration of the permit, Central Hudson Gas & Electric (former owner) filed a timely and sufficient application to renew the SPDES Permit. Under New York State law, when a timely and sufficient application for renewal is filed before a SPDES Permit expires, the permit is extended by operation of law until final action is taken on the renewal application. In April 2005, the NYSDEC issued to DNE a draft SPDES Permit for the Roseton plant. The draft SPDES Permit contains provisions governing, among other things, the cooling water intake and the discharge of heated effluent water. These provisions require the facility to actively manage its water intake to reduce impingement mortality of fish by 85% and to reduce entrainment mortality of aquatic organisms including juvenile fish, larvae and fish eggs by 70% during the first two years of the renewal term, and by 80% thereafter.

On July 18, 2005, a public hearing was held to receive public comments on the draft SPDES Permit. On July 19 and 20, 2005, the Administrative Law Judge held an issues conference to consider party status and to determine what issues should be subject to adjudication at the adjudicatory hearing. Three organizations filed petitions for party status and appeared through counsel at the issues conference. The petitioners, Riverkeeper, Inc., Natural Resource Defense Council, Inc. and Scenic Hudson, Inc. seek to impose a permit requirement that the Roseton plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing entrainment and impingement. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts from the facility’s cooling water intake structures. The current draft SPDES Permit does not require installation of a closed cycle cooling system; however, it does require entrainment and impingement mortality reductions that exceed the best technology available requirements of the USEPA regulations applicable to existing facilities. We expect that the adjudicatory hearing on the Roseton draft SPDES Permit will be held in the spring or summer of 2006. We believe that the Petitioners’ claims are without merit and we plan to vigorously oppose those claims. Given the cost of installing a closed cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operations and cash flows.

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

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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 are currently challenging the Court’s ruling voiding our permit. We are also continuing to seek renewal of the water intake and discharge permit in proceedings before the NYSDEC. 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 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. On June 16, 2005, the FERC issued an order accepting the updated market power analyses submitted by Sithe Energies and Dynegy. Our next (“triennial”) market power analysis is due June 16, 2008.

Note 12—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
	Three Months Ended June 30,
	2005			2004			2005		2004
	(in millions)
Service cost benefits earned during period	$	3		$	6		$	—	$	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		$	1	$	4

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	Pension Benefits						Other Benefits
	Six Months Ended June 30,
	2005			2004			2005		2004
	(in millions)
Service cost benefits earned during period	$	6		$	12		$	1	$	2
Interest cost on projected benefit obligation		4			20			2		6
Expected return on plan assets		(4	)		(24	)		—		(3	)
Recognized net actuarial loss		2			8			—		3

Total net periodic benefit cost	$	8		$	16		$	3	$	8

Contributions. During 2005, we expect to contribute approximately $31 million to our pension plans, the final $21 million of which we expect to pay in September 2005, and $0.3 million to our other post-retirement benefit plans in 2005. During the first half of 2005, we made $7 million in contributions, and we made an additional $3 million contribution in July.

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 13—Income Taxes

Effective Tax Rate. The income tax benefits included in our loss from continuing operations were as follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
	(in millions, except rates)
Income tax benefit	$	41		$	29		$	215		$	82
Effective tax rate		27	%		66	%		35	%		101	%

We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. During 2005, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to the nondeductible portion of the shareholder litigation settlement, offset by the changes in the valuation allowance, as further discussed below, and adjustments to the effective state tax rate. During 2004, our overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to changes in the valuation allowance and adjustments related to the conclusion of prior year tax audits, as further discussed below.

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Capital Loss Valuation Allowance. As a result of the anticipated sale of DMSLP, as further discussed in Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids, we reduced the valuation allowance related to our capital loss carryforward by $125 million in both the three and six months ended June 30, 2005. This benefit is reflected in income from discontinued operations on our unaudited condensed consolidated statements of operations.

The changes in the valuation allowance by attribute since December 31, 2004 were as follows:


	Capital Loss Carryforwards			Foreign Tax Credits			State NOL Carryforwards			Total
	(in millions)
Balance as of December 31, 2004	$	(125	)	$	(38	)	$	(1	)	$	(164	)
Acquisition of Sithe Energies		(17	)		—			(20	)		(37	)
Tax benefit from discontinued operations		125			—			—			125

Balance as of June 30, 2005	$	(17	)	$	(38	)	$	(21	)	$	(76	)

Previously, as a result of the asset sales discussed in Note 3—Discontinued Operations, Dispositions and Contract Terminations, as well as other transactions occurring in 2004, we reduced the valuation allowance related to our capital loss carryforward by $8 million and $47 million in the three and six months ended June 30, 2004, respectively. This benefit is reflected in income tax benefit (expense) on our unaudited condensed consolidated statements of operations.

Prior Year Tax Audits. In the second quarter 2004, we recognized an expense of $17 million associated with the conclusion of prior year federal tax audits. A charge of $20 million related to our discontinued U.K. CRM business is included in income from discontinued operations on our unaudited condensed consolidated statements of operations. An offsetting benefit of $3 million is reflected in income tax benefit (expense) on our unaudited condensed consolidated statements of operations.

Balance Sheet Classification. The balance sheet classification of deferred tax liabilities and assets is as follows:


	June 30, 2005			December 31, 2004
	(in millions)
Deferred tax assets:
Current	$	496		$	74
Non-current		13			12
Deferred tax liabilities:
Non-current		(885	)		(597	)

Net deferred tax liability	$	(376	)	$	(511	)

The balance sheet classification of our deferred tax liabilities and assets has changed significantly since December 31, 2004. As a result of our projected gain on the sale of DMSLP, coupled with current year operations, we expect to utilize approximately $860 million of our net operating loss carryforwards and approximately $350 million of our capital loss carryforwards within the next 12 months. Accordingly, we have reclassified the deferred tax assets associated with these attributes from non-current to current as of June 30, 2005.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

Note 14—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, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,” 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.

In accordance with SFAS No. 144, results associated with our NGL segment, primarily consisting of DMSLP, have been reclassified to discontinued operations for all periods presented. These results include revenues and cost of sales arising from intersegment transactions, which will cease after the sale of DMSLP. NGL processes natural gas and sells this natural gas to CRM for resale to third parties. NGL also purchases natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGL’s results were reclassified to discontinued operation, the effects of these intersegment transactions, eliminated in consolidation, including the ultimate third party settlement, previously recorded in other segments, have also been reclassified to discontinued operations. Revenues from continuing operations represents third party sales not originating from NGL.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

Reportable segment information for the three- and six-month periods ended June 30, 2005 and 2004 is presented below.

Dynegy’s Segment Data for the Quarter Ended June 30, 2005

(in millions)


	GEN			NGL			REG		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	428		$	—		$	—	$	(3	)	$	—		$	425
Other		30			—			—		4			—			34

		458			—			—		1			—			459
Intersegment revenues		(17	)		—			—		17			—			—

Total revenues	$	441		$	—		$	—	$	18		$	—		$	459

Depreciation and amortization	$	(50	)	$	—		$	—	$	—		$	(4	)	$	(54	)
Operating income (loss)	$	19		$	—		$	—	$	(15	)	$	(68	)	$	(64	)
Earnings from unconsolidated investments		4			—			—		—			—			4
Other items, net		2			—			—		(1	)		5			6
Interest expense																(96	)

Loss from continuing operations before taxes																(150	)
Income tax benefit																41

Loss from continuing operations																(109	)
Income from discontinued operations, net of taxes																147

Net income															$	38

Identifiable assets:
Domestic	$	7,580		$	1,542		$	16	$	927		$	563		$	10,628
Other		5			2			—		134			—			141

Total	$	7,585		$	1,544		$	16	$	1,061		$	563		$	10,769

Unconsolidated investments	$	290		$	78		$	—	$	—		$	—		$	368

Capital expenditures	$	(25	)	$	(13	)	$	—	$	—		$	(1	)	$	(39	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

Dynegy’s Segment Data for the Quarter Ended June 30, 2004

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	54		$	—		$	317		$	343		$	—		$	714
Other		—			—			—			(25	)		—			(25	)

		54			—			317			318			—			689
Intersegment revenues		359			—			7			(185	)		(181	)		—

Total revenues	$	413		$	—		$	324		$	133		$	(181	)	$	689

Depreciation and amortization	$	(47	)	$	—		$	—		$	—		$	(10	)	$	(57	)
Operating income (loss)	$	35		$	—		$	22		$	90		$	(91	)	$	56
Earnings from unconsolidated investments		50			—			—			—			—			50
Other items, net		—			—			—			(1	)		(8	)		(9	)
Interest expense																	(141	)

Loss from continuing operations before taxes																	(44	)
Income tax benefit																	29

Loss from continuing operations																	(15	)
Income from discontinued operations, net of taxes																	23

Net income																$	8

Identifiable assets:
Domestic	$	6,362		$	1,670		$	4,867		$	2,353		$	(2,199	)	$	13,053
Other		35			4			—			209			30			278

Total	$	6,397		$	1,674		$	4,867		$	2,562		$	(2,169	)	$	13,331

Unconsolidated investments	$	546		$	80		$	—		$	—		$	—		$	626

Capital expenditures	$	(44	)	$	(18	)	$	(33	)	$	—		$	(3	)	$	(98	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

Dynegy’s Segment Data for the Six Months Ended June 30, 2005

(in millions)


	GEN			NGL			REG		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	873		$	—		$	—	$	60		$	—		$	933
Other		30			—			—		(42	)		—			(12	)

		903			—			—		18			—			921
Intersegment revenues		(26	)		—			—		26			—			—

Total revenues	$	877		$	—		$	—	$	44		$	—		$	921

Depreciation and amortization	$	(97	)	$	—		$	—	$	(1	)	$	(11	)	$	(109	)
Operating income (loss)	$	79		$	—		$	—	$	(207	)	$	(321	)	$	(449	)
Earnings from unconsolidated investments		7			—			—		—			—			7
Other items, net		2			—			—		—			7			9
Interest expense																(185	)

Loss from continuing operations before taxes																(618	)
Income tax benefit																215

Loss from continuing operations																(403	)
Income from discontinued operations, net of taxes																179

Net loss															$	(224	)

Identifiable assets:
Domestic	$	7,580		$	1,542		$	16	$	927		$	563		$	10,628
Other		5			2			—		134			—			141

Total	$	7,585		$	1,544		$	16	$	1,061		$	563		$	10,769

Unconsolidated investments	$	290		$	78		$	—	$	—		$	—		$	368

Capital expenditures	$	(65	)	$	(23	)	$	—	$	—		$	(5	)	$	(93	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2005 and 2004

Dynegy’s Segment Data for the Six Months Ended June 30, 2004

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	100		$	—		$	769		$	654		$	—		$	1,523
Other		2			—			—			(69	)		—			(67	)

		102			—			769			585			—			1,456
Intersegment revenues		750			—			12			(423	)		(339	)		—

Total revenues	$	852		$	—		$	781		$	162		$	(339	)	$	1,456

Depreciation and amortization	$	(95	)	$	—		$	(10	)	$	—		$	(20	)	$	(125	)
Operating income (loss)	$	88		$	—		$	76		$	77		$	(145	)	$	96
Earnings from unconsolidated investments		88			—			—			—			—			88
Other items, net		—			—			1			2			3			6
Interest expense																	(271	)

Loss from continuing operations before taxes																	(81	)
Income tax benefit																	82

Income from continuing operations																	1
Income from discontinued operations, net of taxes																	77

Net income																$	78

Identifiable assets:
Domestic	$	6,362		$	1,670		$	4,867		$	2,353		$	(2,199	)	$	13,053
Other		35			4			—			209			30			278

Total	$	6,397		$	1,674		$	4,867		$	2,562		$	(2,169	)	$	13,331

Unconsolidated investments	$	546		$	80		$	—		$	—		$	—		$	626

Capital expenditures	$	(58	)	$	(27	)	$	(61	)	$	—		$	(5	)	$	(151	)

Note 15—Subsequent Events

On July 27, 2005, we received $100 million of funds held in escrow pursuant to the Baldwin consent decree. Please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Dispositions and Contract Terminations—Sale of Illinois Power.

In July 2005, we made a $75 million payment in connection with the settlement of the shareholder class action litigation and a $5 million payment in connection with the derivative litigation. Please see Note 10—Commitments and Contingencies—Shareholder Litigation for further discussion.

On August 2, 2005, we entered into an agreement to sell DMSLP, which comprises substantially all of the operations of our NGL segment. Please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion.

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 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

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 two 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.

Operational Highlights. We are a commodity-cyclical business and, as such, our core business results are affected by swings in commodity prices. The four most important regions that impact our power generation business are PJM, MISO, New York Zone G and New York Zone A. We believe prices in these regions will be our most indicative earnings drivers for the remainder of 2005. Pricing in each of these regions for the first six months of the year were higher than the same period last year, and although our volumes continue to be strong, they were slightly less than last year.

For our natural gas liquids business, the price of natural gas has the most impact on our earnings due to our upstream contract structure which is primarily POP and POL. Crude oil pricing is also an important indicator of earnings as natural gas liquids prices have historically moved directionally with crude prices. However, the current price relationship between crude oil and natural gas liquids has been less correlated, and natural gas liquids prices have not risen at the same rate as crude oil prices. Both natural gas and natural gas liquids prices remain strong year to date in 2005. Processing volumes are higher, fractionation volumes are lower and marketing volumes are lower than the same period last year.

Please read “—Results of Operations” for further discussion of the comparative results of our reportable business segments.

Restructuring Activities. We embarked on our self-restructuring strategy in late 2002. Since then, we have been engaged in a comprehensive self-restructuring process through which our top priorities were to refocus, repair and rebuild the company. We refocused around our two core business lines, power generation and natural gas liquids. We have worked to restore credibility and trust, and we restructured and eliminated many liabilities and risks facing the company.

During the first half of 2005, we achieved three critical accomplishments. Our acquisition of Sithe Energies in January 2005 achieved both sector growth and restructuring of a significant toll obligation by making it an intercompany agreement. Through this transaction, we acquired more than 1,000 MW of low heat rate efficient generation facilities. In addition to the power plants, we acquired a 750 MW firm capacity sales agreement with

Con Edison which runs through 2014. Over its term, this contract essentially offsets the principal and interest payments associated with the debt we assumed in this acquisition.

Second, we entered into a comprehensive settlement resolving the environmental litigation related to our Baldwin Energy Complex in Illinois. Under the terms of this settlement, we will undertake several emission control projects in the upcoming years, estimated to require an investment of approximately $320 million between now and 2010, and an additional investment of approximately $225 million in the 2011-2012 timeframe. When completed, these power plant modifications are expected to meet or exceed anticipated federal environmental requirements under the Clean Air Interstate Rules, as well as proposed legislation currently before Congress. The settlement also satisfied one of the conditions for the release of our remaining $100 million in sales proceeds held in escrow in connection with our sale of Illinois Power to Ameren, and we received such funds on July 27, 2005.

Finally, in April 2005, we reached a comprehensive settlement of the shareholder class action litigation. Under the terms of the settlement, which received final court approval in July 2005, we agreed to a total settlement consisting of (i) a $150 million payment to be covered by our directors and officers insurance policy, (ii) two cash payments totaling $250 million, which were made in May and July of 2005, and (iii) the delivery of 17,578,781 shares of our Class A common stock promptly following expiration of the appeal period, which occurred on August 8, 2005.

With these three accomplishments, our self-restructuring phase essentially came to a close, and we move into our strategic era.

Strategic Outlook. During our self-restructuring phase, our main focus was on eliminating liabilities, mitigating risks and preserving collateral, while rebuilding the company around two core businesses – power generation and natural gas liquids. Our new strategic era is one where the company is positioned for growth and focused on strategic alternatives for natural gas liquids and, in turn, power generation.

While the natural gas liquids business has played an integral role in our company’s financial recovery, after careful consideration, we have concluded that significant opportunities exist to realize even greater value through a sale. On August 2, 2005, we entered into an agreement to sell DMSLP, which comprises substantially all of the operations of our NGL segment. Please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion. We expect to net 95% of the cash proceeds from the sale of DMSLP, as the anticipated taxable gain will be largely offset by net operating losses and capital loss carry-forwards. This will provide us with opportunities to further de-lever our capital structure, which we believe will position us favorably in a potential power generation strategic combination or industry consolidation scenario.

While we believe that our power generation business is commercially sound, operationally focused, reliably run and very well managed, future growth is tied to greater scale and scope and a responsive pricing environment. Accordingly, we believe that growth through (i) independent organic transactions, (ii) opportunistic expansion or (iii) consolidation or strategic combination enabled by a more favorable net debt-to-capital ratio are the best ways to strengthen our business and deliver greater value to investors.

In the case of organic growth, we could continue to develop and expand our existing facilities. We have done this previously through the conversion of our Havana power generating facility to lower-cost and lower-emission PRB coal.

In the case of opportunistic expansion, we could explore opportunistic controlled expansion of our power generation business through calculated acquisitions designed to increase our market share, similar to our acquisition of Sithe Energies and its Northeast power generation assets earlier this year. We believe there are significant opportunities to profitably expand in our existing markets.

In the case of consolidation or strategic combination, we could seek to achieve greater scale and scope by engaging in strategic transactions with industry participants. We anticipate there will be an initial period of one-time transaction costs associated with combinations in the power sector. These integration costs will include, among other things, costs to exit existing business contracts, including building leases, service arrangements or customer obligations. However, we believe the synergies to be realized by participating in the consolidation of the power sector will exceed the initial integration costs. Combined organizations should benefit from economies of scale, which include cost efficiencies through combinations of back offices, as well as greater market share with geographic and fuel diversity.

Our ability to consummate the sale of DMSLP and utilize our tax loss carryforwards should position our power generation business for growth and attractively align it for anticipated 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. Accordingly, 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 second quarter 2005, we used cash on hand to reduce our outstanding debt as follows:

•

$17 million payment related to our Independence Senior Notes due 2007; and

•

$2 million 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 June 30, 2005, were approximately $5.1 billion. This includes the approximately $797 million of debt acquired with our 2005 acquisition of the Independence facility, which had a face value of $919 million at acquisition. Please see Note 2—Acquisition—Sithe Energies and Note 7—Debt—Independence Debt for further discussion of this transaction.

Under the terms of our credit facilities, in connection with the sale of DMSLP, we are required to use a portion of the proceeds of such sale to repay any borrowings under our revolving credit facility, a $594 million term loan and the $189 million generation facility debt. Following such repayments, our debt maturity profile will include $62 million in 2006, $40 million in 2007, $269 million in 2008, $57 million in 2009, $688 million in 2010 and $3,208 million thereafter.

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 August 4, 2005, June 30, 2005 and December 31, 2004:


	August 4, 2005		June 30, 2005		December 31, 2004
	(in millions)
By Segment:
GEN	$	235	$	203	$	192
CRM		68		68		94
NGL		220		230		167
REG		—		—		10
Other		8		8		7

Total	$	531	$	509	$	470

By Type:
Cash	$	209	$	216	$	376
Letters of Credit		322		293		94

Total	$	531	$	509	$	470

The increase in collateral postings since December 31, 2004 is primarily a result of a $53 million increase in postings for NGL. This increase is related to increases in commodity prices, as well as our transition from providing cash as collateral to providing letters of credit as collateral. At June 30, 2005, we had both cash and letters of credit outstanding for the same exposure, resulting in an over-collateralized balance of $33 million which will no longer be advanced by the end of August. In addition, the $43 million increase in GEN is primarily the 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. These items were offset by a $26 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 has been eliminated since December 31, 2004.

We have transitioned counterparty collateral demands from cash postings to letters of credit in order to replenish our cash balances after taking into account (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 and $80 million in July 2005 in connection with the settlement of the shareholder class action and derivative litigation. As of December 31, 2004, approximately 80% of the aggregate collateral posted (or approximately $376 million) consisted of cash, compared to approximately 42% cash collateral (or approximately $216 million) as of June 30, 2005 and 39% cash collateral (or approximately $209 million) as of August 4, 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, our anticipated sale of DMSLP prior to the end of 2005 and forward hedging transactions, we believe that collateral requirements will be approximately $275 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.

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—Acquisition—Sithe Energies and Note 7—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 June 30, 2005, the equipment leases have remaining terms from two to sixteen years and involve a maximum aggregate obligation of $131 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, exclusive of lease or interest costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of June 30, 2005 was approximately $287 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 may cause the facilities to operate at a net cash deficit.

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 are not consolidated by Dynegy for GAAP financial reporting purposes under the provisions of FIN No. 46R.

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

As further discussed in Note 7—Debt—Natural Gas Liquids, upon the sale of DMSLP, we are required to repay the priority lien debt comprised of the $594 million term loan scheduled to mature in 2010 and the $189 million generation facility debt scheduled to mature in 2007.

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 on common stock for the first half of 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. In July 2005, we declared a dividend of $11 million to be paid on or before August 11, 2005. 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. As a result, we may be required to defer payment of dividends on the Series C preferred stock beginning in February 2006.

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. Please see Note 7—Debt for further discussion of our revolving credit facility.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at August 4, 2005, June 30, 2005 and December 31, 2004:


	August 4, 2005			June 30, 2005			December 31, 2004
	(in millions)
Total revolver capacity	$	700		$	700		$	700
Outstanding letters of credit under revolving credit facility		(322	)		(293	)		(94	)

Unused revolver capacity		378			407			606
Cash		320	(1)(2)		358	(1)(2)		628	(1)(2)

Total available liquidity	$	698		$	765	(3)	$	1,234

(1)

The August 4, 2005, June 30, 2005 and December 31, 2004 amounts include approximately $31 million, $32 million and $47 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 August 4, 2005, June 30, 2005 and December 31, 2004 amounts include approximately $14 million, $16 million and $13 million, respectively, of cash held by our NGL business. See Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids.

(3)

The decrease in liquidity from December 31, 2004 to June 30, 2005 is primarily due to (i) cash paid for the Sithe acquisition of $120 million, net of cash acquired, (ii) our payment of $175 million in May 2005 in connection with the settlement of the shareholder class action litigation and (iii) capital expenditures of $93 million.

Cash Flows from Operations. We had operating cash outflows of $9 million in the six months ended June 30, 2005. This consisted of $372 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 $381 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 outflows of $43 to $33 million. This projection, which is subject to change based on a number of factors, many of which are beyond our control, reflects $725 to $730 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 $737 to $732 million in corporate-level expenses, including $435 million of interest.

Upon the anticipated sale of DMSLP, cash interest expense associated with the term loan and the generation facility debt will be eliminated, as these instruments will be repaid immediately. However, until the remaining cash proceeds from the sale are re-invested or utilized in a liability management program, as more fully described in Note 7—Debt—Natural Gas Liquids, the interest income from the cash proceeds will be more than offset by the reduced operating cash flows from the NGL business.

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, we entered into long-term rail transportation contracts and commodities contracts that will reduce our exposure to future changes in costs 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—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, excluding impairments of $85 million, totaled $165 million, approximately 70% of which was derived from the CDWR agreement. Cash distributions from this investment totaled $103 million in 2004. 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 August 4, 2005 and June 30, 2005, we had cash on hand of $320 million and $358 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 payments of $175 million in May 2005 and $80 million in July 2005 in connection with the settlement of the shareholder class action and derivative 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 $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 August 4, 2005, we had $322 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.

In connection with the sale of DMSLP, we anticipate amending or replacing our current revolving credit facility with a new, smaller facility that, when collateralized with cash, gives us the ability to post letters of credit. Please read Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion.

External Liquidity Sources

Over the last twelve months, our primary external liquidity source has been proceeds from asset sales. Looking forward, we expect our primary external liquidity sources to be proceeds from asset sales and other types of capital-raising transactions, including potential equity issuances.

Asset Sale Proceeds. On August 2, 2005, we entered into an agreement to sell DMSLP for an estimated $2.475 billion in cash proceeds. Please read Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion.

Upon repayment of the credit facility ($594 million scheduled to mature in 2010), we must also repay the generation facility ($189 scheduled to mature 2007). As of June 30, 2005, there were no borrowings outstanding under our $700 million revolving credit facility. We anticipate amending or replacing our current revolving credit facility with a new, smaller facility that, when collateralized with cash, gives us the ability to post letters of credit.

Under the terms of the SPNs, we can elect to use the balance of the proceeds to (i) repay parity lien debt, provided that any offer to repay parity lien debt holders is made on a pro rata basis, or (ii) make a capital expenditure or invest in various types of assets defined as Replacement Assets in the SPN indenture. Any net proceeds from a sale of DMSLP that are not applied or invested in the manner described above constitute Excess Proceeds. If Excess Proceeds exceed $50 million, we must within 365 days from the closing of the sale, offer to use the proceeds to repurchase the SPNs at par. Sales proceeds remaining after such an offer can be used for any purpose not otherwise restricted by the SPN indenture. We will evaluate alternative uses for the remaining proceeds from the transaction, such as reducing our outstanding debt or other obligations to further deleverage our capital structure to position our GEN business favorably in relation to future combination or consolidation opportunities.

In an effort to maximize our return on investment and to further clarify our business strategy, we have previously sold assets that we did 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, before consideration of interest savings, of approximately $15 million annually from such assets will no longer be offset by gains on sale.

Capital-Raising Transactions. As part of our ongoing efforts to move toward 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 will continue to consider 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 could 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 17,578,781 shares of Dynegy Class A common stock pursuant to the settlement of the shareholder class action litigation, as 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 remainder of 2005, we intend to continue to meet our customer and supplier commitments and operate our business safely, reliably and efficiently. We will maintain our focus on fiscal discipline and manage our costs and capital expenditures. We will continually review our portfolio to seek ways to improve our return on capital employed. We will continue to work toward a sustainable capital structure in line with our underlying business risks. Finally, we will consider fiscally responsible growth and sector consolidation opportunities that will add scale and scope to our business.

As previously indicated, our decision to sell DMSLP could positively impact the future of our power generation business. The sale of DMSLP will be a tax efficient sale, as tax benefits, including net operating losses and capital loss-carryforwards provide us with a large tax asset position. By utilizing these tax attributes to offset the gain from the sale of DMSLP, we maximize our after-tax proceeds.

The proceeds from the transaction will enable us to further improve our overall financial condition and liquidity position, as well as significantly lower our net debt-to-capital ratio. These benefits will position our power generation business with a more sustainable capital structure, stronger business platform and the flexibility to consider new strategic directions – be it either organic growth, growth through opportunistic expansion and/or participation in power sector consolidation or combination.

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 strategic direction(s) will be available to us, nor can we predict with any degree of certainty the impact of any such strategic direction(s) on our financial condition or results of operations. In the meantime, however, we intend to remain focused on meeting our customers’ energy services and supply needs in a safe, reliable and efficient manner.

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, the restructuring or termination of which likely would require a significant cash payment;

•

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

•

Our ability to consummate the agreed upon sale of DMSLP on the terms and in the timeframes anticipated;

•

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

•

Our ability to participate in growth opportunities in the power sector.

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

RESULTS OF OPERATIONS

Overview and Discussion of Comparability of Results. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three- and six-month periods ended June 30, 2005 and 2004. At the end of this section, we have included our business 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.

Three Months Ended June 30, 2005 and 2004

Summary Financial Information. The following tables provide summary financial data regarding our consolidated and segmented results of operations for the three-month periods ended June 30, 2005 and 2004, respectively:

Quarter Ended June 30, 2005


	GEN		NGL		REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	19	$	—	$	—	$	(15	)	$	(68	)	$	(64	)
Earnings from unconsolidated investments		4		—		—		—			—			4
Other items, net		2		—		—		(1	)		5			6
Interest expense														(96	)

Loss from continuing operations before taxes														(150	)
Income tax benefit														41

Loss from continuing operations														(109	)
Income from discontinued operations, net of taxes														147

Net income													$	38

Quarter Ended June 30, 2004


	GEN		NGL		REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	35	$	—	$	22	$	90		$	(91	)	$	56
Earnings from unconsolidated investments		50		—		—		—			—			50
Other items, net		—		—		—		(1	)		(8	)		(9	)
Interest expense														(141	)

Loss from continuing operations before taxes														(44	)
Income tax benefit														29

Loss from continuing operations														(15	)
Income from discontinued operations, net of taxes														23

Net income													$	8

The following table provides summary segmented operating statistics for the three months ended June 30, 2005 and 2004, respectively:


	Quarter Ended June 30,
	2005		2004
Power Generation
Million megawatt hours generated—gross		8.6		9.0
Million megawatt hours generated—net		8.3		8.6
Average natural gas price—Henry Hub ($/MMBtu) (1)	$	6.94	$	6.09
Average on-peak market power prices ($/MW hour)
Cinergy	$	54	$	45
NI Hub/ComEd	$	52	$	44
Southern	$	57	$	52
New York—Zone G	$	78	$	63
New York—Zone A	$	62	$	53
ERCOT	$	68	$	54
SP-15	$	55	$	55


	Quarter Ended June 30,
	2005		2004
Natural Gas Liquids
Gross NGL production (MBbls/d):
Field plants		58.0		56.1
Straddle plants		28.6		23.6

Total gross NGL production		86.6		79.7

Natural gas (residue) sales (Bbtu/d)		181.1		181.9

Natural gas inlet volumes (MMCFD):
Field plants		516.3		529.9
Straddle plants		1,212.5		785.1

Total natural gas inlet volumes		1,728.8		1,315.0

Fractionation volumes (MBbls/d)		176.6		213.1
Natural gas liquids sold (MBbls/d)		242.2		252.3
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	51.96	$	38.51
Natural gas—Henry Hub ($/MMBtu) (2)	$	6.74	$	6.00
Natural gas liquids ($/Gal)	$	0.79	$	0.64
Fractionation spread ($/MMBtu)—daily	$	1.97	$	1.15

Regulated Energy Delivery (3)
Electric sales in KWH (millions)
Residential		—		1,135
Commercial		—		1,118
Industrial		—		1,371
Transportation of customer-owned electricity		—		803
Other		—		90

Total electric sales		—		4,517

Gas sales in Therms (millions)
Residential		—		34
Commercial		—		16
Industrial		—		10
Transportation of customer-owned gas		—		56

Total gas delivered		—		116

Cooling degree days – actual (4)		—		373
Cooling degree days – 10-year rolling average		—		373
Heating degree days—actual (5)		—		388
Heating degree days—10-year rolling average		—		453

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

(5)	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 service area. 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 2005 and 2004 tax items, affecting net income for the periods presented.


	Quarter Ended June 30, 2005
	GEN		NGL		REG			CRM		Other			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—		$	—	$	(31	)	$	(31	)
Independence toll settlement adjustment		—		—		—			13		—			13
Discontinued operations		—		35		—			1		—			36
Taxes		—		—		—			—		112			112

Total	$	—	$	35	$	—		$	14	$	81		$	130


	Quarter Ended June 30, 2004
	GEN		NGL		REG			CRM		Other			Total
	(in millions)
Illinois Power asset impairment	$	—	$	—	$	(48	)	$	—	$	—		$	(48	)
Legal and settlement charges		—		—		1			—		(42	)		(41	)
Acceleration of financing costs		—		—		—			—		(14	)		(14	)
Taxes		—		—		—			—		(9	)		(9	)
Gas transportation contracts		—		—		—			88		—			88
Discontinued operations		—		70		—			1		—			71

Total	$	—	$	70	$	(47	)	$	89	$	(65	)	$	47

Operating Income/Loss

Operating loss was $64 million for the quarter ended June 30, 2005, compared to operating income of $56 million for the quarter ended June 30, 2004.

GEN. Operating income for our GEN segment was $19 million for the three months ended June 30, 2005, compared to $35 million for the three months ended June 30, 2004.

In the Midwest-MAIN region, where we produce approximately 60% of our generated volumes, results decreased $7 million year over year, from $100 million for the second quarter 2004 to $93 million for the second quarter 2005. Volumes were up 11%, from 4.8 million MWh for the second quarter 2004 to 5.4 million MWh for the second quarter 2005. Additionally, the Midwest region’s results for the second quarter 2005 include a $3 million benefit from mark-to-market income, primarily in connection with hedge ineffectiveness, compared with a mark-to-market loss of $1 million for the second quarter 2004. However, although energy consumed by AmerenIP was more than 35% higher in 2005’s second quarter than in 2004, incremental energy sold to AmerenIP under this power purchase agreement, that expires at the end of 2006, is priced significantly below current on-peak market prices. Additionally, operating expenses were up $2 million over the prior year, as a result of the timing of maintenance expense.

Earnings were also down in the Northeast region, where results declined from a loss of $3 million for the three months ended June 30, 2004 to a loss of $4 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—Acquisition—Sithe Energies for further discussion of the acquisition of Independence. For the second quarter of 2005, earnings for the Independence facility were $3 million. However, earnings at our existing Northeast facilities declined as a result of increased operating expense and decreased volumes at our Roseton facility. Volumes at Roseton decreased 0.4 million MWh, primarily due to compressed margins resulting from an increase in the price of fuel oil in relation to the price of generated power. Operating expense increased by $4 million at our existing facilities, primarily related to the timing of maintenance expense. Total volumes for the region inclusive of our

Independence facility were up slightly, from 1.4 million MWh in the second quarter 2004 to 1.5 million MWh for the same period in 2005, as additional volumes resulting from the acquisition of the Independence facility were largely offset by the decrease at the Roseton facility. The decrease in generated volumes and increase in operating expense was partially mitigated as average on-peak prices were up 24% in the market served by our Danskammer and Roseton facilities. Our Northeast results for the second quarter of 2005 include a mark-to-market charge of $2 million in connection with hedge ineffectiveness.

Results for our peaking facilities in the Midwest-ECAR region were improved by $3 million, from a loss of $1 million for the second quarter 2004 to earnings of $2 million for 2005. This improvement was a result of both favorable pricing and an increase in volumes. Results in our Southeast region decreased by $1 million, from earnings of $1 million for the second quarter 2004 to zero for 2005, as a result of decreased volumes. Results in our Texas region improved by $7 million, from a loss of $4 million for the second quarter 2004 to earnings of $3 million for the second quarter 2005. Earnings in the Texas Region during 2005 included a charge of $2 million related to hedge ineffectiveness. Although natural gas prices have remained high, power prices increased by 26% compared to 2004, resulting in improved spark spreads. Additionally, we were able to mitigate the negative impact of high gas prices by providing additional ancillary services to the market.

General and administrative expense increased from $14 million for the three months ended June 30, 2004 to $19 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, which we are in the process of closing. Depreciation expense increased from $47 million for the second quarter 2004 to $50 million for the second quarter 2005, primarily as a result of depreciation associated with the Independence facility acquired in 2005. Additionally, our 2005 results include a $7 million charge associated with the write-off of an environmental project.

GEN’s reported operating income for the three-month periods ended June 30, 2005 and 2004 also includes approximately $1 million and zero, respectively, of mark-to-market losses in addition to those discussed above, 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.

REG. Operating income for the REG segment was $22 million for the quarter ended June 30, 2004. We sold Illinois Power to Ameren on September 30, 2004. The 2004 period includes a $48 million charge related to an asset impairment at Illinois Power.

CRM. Operating loss for the CRM segment was $15 million for the quarter ended June 30, 2005, compared to operating income of $90 million in 2004.

In the second quarter 2005, we substantially completed the determination of the tax basis of the assets and liabilities acquired in connection with our purchase of Sithe Energies, and we do not expect any material changes to our purchase price allocation. 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 a $183 million charge recorded in the first quarter of 2005. In the second quarter of 2005, we revised the purchase price allocation, which resulted in a $13 million reduction of the charge recorded in the first quarter, resulting in a net charge of $170 million. Results for the second quarter 2005 reflect $22 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold, as well as net mark-to-market losses of $6 million on our legacy coal, gas and power positions.

2004 results included an $88 million gain related to our exit of four natural gas transportation contracts. In addition, results for the second quarter 2004 include $10 million in gains associated with the mark-to-market value of certain legacy gas contracts, which had previously been accounted for on an accrual basis. Additionally, our results include net mark-to-market-gains of $13 million on our legacy coal, gas and power positions. These

gains were partly offset by $22 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold.

Other. Other operating loss was $68 million for the quarter ended June 30, 2005, compared to a loss of $91 million for the quarter ended June 30, 2004. Results for 2005 include an $18 million charge associated with the recent settlement of our shareholder class action litigation and other legal and settlement charges totaling $13 million. For more information, please read Note 10—Commitment and Contingencies—Shareholder Litigation. Results for 2004 include approximately $42 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. In addition, 2005 results benefited from lower compensation, insurance and external consultant costs compared to the same period in 2004.

Earnings from Unconsolidated Investments

Our earnings from unconsolidated investments were approximately $4 million for the quarter ended June 30, 2005, compared to $50 million for the quarter ended June 30, 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 June 30, 2005, compared to $47 million for the same period in 2004. The decrease in earnings is primarily the result of the expiration of West Coast Power’s CDWR contract at the end of 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.

Other Items, Net

Other items, net, totaled $6 million of income for the quarter ended June 30, 2005, compared to an expense of $9 million for the quarter ended June 30, 2004. The increase is primarily a result of mark-to-market losses recognized in the second quarter 2004 associated with interest rate swaps as well as higher interest income in the second quarter 2005 due to higher interest rates.

Interest Expense

Interest expense totaled $96 million for the quarter ended June 30, 2005, compared to $141 million for the quarter ended June 30, 2004. The significant decrease is primarily attributable to the sale of Illinois Power in September 2004.

Income Tax Benefit

We reported an income tax benefit during the quarter ended June 30, 2005 of $41 million compared to $29 million for the quarter ended June 30, 2004. The income tax benefit in 2005 includes a $13 million expense, primarily related to an adjustment to the effective state rate and an increase to the valuation allowance. The income tax benefit in 2004 includes an $11 million benefit associated primarily with reducing a valuation allowance related to our capital loss carryforward. 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 these items, the 2005 and 2004 effective tax rates would be 36% and 41%, respectively. 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 NGL business in our NGL segment, our U.K. CRM business in our CRM segment and our communications business in Other and Eliminations. The following summarizes the activity included in income from discontinued operations:

Quarter Ended June 30, 2005


	U.K. CRM		DGC		NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	1	$	—	$	53		$	54
Earnings from unconsolidated investments included in income from discontinued operations		—		—		2			2
Other items, net included in income from discontinued operations		—		—		(6	)		(6	)
Interest expense included in income from discontinued operations									(14	)

Income from discontinued operations before taxes									36
Income tax benefit									111

Income from discontinued operations								$	147

Quarter Ended June 30, 2004


	U.K. CRM			DGC		NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	2		$	—	$	77		$	79
Earnings from unconsolidated investments included in income from discontinued operations		—			—		2			2
Other items, net included in income from discontinued operations		(1	)		—		(5	)		(6	)
Interest expense included in income from discontinued operations										(4	)

Income from discontinued operations before taxes										71
Income tax expense										(48	)

Income from discontinued operations									$	23

Income from discontinued operations before taxes. Income from discontinued operations before taxes was primarily driven by the results of operations of our NGL segment, which was reclassified to discontinued operations due to the anticipated sale of DMSLP. For further information regarding the sale, please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids.

Operating income for the NGL segment was $53 million for the quarter ended June 30, 2005, compared to $77 million in the quarter ended June 30, 2004. Operating income for the quarter ended June 30, 2004 included a $36 million gain associated with the sale of our financial interest in Indian Basin.

Gathering and processing operating results increased by $16 million for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004, primarily benefiting from 12% higher absolute commodity prices for natural gas and 23% higher absolute commodity prices for natural gas liquids year over year. At our field plants, results increased $13 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from higher prices. Operating results for the quarter ended June 30, 2004 included $2 million in operating margin from our Sherman plant, which was sold in November 2004. At our straddle plants, operating results increased $3 million, due largely to the impact of higher natural gas liquids prices under our POL contract settlements.

Results of our fractionation, storage and terminalling and transportation and logistics businesses decreased $4 million for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. Overall fractionation volumes decreased period over period due to the loss of a large fractionation customer at the end of September 2004 at our Cedar Bayou Fractionator. This was partially offset by increased fractionation volumes at our Lake Charles Fractionator caused by industry-wide increased liquids production in Louisiana primarily as a result of higher frac spreads.

Wholesale marketing results were $1 million unfavorable for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004, primarily as a result of the first quarter 2005 buyout of a refinery services contract. Higher natural gas liquids prices contributed higher earnings on our net back refinery services contracts.

NGL marketing services and distribution results decreased approximately $13 million for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. Although average natural gas liquids prices were higher in the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004, sharp declines in natural gas liquids prices during the quarter ended June 30, 2005 contributed to lower marketing margins. Further, although within acceptable measurement tolerances, natural gas liquids well losses also contributed to lower marketing margins during the quarter ended June 30, 2005. In addition, in the second quarter 2004, we terminated an inactive natural gas liquids sales contract which allowed us to recognize a $6 million gain on sales of natural gas liquids at current market prices previously held outside our normal inventory at historic below-current market prices.

Depreciation and amortization expense decreased $10 million for the quarter ended June 30, 2005 compared to the quarter ended June 30, 2004. We stopped depreciating our NGL assets on June 1, 2005, as they are classified as held for sale, which resulted in reduced depreciation of $7 million during the quarter ended June 30, 2005. In addition, depreciation expense in the quarter ended June 30, 2004 included a $6 million charge related to an adjustment to accumulated depreciation.

At both June 2005 and June 2004, we tested certain of our assets for impairment based on the identification of triggering events as defined by SFAS No. 144. After testing, we recorded a pre-tax impairment of $5 million for our Puckett gas treating plant and gathering system due to rapidly depleting reserves associated with that facility in the second quarter 2004. We concluded that no impairment was necessary for any of the other facilities in either period as estimated undiscounted cash flows exceeded facility book values.

Interest expense included in income from discontinued operations includes interest incurred on our $594 million Term Loan scheduled to mature in 2010 and our $189 million Generation facility debt scheduled to mature in 2007. In accordance with EITF Issue 87-24, “Allocation of Interest to Discontinued Operations,” we have allocated interest expense associated with these two debt instruments to discontinued operations, as they are required to be paid upon the sale of DMSLP. The increase in interest expense is due primarily to the Term Loan, which was entered into on May 28, 2004. As a result, 2004 results include one month of interest, compared to three months of interest in 2005.

Income tax benefit (expense) from discontinued operations. The income tax benefit in 2005 includes a $125 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of NNG. We reduced the valuation allowance related to our capital loss carryforward as a result of capital gains expected to be recognized from our anticipated sale of DMSLP. For further information regarding the sale, please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids. The income tax expense in 2004 includes $20 million in tax expenses related to the conclusion of prior year tax audits. Please see Note 13—Income Taxes—Prior Year Tax Audits for further discussion. Excluding these items, the 2005 and 2004 effective tax rates would be 37% and 39%, respectively. 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.

Six Months Ended June 30, 2005 and 2004

The following tables provide summary financial data regarding our consolidated and segmented results of operations for the six-month periods ended June 30, 2005 and 2004, respectively.

Six Months Ended June 30, 2005


	GEN		NGL		REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	79	$	—	$	—	$	(207	)	$	(321	)	$	(449	)
Earnings from unconsolidated investments		7		—		—		—			—			7
Other items, net		2		—		—		—			7			9
Interest expense														(185	)

Loss from continuing operations before taxes														(618	)
Income tax benefit														215

Loss from continuing operations														(403	)
Income from discontinued operations, net of taxes														179

Net loss													$	(224	)

Six Months Ended June 30, 2004


	GEN		NGL		REG		CRM		Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	88	$	—	$	76	$	77	$	(145	)	$	96
Earnings from unconsolidated investments		88		—		—		—		—			88
Other items, net		—		—		1		2		3			6
Interest expense													(271	)

Loss from continuing operations before taxes													(81	)
Income tax benefit													82

Income from continuing operations													1
Income from discontinued operations, net of taxes													77

Net income												$	78

The following table provides summary segmented operating statistics for the six months ended June 30, 2005 and 2004, respectively.


	Six Months Ended June 30,
	2005		2004
Power Generation
Million megawatt hours generated—gross		17.5		19.6
Million megawatt hours generated—net		16.7		18.7
Average natural gas price—Henry Hub ($/MMBtu) (1)	$	6.67	$	5.86
Average on-peak market power prices ($/MW hour)
Cinergy	$	52	$	43
NI Hub/Com Ed	$	50	$	42
Southern	$	53	$	47
New York—Zone G	$	74	$	63
New York—Zone A	$	60	$	55
ERCOT	$	60	$	49
SP-15	$	55	$	52


	Six Months Ended June 30,
	2005		2004
Natural Gas Liquids
Gross NGL production (MBbls/d):
Field plants		56.7		57.0
Straddle plants		29.7		23.8

Total gross NGL production		86.4		80.8

Natural gas (residue) sales (Bbtu/d)		182.6		182.4

Natural gas inlet volumes (MMCFD):
Field plants		517.2		551.3
Straddle plants		1,275.9		826.7

Total natural gas inlet volumes		1,793.1		1,378.0

Fractionation volumes (MBbls/d)		168.6		199.0
Natural gas liquids sold (MBbls/d)		268.2		276.9
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	49.96	$	36.64
Natural gas—Henry Hub ($/MMBtu) (2)	$	6.51	$	5.84
Natural gas liquids ($/Gal)	$	0.78	$	0.63
Fractionation spread ($/MMBtu)—daily	$	2.15	$	1.27

Regulated Energy Delivery (3)
Electric sales in KWH (millions)
Residential		—		2,590
Commercial		—		2,172
Industrial		—		2,691
Transportation of customer-owned electricity		—		1,432
Other		—		188

Total electric sales		—		9,073

Gas sales in Therms (millions)
Residential		—		194
Commercial		—		74
Industrial		—		29
Transportation of customer-owned gas		—		125

Total gas delivered		—		422

Cooling degree days—actual (4)		—		373
Cooling degree days—10-year rolling average		—		374
Heating degree days—actual (5)		—		3,096
Heating degree days—10-year rolling average		—		3,131

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

(5)	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 service area. 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 2005 and 2004 tax items, affecting net income (loss) for the periods presented.


	Six Months Ended June 30, 2005
	GEN		NGL		REG			CRM			Other			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—		$	—		$	(253	)	$	(253	)
Independence toll settlement charge		—		—		—			(170	)		—			(170	)
Discontinued operations		—		81		—			5			—			86
Taxes		—		—		—			—			125			125

Total	$	—	$	81	$	—		$	(165	)	$	(128	)	$	(212	)


	Six Months Ended June 30, 2004
	GEN		NGL		REG			CRM			Other			Total
	(in millions)
Legal and settlement charges	$	2	$	—	$	(1	)	$	—		$	(57	)	$	(56	)
Illinois Power goodwill impairment		—		—		(54	)		—			—			(54	)
Loss on anticipated sale of Illinois Power		—		—		(15	)		—			—			(15	)
Acceleration of financing costs		—		—		—			—			(14	)		(14	)
Discontinued operations		—		134		—			18			3			155
Gas transportation contracts		—		—		—			88			—			88
Taxes		—		—		—			—			30			30

Total	$	2	$	134	$	(70	)	$	106		$	(38	)	$	134

Operating Income/Loss

Operating loss was $449 million for the six months ended June 30, 2005, compared to operating income of $96 million for the six months ended June 30, 2004.

GEN. Operating income for our GEN segment was $79 million for the six months ended June 30, 2005, compared to $88 million for the six months ended June 30, 2004.

In the Midwest-MAIN region, results remained flat at $200 million for the first six months of 2004 and 2005. Although average on-peak prices increased from $42 per MWh for the first half of 2004 to $50 per MWh for the first half of 2005, a significant portion of our production was under contract, preventing us from realizing the full benefit of the increase in market prices. Volumes increased slightly, from 10.3 million MWh for the six months ended June 30, 2004 to 10.4 million MWh for the six months ended June 30, 2005. Our Midwest results for the six months ended June 30, 2005 include $3 million of mark-to-market income, compared with a loss of $2 million in the same period 2004.

Results for our peaking facilities in the Midwest-ECAR region were improved by $6 million, from a loss of $5 million for the six months ended June 30, 2004 to income of $1 million for 2005. This improvement was a result of both favorable pricing and an increase in volumes. Results in our Southeast region decreased slightly, from $1 million for the six months ended June 30, 2004 to zero for 2005. Results in our Texas region improved by $8 million, from a loss of $10 million for the six months ended June 30, 2004 to a loss of $2 million for the six months ended June 30, 2005. Although natural gas prices have remained high, power prices increased by 22% in the region. Further, we were able to partially mitigate the negative impact on earnings by providing additional ancillary services to the market. Our 2005 results for Texas include a charge of approximately $2 million related to hedge ineffectiveness.

Improved earnings in the Midwest and Texas regions were offset in the Northeast region, where results decreased from $17 million for the six months ended June 30, 2004 to $11 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—Acquisition—Sithe Energies for further discussion of the acquisition of Independence. Earnings associated with the Independence facility were $5 million for the six months ended June 30, 2005. However, these results were offset primarily as a result of increased operating expense and decreased volumes at our Roseton facility. Volumes at Roseton decreased 1.2 million MWh, primarily due to compressed margins resulting from an increase in the price of fuel oil in relation to the price of generated power. Operating expense increased by $8 million at our existing facilities, primarily related to maintenance at Roseton. Total volumes for the region, inclusive of our Independence facility, were down slightly, from 3.7 million MWh for the six months ended June 30, 2004 to 3.5 million 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 $8 million less revenue in the first six months of 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 17% in the market served by our Danskammer and Roseton facilities.

General and administrative expense increased from $28 million for the six months ended June 30, 2004 to $36 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, which we are in the process of shutting down. Depreciation expense increased from $95 million for the six months ended June 30, 2004 to $97 million for the six months ended June 30, 2005, primarily as a result of depreciation associated with the Independence facility acquired in 2005. Additionally, 2005 earnings include a $7 million charge related to the write-off of an environmental project.

GEN’s reported operating income for the six-month periods ended June 30, 2005 and 2004 also includes approximately $5 million of mark-to-market income in addition to that discussed above, 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.

REG. Operating income for the REG segment was $76 million for the six months ended June 30, 2004. The 2004 period includes a $15 million charge related to the sale of Illinois Power and a $54 million charge for the impairment of assets associated with this segment.

CRM. Operating loss for the CRM segment was $207 million for the six months ended June 30, 2005, compared to operating income of $77 million in 2004.

Results for 2005 were negatively impacted by a $170 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 $170 million charge upon completion of the acquisition. Results for 2005 also reflect $46 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold, and a net mark-to-market benefit of $11 million from our legacy gas, power and coal positions.

2004 results included an $88 million gain related to our exit of four natural gas transportation contracts. In addition, 2004 results include $10 million in gains associated with the mark-to-market value of certain legacy gas contracts, which had previously been accounted for on an accrual basis. Results also include mark-to-market gains of $44 million associated with our legacy gas, power and coal positions, and $6 million of income from our Canadian business. These gains were partly offset by the $70 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold.

Other. Other operating loss was $321 million for the six months ended June 30, 2005, compared to a loss of $145 million for the six months ended June 30, 2004. Results for 2005 include a $240 million charge associated with the recent settlement of our shareholder class action litigation and other legal settlement charges totaling $13 million. For more information, please read Note 10—Commitment and Contingencies—Shareholder Litigation. Results for 2004 include approximately $57 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. In addition, 2005 results benefited from lower compensation, insurance and external consultant costs compared to the same period in 2004.

Earnings from Unconsolidated Investments

Our earnings from unconsolidated investments were approximately $7 million for the six months ended June 30, 2005, compared to $88 million for the same period 2004. Our West Coast Power investment was the primary driver of the decrease. Total earnings from this investment were approximately $2 million for the six months ended June 30, 2005, compared to $82 million for 2004. The decrease in earnings is primarily the result of the expiration of West Coast Power’s CDWR contract at the end of 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.

Other Items, Net

Other items, net totaled $9 million for the six months ended June 30, 2005, compared to $6 million for the six months ended June 30, 2004. The increase is primarily associated with higher interest income in 2005 due to higher interest rates.

Interest Expense

Interest expense totaled $185 million for the six months ended June 30, 2005, compared to $271 million for the six months ended June 30, 2004. The significant decrease is primarily attributable to the sale of Illinois Power in September 2004.

Income Tax Benefit

We reported an income tax benefit during the six months ended June 30, 2005 of $215 million compared to a benefit of $82 million for the six months ended June 30, 2004. The 2005 effective tax rate was 35%, compared to 101% in 2004. The 2004 tax benefit includes a $47 million benefit related to a reduction in a deferred tax capital losses valuation allowance associated with anticipated gains on asset sales and a $3 million benefit related to the release of reserves upon the conclusion of prior year tax audits. Please read Note 13—Income Taxes for further discussion. Excluding these items from the 2004 calculation would result in an effective tax rate of 40%. 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 basis differences.

Discontinued Operations


Six Months Ended June 30, 2005

	U.K. CRM			DGC		NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	6		$	—	$	112		$	118
Earnings from unconsolidated investments included in income from discontinued operations		—			—		4			4
Other items, net included in income from discontinued operations		(1	)		—		(10	)		(11	)
Interest expense included in income from discontinued operations										(25	)

Income from discontinued operations before taxes										86
Income tax benefit										93

Income from discontinued operations									$	179


Six Months Ended June 30, 2004

	U.K. CRM			DGC		NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	3		$	—	$	145		$	148
Earnings from unconsolidated investments included in income from discontinued operations		—			—		4			4
Other items, net included in income from discontinued operations		15			3		(9	)		9
Interest expense included in income from discontinued operations										(6	)

Income from discontinued operations before taxes										155
Income tax expense										(78	)

Income from discontinued operations									$	77

Operating income for the NGL segment was $112 million for the six months ended June 30, 2005, compared to $145 million for the six months ended June 30, 2004. Operating income for the six months ended June 30, 2004 included pre-tax gains of $17 million and $36 million, respectively, from our Hackberry LNG and Indian Basin sales.

Excluding the Hackberry and Indian Basin gains, the significant improvement in operating income was driven by natural gas, crude oil and natural gas liquids prices, which increased dramatically year over year. The first half of 2005 was marked by continued high run times experienced across our facilities.

Gathering and processing operating results increased by $27 million for the six months ended June 30, 2005 compared to the six months ended June 30, 2004, primarily benefiting from 11% higher absolute commodity prices for natural gas and 24% higher absolute commodity prices for natural gas liquids year over year. At our

field plants, results increased $20 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from higher prices. Operating results for the six months ended June 30, 2004 included $6 million in operating margin from our Indian Basin and Sherman plants, which were sold in April 2004 and November 2004, respectively. At our straddle plants, operating results increased $7 million, due largely to the impact of higher natural gas liquids prices under our POL contract settlements.

Results of our fractionation, storage and terminalling and transportation and logistics businesses decreased $5 million for the six months ended June 30, 2005 compared to the six months ended June 30, 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. This was partially offset by increased fractionation volumes at our Lake Charles Fractionator caused by industry-wide increased liquids production primarily as a result of higher frac spreads. Natural gas liquids storage and transportation operations’ operating results increased period over period, partially offsetting fractionation impacts.

Wholesale marketing results were $3 million unfavorable for the six months ended June 30, 2005 compared to the six months ended June 30, 2004, primarily as a result of milder than usual weather and the first quarter buyout of a refinery services contract. Higher natural gas liquids prices contributed higher earnings on our net back refinery services contracts.

NGL marketing services and distribution results decreased approximately $11 million for the six months ended June 30, 2005 compared to the six months ended June 30, 2004. Although average natural gas liquids prices were higher during the six months ended June 30, 2005 compared to the six months ended June 30, 2004, sharp declines in natural gas liquids prices during the six months ended June 30, 2005 contributed to lower marketing margins. Further, although within acceptable measurement tolerances, natural gas liquids well losses also contributed to lower marketing margins during the six months ended June 30, 2005. In addition, during the six months ended June 30, 2004, we terminated an inactive natural gas liquids sales contract and reevaluated liquid pipelines contractual requirements which allowed us to recognize a $9 million gain on sales of natural gas liquids at current market prices previously held outside our normal inventory at historic below-current market prices.

Depreciation and amortization expense decreased $10 million for the six months ended June 30, 2005 compared to the six months ended June 30, 2004. We stopped depreciating our NGL assets on June 1, 2005, as they are classified as held for sale, which resulted in reduced depreciation of $7 million during the six months ended June 30, 2005. In addition, depreciation expense in the six months ended June 30, 2004 included a $6 million charge related to an adjustment to accumulated depreciation.

In June 2005 and June 2004, we tested certain of our assets for impairment based on the identification of triggering events as defined by SFAS No. 144. After testing, we recorded a pre-tax impairment of $5 million for our Puckett gas treating plant and gathering system due to rapidly depleting reserves associated with that facility in second quarter 2004. We concluded that no impairment was necessary for any of the other facilities in either period as estimated undiscounted cash flows exceeded facility book values.

During 2005, U.K. CRM recognized $5 million of pre-tax income primarily associated with the receipt of a third-party bankruptcy settlement. During 2004, U.K. CRM recognized $17 million of translation gains on the repatriation of cash from the U.K. Also during 2004, DGC recognized $3 million of pre-tax income associated with the receipt from a third party of a prior contractual claim.

which was entered into on May 28, 2004. As a result, 2004 results include one month of interest, compared to six months of interest in 2005.

Income tax benefit (expense) from discontinued operations. The income tax benefit in 2005 includes a $125 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of NNG. We reduced the valuation allowance related to our capital loss carryforward as a result of capital gains expected to be recognized from our anticipated sale of DMSLP. For further information regarding the sale, please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids. The income tax expense in 2004 includes $20 million in tax expenses related to the conclusion of prior year tax audits. Please see Note 13—Income Taxes—Prior Year Tax Audits for further discussion. Excluding these items, the 2005 and 2004 effective tax rates would both be 37%. 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.

Outlook

The following summarizes our outlook 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 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.

Power Generation benefited from the operation of substantially all of our peaking plants during the second quarter 2005. During the first six months of 2005, our peaking plants have generated more electricity than they did throughout all of 2004. We believe this increase is attributable to increased demand as well as market design changes including MISO implementation.

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, had been our largest contributor to earnings from unconsolidated investments prior to 2005. 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 AmerenIP with expected volumes comparable to the former agreement. Under the terms of this agreement, effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48 per kW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. Under this 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.

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 R.L. 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—Acquisition—Sithe Energies for further discussion of this transaction.

NGL Outlook. Financial results for our NGL segment are impacted by natural gas and natural gas liquids prices, as well as the frac spread. Provided that a strong pricing environment continues throughout 2005, our upstream contract settlements under POP and POL contracts will continue to benefit.

The effects of the NGL segment on our consolidated results of operations will be significantly impacted by our ability to consummate the anticipated sale of DMSLP, as well as the timing of such sale. Please read Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion of this anticipated transaction.

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—Acquisition—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 expired by its terms in July 2005.

Our Sterlington tolling arrangement remains in place through 2017. We are open to 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 table includes 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 income from discontinued operations, net of taxes, in our unaudited condensed consolidated statements of operations:


	GEN		NGL		REG		CRM			Other and Eliminations			Consolidated
	(in millions)
For the six months ended June 30, 2005	$	194	$	178	$	—	$	41		$	(422	)	$	(9	)

For the six months ended June 30, 2004	$	200	$	170	$	181	$	(182	)	$	(308	)	$	61

Operating Cash Flow. Our cash flow used in operations totaled $9 million for the six months ended June 30, 2005. During the period, our GEN, NGL and CRM segments provided positive cash flow from operations. GEN provided cash flow from operations of $194 million, and NGL provided cash flow from operations of $178 million primarily due to positive earnings for the period as well as the return of cash collateral. Our CRM segment provided cash flow of approximately $41 million in cash primarily due to the return of cash collateral offset by fixed payments associated with the power tolling arrangements and our final payment of $26 million related to our exit from gas transportation contracts. Other and Eliminations includes a use of approximately $422 million in cash primarily due to our payment of $175 million in May 2005 in connection with the settlement of the shareholder class action litigation, interest payments to service debt and general and administrative expenses.

Our cash flow provided by operations totaled $61 million for the six months ended June 30, 2004. During the period, our GEN, NGL and REG segments provided positive cash flow from operations. GEN provided cash flow from operations of $200 million due primarily to positive earnings for the period, partially offset by increased cash collateral posted in lieu of letters of credit; NGL provided cash flow from operations of $170 million due primarily to positive earnings and seasonality of the wholesale business for the period; and REG provided cash flow from operations of $181 million due primarily to positive earnings for the period and the withdrawals of gas in storage. Our CRM segment used approximately $182 million in cash due primarily to fixed payments associated with the power tolling arrangements and related gas transportation agreements, increased cash collateral posted in lieu of letters of credit and our exit from four long-term natural gas transportation contracts. Other and eliminations includes a use of approximately $308 million in cash due primarily to interest payments to service debt, settlement payments and general and administrative expenses.

Capital Expenditures and Investing Activities. Cash used in investing activities during the six months ended June 30, 2005 totaled $218 million. Capital spending of $93 million was primarily comprised of $65 million and $23 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 six months ended June 30, 2004 totaled $70 million. Capital spending of $151 million was comprised primarily of $58 million, $27 million and $61 million in the GEN, NGL and REG segments, respectively. The capital spending for our GEN segment related primarily to maintenance capital projects. Capital spending in our NGL segment related primarily to maintenance capital projects and wellconnects, as well as approximately $5 million on a gathering system expansion. Capital spending in our REG segment related primarily to projects intended to maintain system reliability and new business services. Proceeds from asset sales included primarily $17 million in proceeds from the sale of our remaining financial interest in the Hackberry LNG project, $48 million from the sale of Indian Basin, $9 million from the sale of PESA 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 six months ended June 30, 2005 totaled $43 million. Repayments of long-term debt totaled $38 million for the six months ended June 30, 2005 and consisted of the following: (i) payments of $18 million on a maturing series of DHI senior notes; (ii) payments of $17 million on the Independence Senior Notes due 2007 and (iii) payments of $3 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.

Net cash provided by financing activities during the six months ended June 30, 2004 totaled $370 million. The cash provided was due primarily to proceeds from a new $600 million secured term loan, net of issuance costs of $19 million, which was offset partially by repayments of long-term debt. Repayments of long-term debt totaled $193 million for the six months ended June 30, 2004 and consisted of the following: (i) payments of $95 million on a maturing series of Illinova senior notes; (ii) payments of $43 million on Illinois Power’s transitional funding trust notes; (iii) payments of $39 million under our ABG Gas Supply financing and (iv) payments of $16 million on the junior notes. Net cash provided by financing activities was also offset by 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 Six Months Ended June 30, 2005
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2005	$	(133	)
Risk-management losses recognized through the income statement in the period, net		(2	)
Cash paid related to risk-management contracts settled in the period, net		18
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		32

Fair value of portfolio at June 30, 2005	$	(85	)

Income Statement Reconciliation
Risk-management losses recognized through the income statement in the period, net	$	(2	)
Physical business recognized through the income statement in the period, net (3)		(154	)
Non-cash adjustments and other		4

Net recognized operating loss	$	(152	)

Cash Flow Statement
Cash paid related to risk-management contracts settled in the period, net	$	(18	)
Estimated cash paid related to physical business settled in the period, net (3)		(154	)
Timing and other, net (4)		19

Cash paid during the period	$	(153	)

Risk-Management cash flow adjustment for the quarter ended June 30, 2005 (5)	$	(1	)

(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 $170 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 $85 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 June 30, 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)
June 30, 2005 (2)	$	(30	)	$	7		$	15		$	(39	)	$	(12	)	$	(4	)	$	3
December 31, 2004		(96	)		(7	)		(8	)		(48	)		(21	)		(10	)		(2	)

Increase (4)	$	66		$	14		$	23		$	9		$	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 June 30, 2005 of $85 million on the unaudited condensed consolidated balance sheets include the $30 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 June 30, 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 July 1 to December 31, 2005 values in the June 30, 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 Assets


	Six Months Ended June 30, 2005		Six Months Ended December 31, 2005		Total 2005			2006			2007			2008			2009			Thereafter
	(in millions)
June 30, 2005 (1)	$	1	$	7	$	8		$	17		$	(41	)	$	(14	)	$	(5	)	$	4
December 31, 2004						(5	)		(7	)		(51	)		(23	)		(12	)		(1	)

Increase (2)					$	13		$	24		$	10		$	9		$	7		$	5

(1)

The cash flow values for 2005 reflect realized cash flows for the six months ended June 30, 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 matters involving the western power and natural gas markets, master netting agreement matters, and the investigations primarily relating to past trading practices;

•

the effects of the Sithe Energies acquisition;

•

consummation of the agreed upon sale of DMSLP;

•

positioning GEN for future growth; 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;

•

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

•

our ability to achieve tax and capital structure objectives associated with, our receipt of required regulatory approvals for, the satisfaction of other conditions precedent to the consummation of, and the effects on our financial condition of, the agreed upon sale of DMSLP;

•

the availability of, and our ability to participate in, organic growth, controlled expansion, or consolidation or combination opportunities for our power generation business, and the impact of any such opportunities on our financial condition and results of operations;

•

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

•

the impact on our financial condition of payments and stock issuances required by the settlement agreement, approved July 2005, relating to the shareholder class action litigation;

•

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, 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 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, increase the environmental compliance cost for our facilities, or 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 June 30, 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 June 30, 2005 is significantly lower than that reported for December 31, 2004 due to the acquisition and consolidation of ExRes, the parent company of Sithe Energies and Independence, 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 June 30, 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	$	163	$	—	$	163
Commercial/Industrial/End Users		55		26		81
Utility and Power Generators		5		—		5
Oil and Gas Producers		5		—		5

Total	$	228	$	26	$	254

Of the $26 million in credit exposure to non-investment grade counterparties, approximately 85% 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 June 30, 2005, our fixed rate debt instruments as a percentage of total debt instruments was approximately 76%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of June 30, 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 June 30, 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 June 30, 2005 and December 31, 2004, respectively:

Notional Contract Amounts


	June 30, 2005		December 31, 2004
Natural Gas (Trillion Cubic Feet)		0.724		1.084
Electricity (Million Megawatt Hours)		25.452		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 second 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 second 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 June 30, 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 related to our tax accounting and tax reconciliation process, procedures and controls, in preparing our financial statements at and for the three- and six-month periods ended June 30, 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.

Status of 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 Control Over Financial Reporting. 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 10 to the accompanying unaudited condensed consolidated financial statements for discussion of the material legal proceedings to which we are a party.

Item 4—SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Our 2005 annual meeting of the shareholders was held on May 19, 2005. The purpose of the annual meeting was to consider and vote upon the following proposals:

To elect eleven Class A common stock directors and two Class B common stock directors to serve until the 2006 annual meeting of shareholders;

To act upon a proposal to change our state of incorporation from Illinois to Delaware by merging Dynegy with and into Dynegy Inc., a Delaware corporation and wholly owned subsidiary of Dynegy which we refer to as “Merger Sub,” pursuant to the Agreement and Plan of Merger between Dynegy and Merger Sub;

To act upon a proposal to ratify the appointment of PricewaterhouseCoopers LLP as our independent auditors for the fiscal year ending December 31, 2005; and

To consider and act upon the one shareholder proposal described below.

Our Board of Directors is comprised of thirteen members. At the annual meeting, each of the following individuals was elected to serve as one of our directors: Charles E. Bayless, David W. Biegler, Linda Walker Bynoe, Thomas D. Clark, Jr., Barry J. Galt, Patricia A. Hammick, George L. Mazanec, Robert C. Oelkers, Howard B. Sheppard, Joe J. Stewart, William L. Trubeck, Raymond I. Wilcox and Bruce A. Williamson. The votes cast for each nominee and the votes withheld were as follows:

Class A Directors


		FOR	WITHHELD
1.	Charles E. Bayless	238,108,632	22,060,869
2.	David W. Biegler	241,168,483	18,791,634
3.	Linda Walker Bynoe	238,243,195	21,717,078
4.	Thomas D. Clark, Jr.	248,756,152	11,206,745
5.	Barry J. Galt	195,961,775	63,995,247
6.	Patricia A. Hammick	238,406,091	21,559,296
7.	George L. Mazanec	240,932,970	19,046,451
8.	Robert C. Oelkers	238,395,155	21,566,135
9.	Joe J. Stewart	248,753,108	11,206,890
10.	William L. Trubeck	238,469,612	21,488,895
11.	Bruce A. Williamson	248,757,471	11,870,466

Class B Directors

The following votes were cast with respect to the proposal to change our state of incorporation from Illinois to Delaware by merging Dynegy with and into Dynegy Inc., a Delaware corporation and wholly owned subsidiary of Dynegy, which we refer to as “Merger Sub,” pursuant to the Agreement and Plan of Merger between Dynegy and Merger Sub. There were 97,483,358 broker non-votes. This proposal failed to pass even though more than 90% of the votes were cast in favor of the proposal, as the proposal failed to receive a sufficient number of total votes by the holders of Class A common stock to satisfy the two-thirds super-majority required under Illinois law.

Class A Common Stock


FOR	AGAINST	ABSTAIN
149,091,630	10,239,755	3,227,290

Class B Common Stock


FOR	AGAINST	ABSTAIN
96,891,014	0	0

Series C Convertible Preferred Stock


FOR	AGAINST	ABSTAIN
8,000,000	0	0

The following votes were cast with respect to the ratification of the selection of PricewaterhouseCoopers LLP as our independent auditors for the fiscal year ended December 31, 2005. There were no broker non-votes. This proposal was approved by the shareholders.


FOR	AGAINST	ABSTAIN
351,009,510	2,921,200	3,002,337

The following votes were cast with respect to the shareholder proposal requesting that the Board of Directors adopt a policy that, in the event of a restatement of financial results, we would recoup compensation received by senior executives for achieving performance targets to the extent such performance targets were not achieved. There were 98,483,358 broker non-votes. This shareholder proposal failed to pass.


FOR	AGAINST	ABSTAIN
80,785,022	173,493,467	5,171,200

Item 6—EXHIBITS

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


10.1		Dynegy Inc. Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.2		First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.3		Dynegy Inc. Executive Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.4		Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated November 20, 2003 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.5		First Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.5 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.6		Baldwin Consent Decree approved May 27, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2005, File No. 1-15659).

10.7		Director Compensation Summary (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 24, 2005, File No. 1-15659).

10.8		Stipulation of Settlement dated May 2, 2005 (Shareholder Class Action Litigation) (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

10.9		Stipulation of Settlement dated April 29, 2005 (Shareholder Derivative Litigation) (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

+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: August 9, 2005	By:	/s/ NICK J. CARUSO
		Nick J. Caruso Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

EXHIBIT INDEX

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


10.1		Dynegy Inc. Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.2		First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.3		Dynegy Inc. Executive Severance Pay Plan as amended and restated effective as of February 1, 2005 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.4		Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated November 20, 2003 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.5		First Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated June 22, 2005 (incorporated by reference to Exhibit 99.5 to the Current Report on Form 8-K of Dynegy Inc. filed on June 28, 2005, File No. 1-15659).

10.6		Baldwin Consent Decree approved May 27, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2005, File No. 1-15659).

10.7		Director Compensation Summary (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 24, 2005, File No. 1-15659).

10.8		Stipulation of Settlement dated May 2, 2005 (Shareholder Class Action Litigation) (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

10.9		Stipulation of Settlement dated April 29, 2005 (Shareholder Derivative Litigation) (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).

+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.