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 September 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: 000-29311

DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)

Delaware	94-3248415
(State of incorporation)	(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 ¨  No x

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

All of the registrant’s outstanding common stock is owned, directly or indirectly, by Dynegy Inc.

DYNEGY HOLDINGS INC.

TABLE OF CONTENTS

			Page
PART I. FINANCIAL INFORMATION
	Item 1.	CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited):
	Condensed Consolidated Balance Sheets: September 30, 2005 and December 31, 2004		4
	Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2005 and 2004		5
	Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2005 and 2004		6
	Condensed Consolidated Statements of Comprehensive Income (Loss): For the three and nine months ended September 30, 2005 and 2004		7
	Notes to Condensed Consolidated Financial Statements		8
	Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	39
	Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	69
	Item 4.	CONTROLS AND PROCEDURES	70
PART II. OTHER INFORMATION
	Item 1.	LEGAL PROCEEDINGS	72
	Item 6.	EXHIBITS	72

2

DEFINITIONS

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

ARB	Accounting Research Bulletin
ARO	Asset retirement obligation
Cal ISO	The California Independent System Operator
CDWR	California Department of Water Resources
CFTC	Commodity Futures Trading Commission
CPUC	California Public Utilities Commission
CRM	Our customer risk management business segment
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
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
PJM	PJM Interconnection, LLC
POL	Percentage of liquids
POP	Percentage of proceeds
PRB	Powder River Basin coal
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
VESCO	Venice Energy Services Company, LLC
VIE	Variable Interest Entity

3

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)

	September 30, 2005			December 31, 2004
ASSETS
Current Assets
Cash and cash equivalents	$	101		$	245
Accounts receivable, net of allowance for doubtful accounts of $154 and $169, respectively		596			804
Accounts receivable, affiliates		931			859
Inventory		160			233
Assets from risk-management activities		1,264			565
Deferred income taxes		542			73
Prepayments and other current assets		198			303
Assets held for sale (Note 2)		518			—
Total Current Assets		4,310			3,082
Property, Plant and Equipment		6,127			7,822
Accumulated depreciation		(1,128	)		(1,692	)
Property, Plant and Equipment, Net		4,999			6,130
Other Assets
Unconsolidated investments		286			414
Assets from risk-management activities		340			313
Goodwill		—			15
Deferred income taxes		13			12
Other long-term assets		157			192
Assets held for sale (Note 2)		1,171			—
Total Assets	$	11,276		$	10,158
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	458		$	555
Accounts payable, affiliates		16			23
Accrued interest		76			113
Accrued liabilities and other current liabilities		260			432
Liabilities from risk-management activities		1,328			616
Notes payable and current portion of long-term debt		36			34
Notes payable affiliate		270			—
Liabilities held for sale (Note 2)		251			—
Total Current Liabilities		2,695			1,773
Long-term debt		3,864			3,907
Long-term debt to affiliates		200			200
Long-Term Debt		4,064			4,107
Other Liabilities
Liabilities from risk-management activities		355			395
Deferred income taxes		814			462
Other long-term liabilities		292			317
Liabilities held for sale (Note 2)		19			—
Total Liabilities		8,239			7,054
Minority Interest		107			106
Commitments and Contingencies (Note 8)
Stockholder’s equity
Capital Stock, $1 par value, 1,000 shares authorized at September 30, 2005 and December 31, 2004, respectively		—			—
Additional paid-in capital		2,413			2,413
Accumulated other comprehensive loss, net of tax		(28	)		(13	)
Accumulated deficit		(487	)		(434	)
Stockholder’s equity		1,032			1,032
Total Stockholder’s Equity		2,930			2,998
Total Liabilities and Stockholder’s Equity	$	11,276		$	10,158

See the notes to condensed consolidated financial statements.

4

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
Revenues	$	735		$	405		$	1,525		$	1,322
Cost of sales, exclusive of depreciation shown separately below		(472	)		(300	)		(1,103	)		(933	)
Depreciation and amortization expense		(54	)		(57	)		(158	)		(172	)
Impairment and other charges		—			(2	)		1			(24	)
Loss on sale of assets, net		(2	)		(1	)		(2	)		(1	)
General and administrative expenses		(78	)		(61	)		(320	)		(187	)
Operating income (loss)		129			(16	)		(57	)		5
Earnings from unconsolidated investments		5			23			10			110
Interest expense		(79	)		(75	)		(229	)		(259	)
Other income and expense, net		(4	)		—			(4	)		6
Minority interest expense		—			(4	)		—			(4	)
Income (loss) from continuing operations before income taxes		51			(72	)		(280	)		(142	)
Income tax benefit (expense) (Note 11)		(16	)		28			96			61
Income (loss) from continuing operations		35			(44	)		(184	)		(81	)
Income from discontinued operations, net of tax expense of $26, $24, $24 and $101, respectively (Note 2)		43			36			131			111
Net income (loss)	$	78		$	(8	)	$	(53	)	$	30

See the notes to condensed consolidated financial statements.

5

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Nine Months Ended September 30,
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(53	)	$	30
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		204			265
Impairment and other charges		(1	)		29
Earnings from unconsolidated investments, net of cash distributions		51			(5	)
Risk-management activities		(96	)		(24	)
Gain on sale of assets		(8	)		(52	)
Deferred income taxes		(74	)		39
Liability associated with gas transportation contracts (Note 2)		—			(148	)
Other		3			(5	)
Changes in working capital:
Accounts receivable		(183	)		137
Inventory		(13	)		(58	)
Prepayments and other assets		106			(128	)
Accounts payable and accrued liabilities		(103	)		(123	)
Changes in non-current assets		(4	)		(26	)
Changes in non-current liabilities		8			7
Net cash used in operating activities		(163	)		(62	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(132	)		(129	)
Proceeds from asset sales, net		11			197
Affiliate transactions		194			(218	)
Net cash provided by (used in) investing activities		73			(150	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		—			588
Repayments of long-term borrowings		(23	)		(265	)
Other financing, net		(13	)		(23	)
Net cash provided by (used in) financing activities		(36	)		300
Effect of exchange rate changes on cash		—			(1	)
Net increase (decrease) in cash and cash equivalents		(126	)		87
Cash and cash equivalents, beginning of period		245			328
Less: Cash classified as held for sale at end of period (Note 2)		(18	)		—
Cash and cash equivalents, end of period	$	101		$	415

See the notes to condensed consolidated financial statements.

6

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended September 30,
	2005			2004
Net income (loss)	$	78		$	(8	)
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net		(60	)		(4	)
Reclassification of mark-to-market losses to earnings, net		50			4
Changes in cash flow hedging activities, net (net of tax benefit of $5 and zero, respectively)		(10	)		—
Foreign currency translation adjustments		5			3
Minimum pension liability (net of tax expense of zero and $7, respectively)		—			(12	)
Other comprehensive loss, net of tax		(5	)		(9	)
Comprehensive income (loss)	$	73		$	(17	)

	Nine Months Ended September 30,
	2005			2004
Net income (loss)	$	(53	)	$	30
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net		(81	)		(57	)
Reclassification of mark-to-market losses to earnings, net		61			24
Changes in cash flow hedging activities, net (net of tax benefit of $12 and $20, respectively)		(20	)		(33	)
Foreign currency translation adjustments		5			(12	)
Minimum pension liability (net of tax expense of zero and $7, respectively)		—			(12	)
Other comprehensive loss, net of tax		(15	)		(57	)
Comprehensive loss	$	(68	)	$	(27	)

See the notes to condensed consolidated financial statements.

7

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 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. These adjustments are of a normal and recurring nature. 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 nine months ended September 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 September 30, 2005, our ARO liabilities were $38 million for our GEN segment and $10 million for our NGL segment. In anticipation of our sale of DMSLP, the $10 million of ARO liabilities associated with our NGL segment have been reclassified to liabilities held for sale. We sold DMSLP to Targa Resources, Inc. and two of its subsidiaries on October 31, 2005. Please see Note 2—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion of the sale.

Employee Stock Options. In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” and provides alternative methods of transition (prospective, modified prospective or retroactive) for entities that voluntarily change to the fair value-based method of accounting for stock-based employee compensation in a fiscal year beginning before December 16, 2003. SFAS No. 148 requires prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to

8

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

stock-based employee compensation. We transitioned to a fair value-based method of accounting for stock-based compensation on 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 by Dynegy after January 1, 2003 are accounted for on a fair value basis. Options granted by Dynegy prior to January 1, 2003 continue to be accounted for using the intrinsic value method. Accordingly, for options granted by Dynegy 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. Dynegy has granted in-the-money options in the past, and we have recognized compensation expense over the applicable vesting periods. No in-the-money stock options have been granted by Dynegy 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) would have approximated the following pro forma amounts for the three- and nine-month periods ended September 30, 2005 and 2004, respectively.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions, except per share data)
Net income (loss) as reported	$	78		$	(8	)	$	(53	)	$	30
Add: Stock-based employee compensation expense included in reported net income (loss), net of related tax effects		3			1			5			3
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(3	)		(4	)		(5	)		(13	)
Pro forma net income (loss)	$	78		$	(11	)	$	(53	)	$	20

Accounting Principles Adopted

FIN No. 46(R). In the fourth quarter 2003, we adopted the initial provisions of FIN No. 46(R), “Consolidation of Variable Interest Entities—An Interpretation of ARB No. 51.” FIN No. 46(R) was effective on December 31, 2003 for entities considered SPEs. We adopted the remaining provisions of FIN No. 46(R) 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. 46(R). With respect to each of the VIEs we identified, we assessed whether we were the “primary beneficiary,” as defined by FIN No. 46(R). 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. 46(R) 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 two generation facilities, one in Illinois and the other in 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, respectively. Total net generating capacity for these facilities totals 165 MW and 902 MW, respectively. As a result of various contractual arrangements into which these entities have entered, we have concluded that they are both VIEs. As we do not absorb a majority of the

9

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

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 $270 million at September 30, 2005, and one of our affiliates has a loan outstanding to one of these entities, which totaled $19 million at September 30, 2005. As a result, our maximum exposure to loss from these entities was $289 million at September 30, 2005.

In July 2001, we entered into several agreements, including a power tolling agreement, a financial derivative instrument, an energy management agreement and a natural gas supply agreement, with Sithe/Independence Power Partners, L.P., which we refer to as “Independence” and which owns and operates a 1,021 MW combined cycle gas-fired power generation facility near Scriba, New York. We had previously been unable to assess whether the entity was a VIE, but have subsequently received the necessary financial and contractual information related to the entity. As a result of various contractual arrangements into which this entity has entered, we have concluded that it is a VIE. However, as we do not absorb a majority of the expected losses or receive a majority of expected residual returns, we are not considered the primary beneficiary of the entity. Our future obligations under these agreements, which represent our maximum exposure to loss, are approximately $698 million. On January 31, 2005, Dynegy completed the acquisition of ExRes SHC, Inc., or “ExRes,” the parent company of Sithe Energies, Inc., which we refer to as “Sithe Energies,” and Independence. Please see Note 7—Related Party Transactions for further discussion regarding this acquisition.

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, under SFAS No. 148 we previously adopted the prospective method of transition 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 defines a conditional ARO as an ARO 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. 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 for fiscal years ending after December 15, 2005. We will adopt FIN No. 47 on December 31, 2005 and are in the process of evaluating the impact of this guidance.

Note 2— Discontinued Operations, Dispositions and Contract Terminations

Discontinued Operations

Natural Gas Liquids. On October 31, 2005, we consummated the sale of DMSLP, which comprised substantially all of the operations of our NGL segment, to Targa Resources Inc. and two of its subsidiaries, which

10

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

we refer to as “Targa”, for $2.445 billion in cash. At closing we received $2.35 billion in cash proceeds. Targa assumed responsibility for approximately $47 million in letters of credit provided by us for the benefit of DMSLP, with the replacement of those letters of credit to occur within 90 days following the closing. By December 31, 2005, we expect to receive payment of a substantial majority of the balance of the sales proceeds from Targa which represents our cash collateral related to DMSLP. The total amount of cash collateral, approximately $95 million, is lower than our August 2, 2005 estimate of $125 million primarily as a result of less cash collateral posted due to the business interruptions caused by the recent Gulf Coast hurricanes. Please see Note 6—Debt—DMSLP for a discussion of the permitted use of proceeds.

In the second quarter 2005, NGL met the held for sale classification requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”. As of September 30, 2005, NGL continued to meet the held for sale requirements, 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 September 30, 2005 are as follows (in millions):

Current Assets:
Cash	$	18
Accounts receivable, net of allowance for doubtful accounts of $2		395
Inventory		92
Other		13
Total Current Assets	$	518
Long-Term Assets:
Property, plant and equipment, net	$	1,076
Unconsolidated investments		77
Goodwill		15
Other		3
Total Long-Term Assets	$	1,171
Current Liabilities:
Accounts payable	$	151
Other		100
Total Current Liabilities	$	251
Long-Term Liabilities:
Other		19
Total Long-Term Liabilities	$	19

Additionally, the $107 million in minority interest at September 30, 2005 related to NGL will not be included in our unaudited condensed consolidated balance sheets subsequent to the sale. As a result of the sale of DMSLP to Targa, our expected realization of certain deferred tax assets has been accelerated. For further discussion, please see Note 11—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 $2 million and $37 million in the three- and nine-month periods ended September 30, 2005, compared to $21 million and $66 million in the three- and nine-month periods ended September 30, 2004.

11

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 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 sale less liabilities held for sale, we did not recognize a loss in the third quarter 2005. Also, during the second quarter, as a result of the anticipated sale of DMSLP, we reduced the valuation allowance on our deferred tax asset. For further discussion, please see Note 11—Income Taxes—Capital Loss Valuation Allowance. We recorded a pre-tax gain of approximately $1.1 billion ($700 million after-tax), subject to post-closing adjustments, 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 term loan scheduled to mature in 2010 and our generation facility debt scheduled to mature in 2007 has been allocated to discontinued operations, as the respective debt instruments were required to be paid upon the sale of DMSLP. Such interest expense, inclusive of amortization of debt issuance costs, totaled $15 million and $10 million for the three months ended September 30, 2005 and 2004, respectively, and $40 million and $16 million for the nine months ended September 30, 2005 and 2004, respectively.

Additionally, results from NGL’s operations include revenues and cost of sales arising from intersegment transactions, which, other than the short term arrangement described below, 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.

In conjunction with the sale of DMSLP, certain natural gas sales and purchase agreements between DMSLP and CRM were extended through November 30, 2005. Under these agreements, which until the sale were intersegment agreements, CRM purchases natural gas from DMSLP field processing plants or sells natural gas for use as fuel or plant thermal reduction (PTR) replacement in certain of DMSLP’s fractionation and non-operated Gulf Coast processing facilities. DMSLP has agreed to pay CRM essentially all costs it incurs in the sale, procurement and provisioning of natural gas under these agreements.

Pursuant to a Master Gas Processing Agreement, DMSLP has the right, subject to several conditions, to process any of Chevron’s future gas production in the lower 48 continental United States that is not already included within the committed areas of the existing processing agreements. In August 2005, Chevron provided DMSLP with written notice of termination of this Master Gas Processing Agreement effective as of the expiration of the 10-year primary term, which is August 31, 2006. After that date, DMSLP will no longer have a preferential right to process any gas attributable to future production by Chevron. The termination of the Master Gas Processing Agreement does not modify Chevron’s obligations under the existing gas processing agreements with DMSLP.

Other. We sold or liquidated some of our operations during 2003, including our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.

12

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

The following table summarizes information related to all of our discontinued operations, including the NGL operations discussed above:

	U.K. CRM			NGL		Total
	(in millions)
Three Months Ended September 30, 2005
Revenue	$	—		$	1,193	$	1,193
Income from operations before taxes		(2	)		71		69
Income from operations after taxes		(3	)		46		43
Three Months Ended September 30, 2004
Revenue	$	—		$	996	$	996
Income from operations before taxes		(1	)		61		60
Income (loss) from operations after taxes		(2	)		38		36
Nine Months Ended September 30, 2005
Revenue	$	—		$	3,172	$	3,172
Income from operations before taxes		3			152		155
Income from operations after taxes		—			131		131
Nine Months Ended September 30, 2004
Revenue	$	—		$	2,663	$	2,663
Income from operations before taxes		17			195		212
Income (loss) from operations after taxes		(9	)		120		111

In the nine months ending September 30, 2005, we recognized $3 million of pre-tax income primarily associated with U.K. CRM’s receipt of a third party bankruptcy settlement, offset by foreign exchange losses.

In the first quarter 2004, we recognized $17 million of pre-tax income related to translation gains on foreign currency in the U.K. Please see Note 4—Risk Management Activities and Accumulated Other Comprehensive Loss—Net Investment Hedges in Foreign Operations for further discussion. 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 11—Income Taxes—Prior Year Tax Audits for further discussion.

Dispositions and Contract Terminations

Hackberry LNG Project. During the first quarter 2003, we entered into an agreement to sell our ownership interest in Hackberry LNG Terminal LLC, the entity we formed in connection with our proposed LNG terminal/gasification project in Hackberry, Louisiana, to Sempra LNG Corp., a subsidiary of San Diego-based Sempra Energy. The transaction closed in April 2003, after which we received contingent payments in 2003 based upon project development milestones. In March 2004, we sold our remaining financial interest in this project, which 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.

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

13

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

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 3—Restructuring Charges

In the nine months ended September 30, 2004, we recorded a $5 million pre-tax charge related to the impairment of one 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	$	23		$	26
2005 adjustments to liability		—		(1	)		(1	)
Cash payments		—		(6	)		(6	)
Balance at September 30, 2005	$	3	$	16		$	19

We expect the $16 million accrual as of September 30, 2005 associated with cancellation fees and operating leases to be paid by the end of 2007 when the leases expire.

Note 4—Risk Management Activities and Accumulated Other Comprehensive Loss

The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in an attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more fully described in Note 5—Risk Management Activities and Financial Instruments beginning on page F-26 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 nine months ended September 30, 2005, we recorded $10 million and $4 million of income, 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. The hedge ineffectiveness is the result of the volatility of power and gas prices in the regions in which we hedge our power sales and fuel purchases. During the three and nine months ended September 30, 2004, we recorded a $3 million charge related to ineffectiveness from changes in fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows. During the three and nine months

14

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

ended September 30, 2005 and September 30, 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 September 30, 2005 is expected to be reclassified to future earnings, contemporaneously with the related purchases of fuel, sales of electricity and payments of interest, as applicable to each type of hedge. Of this amount, after-tax losses of approximately $40 million are currently estimated to be reclassified into earnings over the 12-month period ending September 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 nine months ended September 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 nine months ended September 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 September 30, 2005, we had no net investment hedges in place.

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

	September 30, 2005			December 31, 2004
	(in millions)
Cash flow hedging activities, net	$	(36	)	$	(16	)
Foreign currency translation adjustment		21			16
Minimum pension liability		(13	)		(13	)
Accumulated other comprehensive loss, net of tax	$	(28	)	$	(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 stockholder’s equity.

15

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

Note 5—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:

	September 30, 2005			December 31, 2004
	(in millions)
Equity affiliates:
GEN investments	$	286		$	336
NGL investments		77			78
Total equity affiliates		363			414
Less: Unconsolidated investments held for sale at end of period		(77	)		—
Total unconsolidated investments	$	286		$	414

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

	Nine Months Ended September 30,
	2005				2004
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	219	$	110	$	538	$	269
Operating income		8		4		246		123
Net income		12		6		247		123

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

	Nine Months Ended September 30,
	2005				2004
	Total		Equity Share		Total		Equity Share
	(in millions)
Revenues	$	242	$	78	$	434	$	179
Operating income		42		17		99		44
Net income		43		17		75		33

Earnings from unconsolidated investments of $10 million for the nine months ended September 30, 2005, include the $17 million above and $6 million from West Coast Power, offset by an $8 million impairment of our investment in West Coast Power and $5 million of earnings from NGL investments which are included in income from discontinued operations. Earnings from unconsolidated investments of $110 million for the nine months ended September 30, 2004, include the $33 million above, $123 million from West Coast Power, our equity investment in Oyster Creek and our equity investment in Hartwell of $15 million and $2 million, respectively. These gains were partially offset by a $45 million impairment of our investment in West Coast Power, an $8 million impairment of our Michigan Power equity investment discussed below, $3 million of amortization of the difference between the cost of our unconsolidated investments and our underlying equity in their net assets and $7 million of earnings from NGL investments, which are included in income from discontinued operations.

16

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

In the third quarter 2004, we sold our unconsolidated investments in the Oyster Creek, Michigan Power and Hartwell generating facilities for aggregate net cash proceeds of approximately $132 million. During the third quarter 2004, we recognized gains of $15 million and $2 million related to our sales of Oyster Creek and Hartwell, but did not recognize any gain or loss on the sale of Michigan Power. However, during the nine months ended September 30, 2004, we recorded an impairment on our investment in Michigan Power totaling $8 million, to adjust our book value to the sale price.

Additionally, in September 2004, we recorded an impairment of $45 million on our investment in West Coast Power, primarily due to the anticipated expiration of the CDWR contract in December 2004.

Note 6—Debt

Revolving Credit Facility. During the three and nine-month periods ended September 30, 2005, we increased letters of credit under our $700 million revolving credit facility by $32 million and $231 million, respectively, in the aggregate, resulting in a total of $325 million outstanding at September 30, 2005. As of September 30, 2005, there were no borrowings outstanding under this facility.

Our former credit facility consisted of a $700 million revolving credit facility and a $600 million term loan (scheduled to mature in 2010) which had $593 million outstanding at September 30, 2005. On October 31, 2005, we repaid the $593 million outstanding on our term loan as well as $189 million outstanding on our generation facility (scheduled to mature in 2007), and as further described below, we amended and restated the credit facility.

DMSLP. As further discussed in Note 2—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids, on October 31, 2005, we consummated the sale of DMSLP. The terms of our former $1.3 billion credit facility and the SPN indenture and security agreements govern the use of the proceeds from this sale.

According to the SPN indenture, we may use the proceeds of the sale of DMSLP to (i) repay and permanently reduce first lien capacity, (ii) repay parity lien debt, provided that any offer to repay parity lien debt holders is made on a pro rata basis or (iii) make a capital expenditure or invest in various type of assets defined as Replacement Assets.

In accordance with the SPN indenture, on November 10, 2005, we made a $1.75 billion Asset Sale Offer to purchase, with the net cash proceeds from the sale of DMSLP, SPNs from the holders thereof at a price equal to 100% of the principal amount plus accrued and unpaid interest. Under the terms of the SPN indenture, “Excess Proceeds” from the sale of DMSLP are approximately $2.39 billion, and to the extent not used for the repurchase of the SPNs, may be used by us for any purpose not otherwise prohibited under the SPN indenture.

Amended and Restated Credit Facility. On October 31, 2005, we replaced our former $1.3 billion credit facility with a second amended and restated credit agreement (the “Amended and Restated Credit Facility”), comprised of (i) a $400 million letter of credit component and (ii) a $600 million revolving credit component. The Amended and Restated Credit Facility is collateralized with cash as well as other assets that were pledged under the former credit facility (excluding those assets sold in connection with the sale of DMSLP) as we are required to post cash collateral in an amount equal to 103% of outstanding letters of credit and borrowings under the Amended and Restated Credit Facility. We will earn interest income on the cash on deposit in the cash collateral account.

A letter of credit fee is payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 0.50% of the undrawn amount. We also incur additional fees for issuing letters of credit. Amounts drawn on letters of credit issued pursuant to the facility, as well as borrowings under the revolving credit component

17

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

of the facility, bear interest at a base rate plus 0.50% per annum. An unused commitment fee of 0.10% is payable on the unused portion of the Amended and Restated Credit Facility.

On October 31, 2005, we borrowed $600 million under the revolving credit component of the Amended and Restated Credit Facility to repay the term loan and accrued interest associated with the former credit facility. The $600 million outstanding principal balance of the revolving credit component was paid in full on November 1, 2005 without a corresponding reduction in revolving credit commitments.

Repayments. In the nine months ended September 30, 2005, we paid the outstanding $18 million balance on our 8.125% senior notes, which matured in March 2005. We also made payments of $5 million related to our term loan during the first nine months of 2005.

On October 31, 2005, as mentioned above, we repaid the $593 million term loan and with cash-on-hand the $189 million generation facility debt.

Transactions With Affiliates. In the first quarter 2005, we received $50 million from Dynegy to fund our operational needs in exchange for a promissory note due April 2005. We paid this note in full, including interest, in April 2005.

In the third quarter, we received $270 million from Dynegy to fund our operational needs in exchange for promissory notes due in the fourth quarter 2005.

Note 7—Related Party Transactions

We routinely engage in business transactions with subsidiaries of Dynegy that are not part of our consolidated group. These transactions included among others, purchases of energy and capacity from Independence, as further discussed below. Please see Note 12—Related Party Transactions—Other beginning on page F-39 of our Form 10-K for further discussion. Additionally, we engage in transactions with Chevron Corporation, which we refer to as “Chevron,” and its affiliates, including purchases and sales of natural gas and natural gas liquids, which we believe are executed on terms that are fair and reasonable. Please see Note 12—Related Party Transactions—Transactions with ChevronTexaco beginning on page F-38 of our Form 10-K for further discussion.

On January 31, 2005, Dynegy completed the acquisition of ExRes. In exchange for $120 million, net of transaction costs and cash acquired, and the assumption of $919 million of face value project debt, Dynegy 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. Independence holds a power tolling contract, financial swap and other contracts with one of our subsidiaries. Upon completion of this acquisition, our transactions with Independence became related party transactions.

Our transactions with ExRes include purchases of energy and capacity under a tolling arrangement and payments associated with a financial derivative instrument. During the periods from February 1, 2005 through September 30, 2005 and the three months ended September 30, 2005, we incurred costs of $58 million and $98 million, respectively, under these contracts. Additionally, during the periods from February 1, 2005 through September 30, 2005 and the three months ended September 30, 2005, we sold an aggregate of $152 million and $71 million, respectively, in natural gas to ExRes. The terms of these transactions are in accordance with the contractual agreements that were in place prior to Dynegy’s acquisition of ExRes. In addition to the contractual arrangements discussed above, we pay all employee and payroll costs, as well as certain general and administrative costs, on behalf of ExRes, and they reimburse us for these costs. For the periods from February 1, 2005 through September 30, 2005 and the three months ended September 30, 2005, we paid $14 million and $3 million, respectively, of such costs on behalf of ExRes. During the period ended September 30, 2005, we received a payment of $6 million

18

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

from ExRes in order to terminate their obligation to post collateral with us. As of September 30, 2005, we have a net outstanding affiliate receivable balance of $46 million from ExRes.

Note 8—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-10 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-Q for the quarter ended June 30, 2005:

• In July 2005, the U.S. district court approved the comprehensive settlement agreement of the parties in Dynegy’s shareholder class action litigation. Pursuant to the settlement agreement, we and Dynegy made an aggregate settlement payment of $468 million (consisting of $150 million funded by insurance proceeds, two cash payments by us totaling $250 million and the issuance of 17,578,781 shares of Class A common stock by Dynegy). Further, the lead plaintiff agreed to submit a list of at least five qualified director candidates from which Dynegy will select two new members for its Board of Directors to replace two directors who were defendants in the litigation.

• Also in July 2005, the state district court approved Dynegy’s settlement of the shareholder derivative litigation. Under this settlement, Dynegy paid approximately $5 million in attorneys’ fees and expenses and agreed to effect certain corporate governance changes, many of which were previously implemented since the initiation of the litigation.

• In September 2005, two former Illinois Power salaried employees who were participants in the DMG Salaried Plan, purporting to represent all DMG Salaried Plan participants who held Dynegy common stock through the DMG Salaried Plan during the period from January 1, 2002 through January 30, 2003,

19

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

filed a lawsuit in federal court in the Southern District of Texas against us and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG Salaried Plan.

• In September and October 2005, two California Superior Courts granted motions to dismiss certain California market litigation based upon federal preemption.

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 and Dynegy settled a class action lawsuit filed on behalf of purchasers of Dynegy’s 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 Dynegy and certain of Dynegy’s current and former officers and directors violated the federal securities laws in connection with disclosures, including accounting disclosures, regarding Project Alpha (a structured natural gas transaction entered into by Dynegy 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 Dynegy’s 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 Dynegy’s 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 Dynegy’s 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 and us of $468 million, comprised of a $150 million cash payment funded by insurance proceeds, a $250 million cash payment by us, and the issuance by Dynegy 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. The appeal period for the litigation expired on August 8, 2005, and, as required by the settlement, Dynegy issued the shares of Class A common stock promptly thereafter, on August 12, 2005.

• The lead plaintiff agreed to submit a list of at least five qualified director candidates from which Dynegy will select two new members for its Board of Directors to replace two directors who were defendants in

20

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

the litigation. Dynegy will also nominate such directors for election at its next meeting of shareholders at which directors are elected.

In addition, Dynegy was named as a nominal defendant in several derivative lawsuits brought by shareholders on Dynegy’s behalf against certain of its former officers and current and former directors whose claims are 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 Dynegy’s 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 had been 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.

We, Dynegy and the other defendants, in the case of the shareholder class action litigation, and Dynegy and the other defendants, in the case of the shareholder derivative litigation 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 zero and $154 million ($111 after-tax) in the three and nine months ended September 30, 2005 and $9 million ($6 million after-tax) and $40 million ($25 million after-tax) in the three and nine months ended September 30, 2004, related to these settlements and associated legal expenses. The net pre-tax charges are reflected in general and administrative expenses on our unaudited condensed consolidated statements of operations.

ERISA/Illinois Power 401(k) Litigation. In January 2005, three DMG union 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 Dynegy, 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 by Dynegy in December 2004, including claims that certain of Dynegy’s former and current officers (who are past and present members of its 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 Dynegy’s 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. Dynegy’s motion to transfer this litigation to the Southern District of Texas was denied in October 2005. However, Dynegy’s motion to dismiss remains pending before the court. Although it is not possible to predict with certainty whether we will incur any liability in connection with this lawsuit, we do not believe that any liability we might incur as a result of this lawsuit would have a material adverse effect on our financial condition, results of operations or cash flows.

Additionally, in September 2005, two former Illinois Power salaried employees who were participants in the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for salaried employees (formerly known as the Illinois Power Incentive Savings Plan), which we refer to as the “DMG Salaried Plan,” purporting to represent all DMG Salaried Plan participants who held Dynegy common stock through the DMG Salaried Plan during the period from January 1, 2002 though January 30, 2003, filed a lawsuit in federal court in the Southern District of Texas against Dynegy and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG Salaried Plan that are similar to the claims made in the ERISA litigation Dynegy settled in December 2004 and the ERISA

21

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

litigation referenced in the preceding paragraph, including claims that certain of Dynegy’s former and current officers (who are past and present members of its 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 Dynegy’s 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. Dynegy is preparing its response to the complaint. Although it is not possible to predict with certainty whether we will incur any liability in connection with this lawsuit, we do not believe that any liability we might incur as a result of this lawsuit would have a material adverse effect on our financial condition, results of operations or cash flows.

Enron/NNG VEBA Litigation. Prior to Dynegy’s 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 for bankruptcy in December 2001. When Dynegy acquired NNG in January 2002, the assets of the Enron VEBA had not been distributed to its participant companies, though Dynegy and NNG made the appropriate requests for such a distribution. In July 2002, Dynegy 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 Dynegy’s sale of NNG to Mid American Energy Holdings Company, NNG established a separate VEBA trust solely for its plan participants (the “NNG VEBA”). As a condition of the sale agreement, Dynegy 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 Dynegy’s escrowed funds into the NNG VEBA. Pursuant to the escrow agreement, once the Enron VEBA releases NNG’s funds to the NNG VEBA, Dynegy 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. At the same time the class action was filed, NNG filed a motion in Enron’s bankruptcy case contesting Enron’s efforts to terminate its VEBA trust and to distribute the assets in a manner unacceptable to NNG. The Nebraska litigation and the dispute in the Enron bankruptcy case remain pending. As we have a receivable recorded to reflect our rights to this disputed distribution, an adverse outcome in this matter would impact Dynegy, even though they are not a party; however, 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 expected to cost an 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

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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.

On July 14, 2000 and March 28, 2002, the EPA requested information, which we provided, concerning maintenance, repair and replacement activities at our Danskammer and Roseton plants, respectively. 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.

California Market Litigation. We and/or Dynegy 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 five coordinated cases were remanded to a California state court, and in May 2005, defendants filed a motion to dismiss. The court granted defendants’ motion to dismiss in October 2005 on grounds of federal preemption.

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/ Dynegy 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 coordinated 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. In September 2005, the court granted defendants’ motion to dismiss on grounds of federal preemption.

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(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

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 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 five 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. Both cases remain pending.

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 we and/or 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 cannot predict their outcome.

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DYNEGY HOLDINGS INC.

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For the Interim Periods Ended September 30, 2005 and 2004

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 Dynegy 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 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 commenced 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. Dynegy’s former CFO, Rob Doty, filed for arbitration pursuant to the terms of his employment/severance agreement. Mr. Doty seeks payment of up to approximately $3.4 million and additional amounts related to long-term incentive payments. A status conference on this matter is scheduled for the fourth quarter 2005. Mr. Doty’s agreement is subject to interpretation, and we maintain that the amount owed is substantially lower than the amount sought. We have 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

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(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

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. The parties attended mediation in February 2005, but did not reach a settlement. The parties have filed briefs with the Texas Court of Appeals. Any liability associated with this suit was assumed by Targa in accordance with the terms of the sale of DMSLP.

Gas Index Pricing Litigation. We and/or Dynegy 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); 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/or Dynegy 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.

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 and in October 2005 the defendants filed answers to the plaintiffs’ complaints. 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. In April 2005 we appealed the decision to the Alabama Supreme Court, and we are awaiting a decision on this appeal.

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

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(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

plaintiffs earlier in the year. In October 2005, the court granted plaintiffs’ motion and certified the class. 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 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. Reserves have been provided in connection with this litigation.

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. The case was removed to West Virginia federal court shortly thereafter. 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, federal 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 motions by certain defendants (including us) to dismiss all federal antitrust claims on statute of limitations grounds, however, the Court later denied our motion to dismiss for lack of personal jurisdiction. In September 2005, defendants filed their answers to plaintiffs’ Second Amended Complaint. Although defendants sought permission from the Fourth Circuit to appeal the district court’s denial of summary judgment on filed rate and preemption grounds, the Fourth Circuit denied the request in October 2005. We continue to analyze plaintiffs’ state antitrust and unjust enrichment claims against the Company 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.

Alleged Marketing Contract Defaults. We have posted collateral to support a portion of our obligations in our CRM business. 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 and have never been late in payments to these counterparties, we previously received a notice of default in 2002 from each such counterparty 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

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(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

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 Investigation–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 Dynegy’s 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 superseding indictment was returned in July 2005, recharging the original violations and adding additional charges. The trial date is set for Spring 2006.

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 activities in the California energy markets in November 2002. Dynegy continues 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 maintained by Dynegy and its ERISA affiliates. Dynegy 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, Dynegy received a letter from the Department of Labor indicating that, as a result of Dynegy’s 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.

Danos Litigation. In late September 2005, Mr. Timothy Danos filed a class action lawsuit in Louisiana federal district court on behalf of himself and similarly situated commercial fisherman against several defendants, including VESCO, seeking actual and punitive damages as a result of the alleged discharge of oil by the defendants in connection with Hurricane Katrina. We had a majority ownership interest in VESCO prior to the DMSLP sale. Plaintiff alleges that VESCO released approximately 25,000 gallons of oil into portions of Louisiana’s coastal regions. VESCO has not yet been served with this litigation. Any liability associated with this suit was assumed by Targa in accordance with the terms of the sale of DMSLP.

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

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limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, 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 million, $857 million and $28 million 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, various Canadian assets, Michigan Power, Oyster Creek, Hartwell, Commonwealth, Sherman and Indian Basin. 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. Upon entering into this contract, we established a liability of $0.3 million reflecting the fair value of this guarantee. During the three and nine months ended September 30, 2005, we increased the liability by $0.2 million and $0.8 million, respectively, as it became probable that we will be obligated to make a greater payment to Constellation under the guarantee.

During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa against losses it may incur under indemnifications DMSLP provided to purchasers of Hackberry and certain other assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their value to be insignificant.

Note 9—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 and 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 (the former plant 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

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DYNEGY HOLDINGS INC.

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(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

until final action is taken on the renewal application. In April 2005, the NYSDEC issued to DNE a draft SPDES Permit (the “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 manage actively 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. Currently, the 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 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 oppose those claims vigorously. Given the high 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 State Pollutant Discharge Elimination System Permit. Danskammer’s SPDES Permit was issued for a five-year term in 1987. Prior to the expiration of the permit, Central Hudson Gas & Electric (the former plant owner), filed an application to renew the SPDES Permit. We believe that application was timely and sufficient. 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 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 SPDES Permit had expired because of alleged deficiencies in the renewal application process. In September 2004, the Court ruled that the SPDES Permit for our Danskammer facility was 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. Oral argument before the Appellate Division occurred in September 2005, and a decision is expected in the fourth quarter of 2005. We are also continuing to seek renewal of the SPDES Permit in proceedings before the NYSDEC. If our appeal is ultimately unsuccessful, we may be required to suspend operations at our Danskammer facility until receipt of final approval of the renewal of our Danskammer SPDES 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

30

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

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. Our entities with applications pending since February 2002, 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. Dynegy’s next triennial market power analysis is due June 16, 2008. Accordingly, these entities have continuously had market-based rate authority.

Seams Elimination Charges. On September 6, 2005, in a filing in the ongoing FERC proceedings relating to Midwest transmission rates, AmerenIP is seeking to require DMG and other Dynegy affiliates to compensate AmerenIP for certain MISO charges currently being assessed to and paid by AmerenIP. AmerenIP maintained in its filing that these charges should be Dynegy’s responsibility. FERC is not expected to rule on whether the specific charges may be shifted to Dynegy and, if applicable, the amount that Dynegy is required to compensate AmerenIP, until approximately mid-2006. A preliminary settlement conference scheduled by the administrative law judge in the proceeding was held on November 4, 2005. During the three months ended September 30, 2005, we recorded a reserve related to these charges.

Note 10—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 17—Employee Compensation, Savings and Pension Plans beginning on page F-59 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 September 30,
	2005			2004			2005		2004
	(in millions)
Service cost benefits earned during period	$	2		$	2		$	1	$	1
Interest cost on projected benefit obligation		3			1			—		—
Expected return on plan assets		(2	)		(1	)		—		—
Recognized net actuarial loss		—			—			1		—
Total net periodic benefit cost	$	3		$	2		$	2	$	1
	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2005			2004			2005		2004
	(in millions)
Service cost benefits earned during period	$	8		$	6		$	2	$	1
Interest cost on projected benefit obligation		7			3			2		1
Expected return on plan assets		(6	)		(2	)		—		—
Recognized net actuarial loss		2			1			1		—
Total net periodic benefit cost	$	11		$	8		$	5	$	2

31

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

Contributions. During the nine months ended September 2005, we contributed approximately $31 million to our pension plans. In October 2005, we contributed $0.3 million to our other post-retirement benefit plans. We do not expect to make any further contributions to the plans in 2005.

Medicare Prescription Drug, Improvement and Modernization Act of 2003. As discussed in Note 17—Employee Compensation, Savings and Pension Plans—Medicare Prescription Drug, Improvement and Modernization Act of 2003, beginning on page F-64 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 11—Income Taxes

Effective Tax Rate. The income tax benefit (expense) included in our loss from continuing operations were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
	(in millions, except rates)
Income tax benefit (expense)	$	(16	)	$	28		$	96		$	61
Effective tax rate		31	%		39	%		34	%		43	%

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 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.

Capital Loss Valuation Allowance. In the second quarter of 2005 and in anticipation of the sale of DMSLP, as further discussed in Note 2—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids, we reduced the valuation allowance related to our capital loss carryforward by $34 million. 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	$	(34	)	$	(34	)	$	(1	)	$	(69	)
Tax benefit from discontinued operations		34			—			—			34
Balance as of September 30, 2005	$	—		$	(34	)	$	(1	)	$	(35	)

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

32

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

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:

	September 30, 2005			December 31, 2004
	(in millions)
Deferred tax assets:
Current	$	542		$	73
Non-current		13			12
Deferred tax liabilities:
Non-current		(814	)		(462	)
Net deferred tax liability	$	(259	)	$	(377	)

The balance sheet classification of our deferred tax liabilities and assets has changed significantly since December 31, 2004. As a result of our gain on the sale of DMSLP, coupled with current year operations, we expect to utilize approximately $580 million of our net operating loss carryforwards and approximately $90 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 September 30, 2005.

Note 12—Segment Information

We report our operations in the following segments: GEN, NGL 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 operations, the effects of these intersegment transactions, eliminated in consolidation, including the

33

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

ultimate third party settlement, previously recorded in other segments have also been reclassified to discontinued operations. Revenues from continuing operations represent third party sales not originating from NGL.

Reportable segment information for the three- and nine-month periods ended September 30, 2005 and 2004 is presented below:

DHI’s Segment Data for the Quarter Ended September 30, 2005

(in millions)

	GEN			NGL		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	608		$	—	$	30		$	—		$	638
Other		—			—		(83	)		—			(83	)
		608			—		(53	)		—			555
Affiliated revenues		—			—		180			—			180
Intersegment revenues		(4	)		—		5			(1	)		—
Total revenues	$	604		$	—	$	132		$	(1	)	$	735
Depreciation and amortization	$	(50	)	$	—	$	—		$	(4	)	$	(54	)
Operating income (loss)	$	104		$	—	$	63		$	(38	)	$	129
Earnings from unconsolidated investments		5			—		—			—			5
Other items, net		—			—		(4	)		—			(4	)
Interest expense													(79	)
Income from continuing operations before taxes													51
Income tax expense													(16	)
Income from continuing operations													35
Income from discontinued operations, net of taxes													43
Net income												$	78
Identifiable assets:
Domestic	$	6,766		$	1,705	$	1,516		$	1,184		$	11,171
Other		—			—		105			—			105
Total	$	6,766		$	1,705	$	1,621		$	1,184		$	11,276
Unconsolidated investments	$	286		$	77	$	—		$	—		$	363
Capital expenditures	$	22		$	16	$	—		$	1		$	39

34

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

DHI’s Segment Data for the Quarter Ended September 30, 2004

(in millions)

	GEN			NGL		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	273		$	—	$	33		$	—		$	306
Other		—			—		(15	)		—			(15	)
		273			—		18			—			291
Affiliated revenues		114			—		—			—			114
Intersegment revenues		38			—		(9	)		(29	)		—
Total revenues	$	425		$	—	$	9		$	(29	)	$	405
Depreciation and amortization	$	(50	)	$	—	$	(1	)	$	(6	)	$	(57	)
Operating income (loss)	$	71		$	—	$	(32	)	$	(55	)	$	(16	)
Earnings from unconsolidated investments		23			—		—			—			23
Other items, net		—			—		(3	)		(1	)		(4	)
Interest expense													(75	)
Loss from continuing operations before taxes													(72	)
Income tax benefit													28
Loss from continuing operations													(44	)
Income from discontinued operations, net of taxes													36
Net loss												$	(8	)
Identifiable assets:
Domestic	$	5,427		$	2,131	$	1,362		$	917		$	9,837
Other		—			7		770			7			784
Total	$	5,427		$	2,138	$	2,132		$	924		$	10,621
Unconsolidated investments	$	373		$	78	$	—		$	—		$	451
Capital expenditures	$	20		$	14	$	—		$	5		$	39

35

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

DHI’s Segment Data for the Nine Months Ended September 30, 2005

(in millions)

	GEN			NGL		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	1,391		$	—	$	49		$	—		$	1,440
Other		—			—		(163	)		—			(163	)
		1,391			—		(114	)		—			1,277
Affiliated revenues		—			—		248			—			248
Intersegment revenues		(28	)		—		29			(1	)		—
Total revenues	$	1,363		$	—	$	163		$	(1	)	$	1,525
Depreciation and amortization	$	(142	)	$	—	$	(1	)	$	(15	)	$	(158	)
Operating income (loss)	$	193		$	—	$	11		$	(261	)	$	(57	)
Earnings from unconsolidated investments		10			—		—			—			10
Other items, net		—			—		(4	)		—			(4	)
Interest expense													(229	)
Loss from continuing operations before taxes													(280	)
Income tax benefit													96
Loss from continuing operations													(184	)
Income from discontinued operations, net of taxes													131
Net loss												$	(53	)
Identifiable assets:
Domestic	$	6,766		$	1,705	$	1,516		$	1,184		$	11,171
Other		—			—		105			—			105
Total	$	6,766		$	1,705	$	1,621		$	1,184		$	11,276
Unconsolidated investments	$	286		$	77	$	—		$	—		$	363
Capital expenditures	$	87		$	39	$	—		$	6		$	132

36

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

DHI’s Segment Data for the Nine Months Ended September 30, 2004

(in millions)

	GEN			NGL		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	373		$	—	$	681		$	—		$	1,054
Other		—			—		(84	)		—			(84	)
		373			—		597			—			970
Affiliated revenues		346			—		6			—			352
Intersegment revenues		556			—		(438	)		(118	)		—
Total revenues	$	1,275		$	—	$	165		$	(118	)	$	1,322
Depreciation and amortization	$	(145	)	$	—	$	(1	)	$	(26	)	$	(172	)
Impairment and other charges		—			—		—			(24	)		(24	)
Operating income (loss)	$	158		$	—	$	45		$	(198	)	$	5
Earnings from unconsolidated investments		110			—		—			—			110
Other items, net		—			—		(1	)		3			2
Interest expense													(259	)
Loss from continuing operations before taxes													(142	)
Income tax benefit													61
Loss from continuing operations													(81	)
Income from discontinued operations, net of taxes													111
Net income												$	30
Identifiable assets:
Domestic	$	5,427		$	2,131	$	1,362		$	917		$	9,837
Other		—			7		770			7			784
Total	$	5,427		$	2,138	$	2,132		$	924		$	10,621
Unconsolidated investments	$	373		$	78	$	—		$	—		$	451
Capital expenditures	$	78		$	41	$	—		$	10		$	129

37

DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2005 and 2004

Note 13—Subsequent Event(s)

On October 31, 2005, we consummated the sale of DMSLP, which comprised substantially all of the operations of our NGL segment, to Targa Resources, Inc. and two of its subsidiaries. Please see Note 2 — Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion.

On October 31, 2005, we repaid the $593 million outstanding on our term loan as well as $189 million outstanding on our generation facility and amended and restated our credit facility. Please see Note 6—Debt—Amended and Restated Credit Facility for further discussion of our amended credit facility.

On November 10, 2005, in accordance with the SPN indenture, we made a $1.75 billion Asset Sale Offer to purchase, with the net cash proceeds from the sale of DMSLP , SPNs from the holders thereof at a price equal to 100% of the principal amount plus accrued and unpaid interest. Please see Note 6—Debt—DMSLP for further discussion of the Asset Sale Offer.

38

DYNEGY HOLDINGS INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended September 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. Management’s Discussion and Analysis contains forward-looking statements including, without limitation, statements relating to our plans, strategies, objectives, expectations, and intentions, that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “estimate,” “project,” “forecast,” “plan,” “may,” “will,” “should,” “expect” and other words of similar meaning identify forward-looking statements. Any and all of our forward-looking statements can be affected by risks, uncertainties or other factors and we do not undertake to update, revise or correct any of the forward-looking information. Readers are cautioned that such forward-looking statements should be read in conjunction with the disclosures under the heading: “UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION” at the end of Management’s Discussion and Analysis .

GENERAL

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Following the sale of DMSLP, our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of the generation business as a separate segment in our consolidated financial statements. As described below, substantially all of our natural gas liquids business, which was conducted through DMSLP and its subsidiaries, was sold to Targa on October 31, 2005. We also separately report the results of our CRM business, which primarily consists of our three remaining power tolling arrangements 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.

Sale of DMSLP. On October 31, 2005, we consummated the sale of DMSLP, which comprised substantially all of the operations of our NGL segment, to Targa Resources Inc. and two of its subsidiaries, which we refer to as “Targa”, for $2.445 billion in cash. At closing we received $2.35 billion in cash proceeds. Targa assumed responsibility for approximately $47 million in letters of credit provided by us for the benefit of DMSLP, with the replacement of those letters of credit to occur within 90 days following the closing. By December 31, 2005, we expect to receive payment of a substantial majority of the balance of the sales proceeds from Targa which represents our cash collateral related to DMSLP. The total amount of cash collateral, approximately $95 million, is lower than our August 2, 2005 estimate of $125 million primarily as a result of less cash collateral posted due to the business interruptions caused by the recent Gulf Coast hurricanes. Please see Note 6—Debt—DMSLP for a discussion of the permitted use of proceeds.

Operational Highlights. We are a commodity-cyclical business and, as such, our core business results in our GEN business are affected by swings in commodity prices. The three most important power pricing markets that impact our power generation business are PJM, MISO and New York Zone G. In addition to commodity prices, the relationships between prices for power and natural gas or other power generating fuels, commonly referred to as the “spark spread,” also affect business results. We believe commodity prices and spark spreads in these markets will be our most indicative earnings drivers for the remainder of 2005. Pricing and spark spread in each of these markets for the first nine months of the year was higher than the same period last year. However, 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

39

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 lower, fractionation volumes are lower and marketing volumes are lower than the same period last year.

Please see “—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. Dynegy’s acquisition of Sithe Energies in January 2005 achieved both sector growth and restructuring of a significant toll obligation by transforming the toll into a Dynegy intercompany (and our affiliate) agreement. Through this transaction, Dynegy acquired more than 1,000 MW of low heat rate efficient generation facilities. In addition to the power plants, Dynegy 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 Dynegy 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 Dynegy’s remaining $100 million in sales proceeds held in escrow in connection with Dynegy’s sale of Illinois Power to Ameren, and Dynegy received such funds on July 27, 2005.

Finally, in April 2005, we and Dynegy 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 and Dynegy agreed to a total settlement consisting of (i) a $150 million payment by Dynegy’s directors and officers insurance policy, (ii) two cash payments totaling $250 million, which we made in May and July of 2005 and (iii) the delivery of 17,578,781 shares of Dynegy’s 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 moved 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. While the natural gas liquids business played an integral role in our company’s financial recovery, after careful consideration, we concluded that significant opportunities existed to realize even greater value through a sale. On October 31, 2005, we consummated the sale of DMSLP, which comprised substantially all of the operations of our NGL segment. Please see Note 2—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.

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) strengthening our position as an independent power producer, (ii)

40

attracting private equity capital to the business or (iii) consolidating or a strategic combination enhanced by a more favorable net debt-to-capital ratio are the best ways to strengthen our business and deliver greater value to investors.

As an independent power producer, we could continue to develop and expand our existing facilities or through opportunistic expansion within our core markets. We have done this previously through the conversion of our Havana power generating facility to lower-cost and lower-emission PRB coal and Dynegy’s acquisition of Sithe Energies and its Northeast power generation assets.

We or Dynegy may seek to raise additional capital by attracting private equity funds to the business to recapitalize or finance future growth. While there can be no assurance that future financing will be available or available on terms acceptable to us, we believe there could be significant advantages to privately funding future transactions. The market recently has shown that this type of capital support can be successful.

With 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. 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.

Hurricane Katrina and Hurricane Rita. On August 29, 2005, Hurricane Katrina struck the Gulf Coast region of the United States, causing widespread damage to Southeast Louisiana, Mississippi, Alabama and to energy infrastructure in nearby state and federal offshore waters. On September 24, 2005, Hurricane Rita also struck the Gulf Coast, causing damage to Southwest Louisiana, the Texas Gulf Coast near Louisiana and to energy infrastructure in nearby state and federal offshore waters. Hurricane Katrina and Rita damaged certain of NGL’s facilities, which we owned prior to October 31, 2005. Although we are bearing a portion of the business interruption loss, we carry, for the benefit of DMSLP, business interruption and property damage insurance, which we believe contains deductibles, limits, and sub-limits customary for companies in the energy industry. Our GEN facilities were not damaged by Hurricane Katrina or Rita. We do not anticipate a significant impact on our financial condition, results of operations or cash flows as a result of the hurricanes.

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. Additionally, from time to time, we may borrow money from our parent.

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Debt Obligations

During the third quarter 2005, we used cash on hand to reduce our outstanding debt by $1 million for our term loan. On October 31, 2005, we borrowed $600 million under the revolving credit component of the Amended and Restated Credit Facility to repay the $593 million term loan and accrued interest associated with the former credit facility, and with cash on hand, we repaid the $189 million generation facility debt. Following such repayments, our debt maturity profile will include $22 million in 2006, zero in 2007, $225 million in 2008, zero in 2009, $626 million in 2010 and $2,451 million thereafter.

Our aggregate maturities for long-term debt, including the current portion and excluding our Central Hudson leveraged lease, as of September 30, 2005, were approximately $4.1 billion.

Amended and Restated Credit Facility. On October 31, 2005, we replaced our former $1.3 billion credit facility with a second amended and restated credit agreement (the “Amended and Restated Credit Facility”), comprised of (i) a $400 million letter of credit component and (ii) a $600 million revolving credit component. The Amended and Restated Credit Facility is collateralized with cash as well as other assets that were pledged under the former credit facility, excluding those assets sold in connection with the sale of DMSLP, as we are required to post cash collateral in an amount equal to 103% of outstanding letters of credit and borrowings under the Amended and Restated Credit Facility. We will earn interest income on the cash on deposit in the cash collateral account.

A letter of credit fee is payable on the undrawn amount of each letter of credit outstanding at a percentage per annum equal to 0.50% of the undrawn amount. We also incur additional fees for issuing letters of credit. Amounts drawn on letters of credit issued pursuant to the facility, as well as borrowings under the revolving credit component of the facility, bear interest at a base rate plus 0.50% per annum. An unused commitment fee of 0.10% is payable on the unused portion of the Amended and Restated Credit Facility.

On October 31, 2005, we borrowed $600 million under the revolving credit component of the Amended and Restated Credit Facility to repay the term loan and accrued interest associated with the former credit facility. The $600 million outstanding principal balance of the revolving credit component was paid in full on November 1, 2005 without a corresponding reduction in revolving credit commitments.

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 November 4, 2005, September 30, 2005 and December 31, 2004:

	November 4, 2005			September 30, 2005		December 31, 2004
	(in millions)
By Segment:
GEN	$	228		$	258	$	192
CRM		97			86		94
NGL		44	(1)		159		167
Other		12			9		17
Total	$	381		$	512	$	470
By Type:
Cash (2)	$	80		$	187	$	376
Letters of Credit		301	(3)		325		94
Total	$	381		$	512	$	470

(1) As of November 4, 2005, we had posted $44 million in letters of credit for NGL. However, with the sale of DMSLP, Targa is contractually obligated to substitute their own letters of credit for our letters of credit, as well as reimburse us approximately $95 million for cash collateral posted in NGL at October 31, 2005. In addition, Targa has indemnified us and issued a letter of credit to us to support any drawings under the letters of credit posted by us on behalf of Targa. We expect a substantial majority of NGL collateral requirements to be eliminated by December 31, 2005.

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(2) Cash collateral consists of either cash deposits to cover physical deliveries or liabilities on mark-to-market positions or prepayments for commodities or services that are in advance of normal payment terms.

(3) In accordance with the terms of the Amended and Restated Credit Facility, we are required to post cash collateral in an amount equal to 103% of outstanding letters of credit.

The increase in collateral postings from December 31, 2004 to September 30, 2005 is primarily a result of a $66 million increase in postings for GEN. This increase in GEN is primarily the result of increases in commodity prices and the volume of fuel purchased, specifically natural gas. The increase was offset by a decrease in collateral posted in NGL of $8 million primarily as a result of lower volumes. The GEN increase was further offset by a $8 million decrease in collateral posted in support of CRM, resulting primarily from expiration of the Gregory tolling agreement and the rolloff of NYMEX positions.

We have transitioned counterparty collateral demands from cash postings to letters of credit in order to replenish our cash balances after taking into account our payments of $175 million in May 2005 and $80 million in July 2005 in connection with the settlement of Dynegy’s shareholder class action and derivative litigation.

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 our credit ratings, the sale of DMSLP and current commodity price estimates, specifically as prices relate to fuel purchases and power hedging activity, we estimate that collateral requirements will be approximately $300 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 collateral 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 materially since December 31, 2004, with respect to which information is included in our Form 10-K. On October 31, 2005, we and Dynegy (i) amended and restated our credit facility; (ii) repaid the $593 million outstanding on our term loan and (iii) used cash-on-hand to repay the $189 million outstanding on our generation facility (scheduled to mature in 2007). Please see Note 6—Debt—Amended and Restated Credit Facility for further discussion of our amended credit facility.

There were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2004. However, as a result of Dynegy’s acquisition of Sithe Energies, certain of these commitments are now due to affiliates.

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Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and, as of October 31, 2005, available capacity under our Amended and Restated Credit Facility. Please see Note 6—Debt—Amended and Restated Credit Facility for further discussion of our amended credit facility. Additionally, from time to time, we may borrow money from our parent.

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

	November 4, 2005			September 30, 2005			December 31, 2004
	(in millions)
Total revolver capacity	$	—		$	700		$	700
Total additional letter of credit capacity		325	(4)		—			—
Outstanding letters of credit under credit facility		(301	)		(325	)		(94	)
Unused credit facility capacity		24			375			606
Cash		1,396	(1)		119	(1)(2)		245	(1)(2)
Total available liquidity	$	1,420		$	494	(3)	$	851

(1) The November 4, 2005, September 30, 2005 and December 31, 2004 amounts include approximately $15 million, $15 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 September 30, 2005 and December 31, 2004 amounts include approximately $18 million and $13 million, respectively, of cash held by our NGL business. See Note 2—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids.

(3) The decrease in liquidity from December 31, 2004 to September 30, 2005 is primarily due to (i) our payments of $255 million in connection with the settlement of the shareholder class action litigation and derivative litigation, (ii) capital expenditures of $132 million and (iii) debt payments of $23 million.

(4) On October 31, 2005, we amended and restated the credit facility to consist of (i) a $400 million letter of credit component and (ii) a $600 million revolving credit component. Please see Note 6—Debt—Amended and Restated Credit Facility for further discussion of our amended credit facility. Our credit facility capacity is limited by, and will increase or decrease by, the amount of cash collateral on deposit.

Cash Flows from Operations. We had operating cash outflows of $163 million for the nine months ended September 30, 2005. This consisted of $584 million in operating cash flows from our GEN and NGL segments, reflecting positive earnings for the period and increases in working capital due to returns of cash collateral postings, partially offset by decreases in working capital due to increased accounts receivable. The cash flows from our operating segments were offset by $747 million of cash outflows relating to our CRM business and corporate-level expenses. Please see “—Results of Operations—Operating Income” and “—Cash Flow Disclosures” for further discussion of factors impacting our operating cash flows for the periods presented.

On October 31, 2005, cash interest expense associated with the term loan and the generation facility debt were eliminated, as these instruments were 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 6—Debt—DMSLP, 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 manage tightly our operating costs, including costs for fuel and maintenance. 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 see “—Results of Operations—Outlook—GEN Outlook” for further discussion.

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In addition, we expect future cash distributions from West Coast Power to be significantly less than they have been historically, due to the expiration of our CDWR power purchase agreement in December 2004. In California’s current energy market, the West Coast Power generating facilities are significantly less profitable under the RMR contracts or as merchant facilities, and the partnership’s cash distributions are derived from cash in excess of its operating requirements.

Cash on Hand. At November 4, 2005 and September 30, 2005, we had cash on hand of $1,396 million and $119 million, respectively, as compared to $245 million at the end of 2004. This increase in cash on hand at November 4, 2005 as compared to the end of 2004 is primarily attributable to the sale of DMSLP.

Revolver Capacity. On October 31, 2005, we amended and restated the credit facility. We are required to post cash collateral in an amount equal to 103% of outstanding letters of credit plus the outstanding balance of advances under the revolver. Therefore, our capacity to borrow and/or issue letters of credit under the Amended and Restated Credit Facility is dependent upon and limited by the amount of cash collateral on deposit. As of November 4, 2005, $301 million in letters of credit are outstanding but undrawn, and no revolving credit borrowings are outstanding under the Amended and Restated Credit Facility. Please see Note 6—Debt— Amended and Restated Credit Facility for further discussion of our amended credit facility.

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 by Dynegy.

Asset Sale Proceeds. As further discussed in Note 2—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids, on October 31, 2005, we consummated the sale of DMSLP. The terms of our former $1.3 billion credit facility and the SPN indenture and security agreements govern the use of the proceeds from this sale.

According to the SPN indenture, we may use the proceeds of the sale DMSLP to (i) repay and permanently reduce first lien capacity, (ii) repay parity lien debt, provided that any offer to repay parity lien debt holders is made on a pro rata basis or (iii) make a capital expenditure or invest in various type of assets defined as Replacement Assets.

In accordance with the SPN indenture, on November 10, 2005, we made a $1.75 billion Asset Sale Offer to purchase, with the net cash proceeds from the sale of DMSLP, SPNs from the holders thereof at a price equal to par value of the principal amount plus accrued and unpaid interest. Under the terms of the SPN indenture, “Excess Proceeds” from the sale of DMSLP are approximately $2.39 billion, and to the extent not used for the repurchase of the SPNs, may be used by us for any purpose not otherwise prohibited under the SPN indenture.

In an effort to maximize our return on investment and to further clarify our business strategy, we have previously sold other assets that we did not consider core to our operations. The aggregate loss of earnings in 2004 associated with these assets was not material and was more than offset by net gains on sale in 2004. However, beginning in 2005, the lost earnings of approximately $14 million annually from such assets, before consideration of interest savings, will no longer be offset by gains on sale.

Capital-Raising Transactions. As part of Dynegy’s ongoing efforts to move toward a capital structure that is more closely aligned with the cash-generating potential of the consolidated enterprise’s asset-based business, which is subject to cyclical changes in commodity prices, Dynegy 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.

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These transactions may include capital markets transactions. Dynegy’s ability to issue public securities is enhanced by its effective shelf registration statement, under which it has approximately $430 million in remaining availability. This availability was not reduced by the issuance on August 12, 2005 of 17,578,781 shares of Dynegy Class A common stock pursuant to the settlement of the shareholder class action litigation, as such issuance was 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, Dynegy’s non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond its control. Any issuance of equity would likely have other effects as well, including shareholder dilution. Further, our and/or Dynegy’s ability to issue debt securities is limited by our and/or Dynegy’s financing agreements, including our SPN indenture. Please see Note 6—Debt— Amended and Restated Credit Facility 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 seek to achieve fiscally responsible growth through (i) strengthening our position as an independent power producer, (ii) attracting private equity capital to the business and (iii) sector consolidation opportunities that will add scale and scope to our business.

As previously indicated, our sale of DMSLP could positively impact the future of our power generation business. We were able to sell DMSLP while minimizing our cash taxes. We expect to be able to utilize net operating losses and capital loss carry-forwards to offset a substantial majority of the tax gain.

The proceeds from the transaction enable us to improve our overall financial condition by significantly increasing our liquidity, which positions our power generation business with the flexibility to consider new strategic directions.

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 see “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 nine-month periods ended September 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 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.

Regarding our results of operations for 2005 and 2004, the impact of disposition activity reduces the comparability of some of our historical financial and volumetric data.

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Three Months Ended September 30, 2005 and 2004

The following tables provide summary financial data regarding our consolidated and segmented results of operations for the three months ended September 30, 2005 and 2004, respectively.

Quarter Ended September 30, 2005

	GEN		NGL		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	104	$	—	$	63		$	(38	)	$	129
Earnings from unconsolidated investments		5		—		—			—			5
Other items, net		—		—		(4	)		—			(4	)
Interest expense												(79	)
Income from continuing operations before taxes												51
Income tax expense												(16	)
Income from continuing operations												35
Income from discontinued operations, net of taxes												43
Net income											$	78

Quarter Ended September 30, 2004

	GEN		NGL		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	71	$	—	$	(32	)	$	(55	)	$	(16	)
Earnings from unconsolidated investments		23		—		—			—			23
Other items, net		—		—		(3	)		(1	)		(4	)
Interest expense												(75	)
Loss from continuing operations before taxes												(72	)
Income tax benefit												28
Loss from continuing operations												(44	)
Income from discontinued operations, net of taxes												36
Net loss											$	(8	)

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

	Quarter Ended September 30,
	2005		2004
Power Generation
Million megawatt hours generated—gross		10.0		9.5
Million megawatt hours generated—net		9.7		9.0
Average natural gas price—Henry Hub ($/MMbtu) (1)	$	9.66	$	5.49
Average on-peak market power prices ($/MWh):
Cinergy	$	80	$	43
NI Hub/ComEd	$	75	$	41
Southern	$	90	$	50
New York—Zone G	$	110	$	57
ERCOT	$	107	$	50
SP-15	$	83	$	57
Natural Gas Liquids
Gross NGL production (MBbls/d):
Field plants		55.1		58.9
Straddle plants		18.5		29.6
Total gross NGL production		73.6		88.5
Natural gas (residue) sales (Bbtu/d)		187.9		190.7
Natural gas inlet volumes (MMCFD):
Field plants		512.4		545.8
Straddle plants		794.1		1,249.9
Total natural gas inlet volumes		1,306.5		1,795.7
Fractionation volumes (MBbls/d)		185.4		257.2
Natural gas liquids sold (MBbls/d)		265.3		290.4
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	60.30	$	42.22
Natural gas—Henry Hub ($/MMbtu) (2)	$	8.51	$	5.76
Natural gas liquids ($/Gal)	$	0.96	$	0.75
Fractionation spread ($/MMBtu)—daily	$	1.76	$	2.93

(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.

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

	Quarter Ended September 30, 2005
	GEN			NGL		CRM			Other		Total
	(in millions)
Legal and settlement charges	$	—		$	—	$	(29	)	$	—	$	(29	)
Discontinued operations		—			71		(2	)		—		69
Total	$	—		$	71	$	(31	)	$	—	$	40
	Quarter Ended September 30, 2004
	GEN			NGL		CRM			Other		Total
	(in millions)
Impairment of West Coast Power	$	(45	)	$	—	$	—		$	—	$	(45	)
Gain on sale of Oyster Creek		15			—		—			—		15
Discontinued operations		—			61		(1	)		—		60
Total	$	(30	)	$	61	$	(1	)	$	—	$	30

Operating Income

Operating income was $129 million for the quarter ended September 30, 2005, compared to operating loss of $16 million for the quarter ended September 30, 2004.

GEN. Operating income for our GEN segment was $104 million for the three months ended September 30, 2005, compared to $71 million for the three months ended September 30, 2004.

In the Midwest region, results decreased $11 million year over year, from $118 million for the third quarter 2004 to $107 million for the third quarter 2005. This decrease consists of a $19 million decrease from our coal-fired generating units offset by an $8 million increase from our gas-fired peaking facilities.

Average on-peak market prices in the NI Hub/Com Ed region increased from $41 per MWh in the third quarter 2004 to $75 per MWh for the third quarter 2005. Additionally, volumes were up 13%, from 5.3 million MWh for the third quarter 2004 to 6.0 million MWh. Despite the increases in output and price, results from our coal-fired generating units were negatively impacted by the AmerenIP contract and mark-to-market losses. To compare, revenues under our power purchase agreement with AmerenIP in the third quarter 2005 were $35 million higher compared with revenues under our agreement with Illinois Power in 2004. However, volumes sold pursuant to this contract increased 59% from the third quarter of 2004 to the third quarter of 2005, resulting in a reduced supply of power available for sale at prevailing market prices in 2005. Please see Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Form 10-K for a discussion of the contractual terms of these agreements. Volumes, excluding those sold under the AmerenIP contract, decreased by 0.7 million MWh. Additionally, the Midwest region’s results for the third quarter 2005 include an $18 million net charge from mark-to-market losses. We previously entered into forward sales and related transactions to economically hedge our exposure to power prices. As a result of increased power prices and overall power price volatility, we recognized $20 million of mark-to-market losses during the third quarter 2005 associated with these forward sales and related transactions. These losses were partly offset by $2 million of income resulting from hedge ineffectiveness, which is also the result of the volatility of power prices in the regions in which we hedge our Midwest power sales. The region experienced $2 million mark-to-market income for the third quarter 2004.

Results from our gas fired peaking facilities in the Midwest increased by $8 million for the quarter ended September 30, 2005 compared with 2004, partly offsetting the decrease in earnings from our coal-fired generating facilities. This improvement was a result of favorable power pricing, resulting from warm weather, and generally higher fuel prices. These factors made it economical to produce substantially more power than our gas-fired facilities produced in 2004.

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The decrease in earnings in the Midwest was more than offset in the Northeast region, where results increased $31 million, from $11 million for the three months ended September 30, 2004 to $42 million for the same period in 2005. This increase in earnings was the result of improved prices, spark spreads, and volumes. Although fuel prices were up, average on-peak market prices in the region increased from $57 per MWh in the third quarter 2004 to $110 per MWh for the third quarter 2005, resulting in increased spark spreads for both our Danskammer and Roseton facilities. This resulted in significantly increased production at Roseton, where volumes rose by 75% from 0.8 million MWh for the third quarter 2004 to 1.4 million MWh for the third quarter 2005.

Results in our Texas region improved by $18 million, from zero for the third quarter 2004 to $18 million for the third quarter 2005. Earnings in the Texas region during 2005 included income of $8 million related to hedge ineffectiveness, caused by gas price volatility in the markets in which we hedge our Texas fuel purchases. In addition, although natural gas prices have remained high, power prices approximately doubled compared to 2004, resulting in improved spark spreads. Finally, we were able to mitigate the negative impact of high natural gas prices by providing additional ancillary services to the market. Results in our Southeast region increased slightly, from zero for the third quarter 2004 to $1 million for 2005, as a short-term, weather-driven, increase in spark spread caused these units to run for a short period of time.

GEN’s reported operating income for the three-month periods ended September 30, 2005 and 2004 also includes approximately zero and $2.5 million, respectively, of mark-to-market income, in addition to those discussed above, related to derivatives that do not qualify as cash flow hedges. These purchases and sales did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market basis. Further, GEN’s 2004 results include additional earnings of $2 million from energy sales to commercial and industrial customers.

General and administrative expense increased slightly, from $14 million for the three months ended September 30, 2004 to $15 million for the same period in 2005. Depreciation expense remained flat, at $50 million for both 2004 and 2005.

GEN’s 2005 results also include a $2 million loss related to the sale of decommissioned and scrapped transformers from our Renaissance power generation facility.

CRM. Operating income for the CRM segment was $63 million for the quarter ended September 30, 2005, compared to a loss of $32 million in 2004.

In the third quarter of 2005, we recognized $82 million of income from our tolling and financial swap arrangements with Sithe Energies. This income is driven primarily by the effect of gas and power price volatility on the value of our financial swap instrument. Additionally, in the third quarter of 2005, we recognized a $21 million gain related to the termination of a contract to sell emissions allowances. However, these benefits were partly offset by $14 million of fixed payments on our Sterlington power tolling arrangement in excess of realized margins on power generated and sold, a $29 million increase in legal reserves, as well as net mark-to-market income of $3 million on our legacy emissions, gas and power positions. 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.

2004 results included net mark-to-market-gains of $7 million on our legacy emissions, gas and power positions. These gains were more than offset by $40 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 $38 million for the quarter ended September 30, 2005, compared to a loss of $55 million for the quarter ended September 30, 2004. Results for 2004 include approximately $10 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.

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Earnings from Unconsolidated Investments

Our earnings from unconsolidated investments were approximately $5 million for the quarter ended September 30, 2005, compared to $23 million for the quarter ended September 30, 2004. In the third quarter 2004, we sold our investment in the Oyster Creek generating facility, resulting in a gain of $15 million. In addition, equity earnings from our West Coast Power investment were approximately $42 million for the three months ended September 30, 2004, offset by a $45 million impairment charge, resulting in a net loss of $3 million. This compared to equity earnings of $4 million for the three months ended September 30, 2005, offset by an $8 million impairment charge.

Other Items, Net

Other items, net, totaled $4 million for the quarters ended September 30, 2005 and 2004.

Interest Expense

Interest expense totaled $79 million for the quarter ended September 30, 2005, compared to $75 million for the quarter ended September 30, 2004.

Income Tax Benefit (Expense)

We reported an income tax expense during the quarter ended September 30, 2005 of $16 million compared to a benefit of $28 million for the quarter ended September 30, 2004. The income tax benefit in 2004 includes a $2 million benefit related to the release of reserves for tax contingencies. Excluding this item, the 2004 effective tax rate would be 36%. The 2005 effective tax rate was 31%. 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 include our NGL business in our NGL segment and our U.K. CRM business in our CRM segment. The following summarizes the activity included in income from discontinued operations:

Quarter Ended September 30, 2005

	U.K. CRM			NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	—		$	93		$	93
Earnings from unconsolidated investments included in income from discontinued operations		—			1			1
Other items, net included in income from discontinued operations		(2	)		(8	)		(10	)
Interest expense included in income from discontinued operations								(15	)
Income from discontinued operations before taxes								69
Income tax expense								(26	)
Income from discontinued operations							$	43

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Quarter Ended September 30, 2004

	U.K. CRM			NGL			Total
	(in millions)
Operating income (loss) included in income from discontinued operations	$	(1	)	$	74		$	73
Earnings from unconsolidated investments included in income from discontinued operations		—			3			3
Other items, net included in income from discontinued operations		—			(6	)		(6	)
Interest expense included in income from discontinued operations								(10	)
Income from discontinued operations before taxes								60
Income tax expense								(24	)
Income from discontinued operations							$	36

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 2—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids.

Operating income for the NGL segment was $93 million for the quarter ended September 30, 2005, compared to $74 million in the quarter ended September 30, 2004.

Gathering and processing operating results increased by $8 million for the quarter ended September 30, 2005 compared to the quarter ended September 30, 2004, primarily benefiting from 48% higher absolute commodity prices for natural gas and 27% higher absolute commodity prices for natural gas liquids year over year. At our field plants, results increased $15 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from higher prices. Operating results for the quarter ended September 30, 2004 included $2 million in operating margin from our Sherman plant, which was sold in November 2004. At our straddle plants, operating results decreased $8 million, due largely to the negative impact of Hurricanes Katrina and Rita, offset in part by the positive impact of higher natural gas liquids prices on POL contracts.

Results of our fractionation, storage and terminalling and transportation and logistics businesses decreased $10 million for the quarter ended September 30, 2005 compared to the quarter ended September 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 and lower volumes processed at our and third party gas processing plants due to reduced frac spreads. Additionally, Hurricanes Katrina and Rita reduced liquids production at many gas processing plants that feed into our fractionators reducing volumes available for fractionation.

Wholesale marketing results were unchanged for the quarter ended September 30, 2005 compared to the quarter ended September 30, 2004.

NGL marketing services and distribution results decreased approximately $7 million for the quarter ended September 30, 2005 compared to the quarter ended September 30, 2004. NGL marketing services and distribution results were favorably impacted in the third quarter 2004 by steeply rising natural gas liquids prices during the quarter. Further, although within acceptable measurement tolerances, natural gas liquids well losses also contributed to lower marketing margins during the quarter ended September 30, 2005.

Depreciation and amortization expense decreased $19 million for the quarter ended September 30, 2005 compared to the quarter ended September 30, 2004. We stopped depreciating the majority of our NGL assets on June 1, 2005, as they are classified as held for sale, which resulted in the reduced depreciation during the quarter ended September 30, 2005.

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Interest expense included in income from discontinued operations includes interest incurred on our term loan scheduled to mature in 2010 and our 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 increase in interest rates.

Income Tax Benefit (Expense) From Discontinued Operations. The 2005 and 2004 effective tax rates are 38% and 40%, 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.

Nine Months Ended September 30, 2005 and 2004

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

Nine Months Ended September 30, 2005

	GEN		NGL		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	193	$	—	$	11		$	(261	)	$	(57	)
Earnings from unconsolidated investments		10		—		—			—			10
Other items, net		—		—		(4	)		—			(4	)
Interest expense												(229	)
Loss from continuing operations before taxes												(280	)
Income tax benefit												96
Loss from continuing operations												(184	)
Income from discontinued operations, net of taxes												131
Net loss											$	(53	)

Nine Months Ended September 30, 2004

	GEN		NGL		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	158	$	—	$	45		$	(198	)	$	5
Earnings from unconsolidated investments		110		—		—			—			110
Other items, net		—		—		(1	)		3			2
Interest expense												(259	)
Loss from continuing operations before taxes												(142	)
Income tax benefit												61
Loss from continuing operations												(81	)
Income from discontinued operations, net of taxes												111
Net income											$	30

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

	Nine Months Ended September 30,
	2005		2004
Power Generation
Million megawatt hours generated—gross		26.3		28.9
Million megawatt hours generated—net		25.3		27.5
Average natural gas price—Henry Hub ($/MMbtu) (1)	$	7.66	$	5.73
Average on-peak market power prices ($/MWh):
Cinergy	$	61	$	43
NI Hub/ComEd	$	59	$	42
Southern	$	65	$	49
New York—Zone G	$	86	$	61
ERCOT	$	76	$	47
SP-15	$	65	$	53
Natural Gas Liquids
Gross NGL production (MBbls/d):
Field plants		56.2		57.6
Straddle plants		25.9		25.7
Total gross NGL production		82.1		83.3
Natural gas (residue) sales (Bbtu/d)		184.4		185.2
Natural gas inlet volumes (MMCFD):
Field plants		515.6		549.4
Straddle plants		1,113.5		968.8
Total natural gas inlet volumes		1,629.1		1,518.2
Fractionation volumes (MBbls/d)		174.3		218.6
Natural gas liquids sold (MBbls/d)		267.2		281.4
Average commodity prices:
Crude oil—WTI ($/Bbl)	$	53.44	$	38.51
Natural gas—Henry Hub ($/MMbtu) (2)	$	7.18	$	5.81
Natural gas liquids ($/Gal)	$	0.84	$	0.67
Fractionation spread ($/MMBtu)—daily	$	2.34	$	1.84

(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.

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.

	Nine Months Ended September 30, 2005
	GEN		NGL		CRM			Other			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	(29	)	$	(154	)	$	(183	)
Discontinued operations		—		152		3			—			155
Taxes		—		—		—			34			34
Total	$	—	$	152	$	(26	)	$	(120	)	$	6

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	Nine Months Ended September 30, 2004
	GEN			NGL		CRM		Other			Total
	(in millions)
Legal and settlement charges	$	2		$	—	$	—	$	(54	)	$	(52	)
Impairment of West Coast Power		(45	)		—		—		—			(45	)
Acceleration of financing costs		—			—		—		(14	)		(14	)
Gas transportation contracts		—			—		88		—			88
Taxes		—			—		—		(15	)		(15	)
Gain on sale of Oyster Creek		15			—		—		—			15
Discontinued operations		—			195		17		—			212
Total	$	(28	)	$	195	$	105	$	(83	)	$	189

Operating Income (Loss)

Operating loss was $57 million for the nine months ended September 30, 2005, compared to operating income of $5 million for the nine months ended September 30, 2004.

GEN. Operating income for the GEN segment was $193 million for the nine months ended September 30, 2005, compared to $158 million for the nine months ended September 30, 2004.

In the Midwest region, results declined from $312 million for the first nine months of 2004 to $308 million for the same period in 2005. This decrease consists of a $18 million decrease from our coal-fired generating units, partly offset by a $14 million increase from our gas-fired peaking facilities.

Average on-peak prices in the NI Hub/ComEd pricing region increased from $42 per MWh for the first nine months of 2004 to $59 per MWh for the first nine months of 2005. Additionally, volumes were up 4%, from 15.6 million MWh for 2004 to 16.3 million MWh. Despite the increases in output and price, results from our coal-fired generating units were negatively impacted by the AmerenIP contract and mark-to-market losses. Revenues under our power purchase agreement with AmerenIP for the nine months ended September 30, 2005 were $34 million higher compared with revenues under our agreement with Illinois Power in 2004. However, volumes sold pursuant to this contract increased 24% for the nine months ended September 30,2005 compared to the same period of 2004, resulting in a reduced supply of power available for sale at prevailing market prices in 2005. Please read Item 1. Business—Segment Discussion—Power Generation beginning on page 2 of our Form 10-K for a discussion of the contractual terms of these agreements. Volumes excluding those sold under the AmerenIP contract decreased by 1.0 million MWh from 2004 to 2005. Additionally, the Midwest region’s results for the nine months ended September 30, 2005 include $15 million, net, of mark-to-market losses. We previously entered into forward sales and related transactions to economically hedge our exposure to power prices. As a result of increased power prices and overall power price volatility, we recognized $18 million of mark-to-market losses during 2005 associated with these forward sales and related transactions. These losses were partly offset by $3 million of income resulting from hedge ineffectiveness, which is also the result of the volatility of power prices in the locations in which we hedge our Midwest power sales. For the nine months ended September 30, 2004, our results included no significant mark-to-market losses.

Results for our gas-fired peaking facilities in the Midwest region were improved by $14 million, from a loss of $6 million for the nine months ended September 30, 2004 to income of $8 million for 2005. This improvement was a result of favorable power pricing, resulting from warm weather, and generally higher fuel prices. These factors made it economical to produce substantially more power than our gas-fired facilities produced in 2004.

Declines in the Midwest were more than offset by significantly stronger results in the Northeast region, up from $28 million for the nine months ended September 30, 2004 to $48 million for the same period in 2005. Earnings from our Roseton and Danskammer facilities were up $20 million, as average on-peak prices were up 41%

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in the market served by these facilities. Although compressed spark spreads resulted in lower production at our Roseton facility during the first half of 2005, production increased in the third quarter, as power prices increased significantly in relation to fuel prices. For the nine months ended September 30, 2005, volumes for our Roseton facility were down 0.6 million MWh from 2004, while Danskammer volumes were up 0.2 million MWh. However, operating expense increased by $10 million at our existing facilities, primarily related to maintenance at Roseton and increased labor costs.

Results in our Texas region improved by $26 million, from a loss of $10 million for the nine months ended September 30, 2004 to income of $16 million for the nine months ended September 30, 2005. Although natural gas prices have remained high, power prices increased by 62% in the region. We were able to further mitigate the negative impact on earnings of high natural gas prices by providing additional ancillary services to the market. Our 2005 results for Texas also include earnings of approximately $7 million related to hedge ineffectiveness, caused by gas price volatility in the markets in which we hedge. Results in our Southeast region remained flat at $1 million for both the nine months ended September 30, 2004 and 2005.

GEN’s reported operating income for the nine-month periods ended September 30, 2005 and 2004 also includes approximately $5 million and $6 million, respectively, of mark-to-market income in addition to that discussed above, related to derivatives that do not qualify as cash flow hedges. These purchases and sales did not meet the criteria for hedge accounting under SFAS No. 133 and, therefore, were accounted for on a mark-to-market basis. Further, GEN’s 2004 results of operations include additional earnings of $5 million from energy sales to commercial and industrial customers.

General and administrative expense increased from $41 million for the nine months ended September 30, 2004 to $46 million for the same period in 2005. However, depreciation expense decreased slightly, from $145 million for the nine months ended September 30, 2004 to $142 million for the nine months ended September 30, 2005. Earnings from 2005 also include a $2 million charge associated with the sale of decommissioned and scrapped transformers from our Renaissance facility.

CRM. Operating income for the CRM segment was $11 million for the nine months ended September 30, 2005, compared to operating income of $45 million in 2004.

Results for 2005 reflect net earnings of $67 million related to our tolling and swap arrangements with Sithe Energies, driven primarily by the effect of gas and power price volatility on the value of our financial swap instrument, a $21 million gain related to the termination of a contract to sell emissions allowances, and a net mark-to-market benefit of $14 million from our legacy gas, power and emissions positions. These gains were offset by $59 million of fixed payments on our Sterlington and Gregory tolling arrangements in excess of realized margins on power generated and sold. Additionally, 2005 results include a $29 million increase in legal 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.

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 $51 million associated with our legacy gas, power and emissions positions, and $9 million of income from our Canadian business. These gains were partly offset by the $111 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 $261 million for the nine months ended September 30, 2005, compared to a loss of $198 million for the nine months ended September 30, 2004. Results for 2005 include a $154 million charge associated with the recent settlement of Dynegy’s and our shareholder class action litigation. For more information, please see Note 8—Commitment and Contingencies—Shareholder Litigation. Results for 2004 include approximately $54 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.

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Earnings from Unconsolidated Investments

Our earnings from unconsolidated investments were approximately $10 million for the nine months ended September 30, 2005, compared to $110 million for the same period 2004. The decrease is due primarily to 2004 investment sales. In 2004, we recognized aggregate income of $98 million, including gains on sales of investments of $17 million from our investments in the Michigan, Hartwell, Oyster Creek and Commonwealth generation facilities, all of which we sold during 2004. In addition, total earnings from our West Coast Power investment were approximately $6 million for the nine months ended September 30, 2005, offset by an impairment charge of $8 million, compared to $123 million for 2004, offset by an impairment charge of $45 million. The decrease in earnings is primarily the result of the expiration of West Coast Power’s CDWR contract at the end of 2004. Please see 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 $4 million of expense for the nine months ended September 30, 2005, compared to income of $2 million for the nine months ended September 30, 2004. The increase is primarily associated with higher interest income in 2005 due to higher interest rates.

Interest Expense

Interest expense totaled $229 million for the nine months ended September 30, 2005, compared to $259 million for the nine months ended September 30, 2004. Interest expense in 2004 includes higher amortization of deferred financing costs, including $14 million associated with deferred financing costs relating to our former credit facility, which were expensed upon the execution of our $1.3 billion credit facility. In addition, interest expense decreased from 2004 to 2005 due to lower outstanding borrowings.

Income Tax Benefit

We reported an income tax benefit during the nine months ended September 30, 2005 of $96 million compared to a benefit of $61 million for the nine months ended September 30, 2004. The 2004 tax benefit includes a $3 million benefit related to the release of reserves upon the conclusion of prior year tax audits. Please see Note 11—Income Taxes for further discussion. Excluding this item, the 2004 effective tax rate would be 41% compared to 34% in 2005. In general, differences between these effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences.

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Discontinued Operations

Discontinued operations include our NGL business in our NGL segment and our U.K. CRM business in our CRM segment. The following summarizes the activity included in income from discontinued operations:

Nine Months Ended September 30, 2005

	U.K. CRM			NGL			Total
	(in millions)
Operating income (loss) included in income from discontinued operations	$	(1	)	$	205		$	204
Earnings from unconsolidated investments included in income from discontinued operations		—			5			5
Other items, net included in income from discontinued operations		4			(18	)		(14	)
Interest expense included in income from discontinued operations								(40	)
Income from discontinued operations before taxes								155
Income tax expense								(24	)
Income from discontinued operations							$	131
Nine Months Ended September 30, 2004
	U.K. CRM			NGL			Total
	(in millions)
Operating income included in income from discontinued operations	$	16		$	219		$	235
Earnings from unconsolidated investments included in income from discontinued operations		—			7			7
Other items, net included in income from discontinued operations		1			(15	)		(14	)
Interest expense included in income from discontinued operations								(16	)
Income from discontinued operations before taxes								212
Income tax expense								(101	)
Income from discontinued operations							$	111

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 2—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids.

Operating income for the NGL segment was $205 million for the nine months ended September 30, 2005, compared to $219 million for the nine months ended September 30, 2004. Operating income for the nine months ended September 30, 2004 included pre-tax gains of $17 million and $36 million, respectively, from our Hackberry LNG and Indian Basin sales, offset by an impairment of $5 million.

Excluding the Hackberry and Indian Basin gains, the significant improvement in operating income was driven by natural gas and natural gas liquids prices, which increased by 24% and 25%, respectively, year over year. The first nine months of 2005 was marked by continued high run times experienced across our facilities.

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Gathering and processing operating results increased by $35 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004, primarily benefiting from 23% higher absolute commodity prices for natural gas and 25% higher absolute commodity prices for natural gas liquids year over year. At our field plants, results increased $36 million. Our current contract portfolio of nearly 99% POP and fee-based contracts benefited from higher prices. Operating results for the nine months ended September 30, 2004 included $8 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 decreased $1 million, due to hurricane impacts offset by the positive 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 $15 million for the nine months ended September 30, 2005 compared to the nine months ended September 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 over the nine month period, offset by reduced volumes available for fractionation due to hurricane impacts at the end of August and all of September, 2005. 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 nine months ended September 30, 2005 compared to the nine months ended September 30, 2004, primarily as a result of milder than usual winter weather in the first quarter. Higher natural gas liquids prices contributed higher earnings on our net back refinery services contracts during the entire period.

NGL marketing services and distribution results decreased approximately $18 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. During the previous year, our results were impacted by volatile and generally rising natural gas liquids prices. In addition, during the nine months ended September 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. Further, although within acceptable measurement tolerances, natural gas liquids well losses also contributed to lower marketing margins during the nine months ended September 30, 2005.

Depreciation and amortization expense decreased $29 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. We stopped depreciating the majority of our NGL assets on June 1, 2005, as they are classified as held for sale, which resulted in the reduced depreciation during the nine months ended September 30, 2005. In addition, depreciation expense in the nine months ended September 30, 2004 included a $6 million charge related to an adjustment to accumulated depreciation.

At the end of each quarter in both 2005 and 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.

During 2005, U.K. CRM recognized $3 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.

Interest expense included in income from discontinued operations includes interest incurred on our term loan scheduled to mature in 2010 and our 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 four months of interest, compared to nine months of interest in 2005.

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Income Tax Benefit (Expense) From Discontinued Operations. The income tax expense in 2005 includes a $34 million benefit associated 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 our anticipated sale of DMSLP. For further information regarding the sale, please see Note 2—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 11—Income Taxes—Prior Year Tax Audits for further discussion. Excluding these items, the 2005 and 2004 effective tax rates would be 37% and 38%, 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.

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 and spark spreads, transportation logistics, weather conditions and in-market asset availability. Although we will continue our efforts to manage price risk through the optimization of fuel procurement, we expect to decrease forward sales of power and related transactions, in order to capture opportunities presented in today’s strong price environment, which we expect to continue through the rest of 2005 and well into 2006. In the event that prices move unfavorably, we will be exposed to lower earnings. Additionally, our future ability to recognize the full benefit of strong power prices will be limited by $40 million of losses associated with previously transacted cash flow hedges, which will be recognized in earnings over the next twelve months.

In the Midwest region, we expect our results to continue to be impacted by power prices and fuel availability. Although we expect prices to continue to remain high in the Midwest, we will not be able to fully realize these strong prices, due to volume options held by AmerenIP in our power purchase agreement with them. Under the terms of our power purchase agreement, which expires at the end of 2006, AmerenIP has the right to put back up to 200 MWh of capacity, provided they are able to demonstrate a reduced need for capacity resulting from a loss of retail customers. Any reduction of capacity under this provision would be effective January 1, 2006, thereby reducing the capacity revenues we would earn under the contract in 2006. AmerenIP has requested to reduce their capacity requirements by 122 MWh, and we are currently in discussions with AmerenIP regarding this request. Beyond 2006, results in the Midwest will be affected by the expiration of this power purchase agreement. Expiration of this contract will result in increased exposure to volatility in market prices, and could allow us to realize additional benefits if power prices remain strong.

Another factor impacting our results in the Midwest beyond 2006 will be the regulatory environment in Illinois. Currently, both of the two major Illinois electric utilities have proposed an auction as the means by which they will procure resources necessary to serve load after 2006. However, legal and regulatory challenges make it difficult to predict (i) whether an auction or some other mechanism(s), if any, will be approved in advance of 2007, and (ii) what impact this will have on our results.

The operation of our Midwest generation facilities is highly dependent on our ability to procure coal as fuel. Power generators 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 largely mitigate these concerns; however, railroad maintenance has resulted in decreased deliveries since May 2005, especially in the month of October. To ensure adequate coal supply for on-peak load during the upcoming winter months, we have begun a program to selectively conserve coal during off-peak periods, foregoing the revenue associated with this off-peak production. As a result, we expect we will be able to maintain current coal inventories during the fourth quarter of 2005, although we remain subject to physical delivery risks outside of our control.

During 2005, we have seen increases in the market for capacity-related products from our peaking and intermediate generation facilities. We benefited from the operation of all of our peaking plants during the summer

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months of 2005. During the first nine months of 2005, our Midwest peaking plants have generated over 600% 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 the 2005 MISO implementation.

In the Northeast region, we expect prices and spreads to continue to be high. As a result, we expect year-to-year increased runtime in the first half of 2006, particularly at our Roseton facility. Our results are also dependent on our ability to maintain coal and oil deliveries to the facilities. While we have experienced some coal and oil transportation delays, we have accumulated sufficient inventory and contractual commitments to provide us with a stable fuel supply. Additionally, our results could be affected by potential changes in New York state environmental regulations, as well as our ability to obtain permits necessary for the operation of our facilities.

In Texas, we entered into an agreement on September 6, 2005 to extend the steam and energy sales component of an ongoing relationship to sell up to approximately 70 MWs of energy and 2 million pounds per hour of steam from our CoGen Lyondell cogeneration facility to Lyondell Chemical Company (“LCC”) for an initial term from January 2007 through December 2021 and subsequent automatic rollover terms of two years each thereafter through December 2046. Expected incremental annual operating income of approximately $30 million for the ERCOT region beyond 2006 is associated primarily with this contract, which allows us to recover our operating costs and reduces our exposure to market price volatility in the Texas region.

With respect to our equity investment in West Coast Power, our results will be affected by our ability to enter into contractual agreements which will allow us to recover the cost of operating our facilities. All West Coast Power units, except the El Segundo units and Encina (Cabrillo I) unit 4, have been re-designated RMR units for 2006 and will operate under RMR agreements with the California ISO. The RMR contracts for the El Segundo units and Encina unit 4 expire December 31, 2005. However, West Coast Power has entered into a power sales agreement with a major California utility for the sale of 100% of the capacity and associated energy from the El Segundo facility from May 2006 through April 2008. The revenues from this agreement are expected to at least offset revenues that El Segundo could have otherwise received under an RMR agreement. Please see 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.

NGL Outlook. On October 31, 2005, we consummated the sale of DMSLP, which comprised substantially all of the operations of our NGL segment, to Targa Resources, Inc. and two of its subsidiaries. Please see Note 2— Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids.

CRM Outlook. Our CRM business’ future results of operations will be significantly impacted by our ability to complete our exit from this business. Our Sterlington tolling arrangement remains in place through 2017. While we are open to opportunities to assign or renegotiate the terms of this arrangement, we will be selective in comparing strategic alternatives to ensure most appropriate uses of our capital. 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 and excess generation capacity in our Southeast region. 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 further discussion of our annual and long-term obligations under this arrangements, as well as others which have been mitigated, please see “Disclosure of Contractual Obligations and Contingent Financial Commitments” beginning on page 34 of our Form 10-K and Item 1. Business—Segment Discussion—Customer Risk Management beginning on page 17 of our Form 10-K.

In January 2005, Dynegy completed its 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 7—Related Party Transactions for further discussion. The acquisition transformed the tolling and swap contracts into Dynegy intercompany (and our affiliate) agreements, but did not change our obligations under the toll or its impact on our consolidated financial statements. Other than the reporting of the transactions with Independence as affiliate transactions, we do not anticipate any other material impact to us from the transaction.

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In addition to our Sterlington and Independence tolling arrangements, our CRM business remains a party to certain legacy gas and power transactions, which have been hedged. Due to the nature of physical and financial settlements, there is a timing difference between when cash is collected and paid. Therefore, cash paid out in 2006 and 2007 to meet physical market obligations will have been largely offset by cash collected in prior periods from financial hedges.

Cash Flow Disclosures

The following table presents operating cash flows by reportable segment and includes cash flows from our discontinued operations, which are disclosed on a net basis in loss from discontinued operations, net of tax, in the condensed consolidated statements of operations:

	GEN		NGL		CRM			Other and Eliminations			Consolidated
	(in millions)
For the nine months ended September 30, 2005	$	343	$	241	$	(56	)	$	(691	)	$	(163	)
For the nine months ended September 30, 2004	$	351	$	194	$	(179	)	$	(428	)	$	(62	)

Operating Cash Flow. Our cash flow used in operations totaled $163 million for the nine months ended September 30, 2005. During the period, our GEN and NGL segments provided positive cash flow from operations. GEN provided cash flow from operations of $343 million, primarily due to positive earnings for the period as well as the return of cash collateral. This was offset by increases in accounts receivable due to higher prices. NGL provided cash flow from operations of $241 million primarily due to positive earnings for the period as well as the return of cash collateral. Our CRM segment had cash outflows of approximately $56 million, primarily due to fixed payments associated with the power tolling arrangements and our final payment of $26 million related to our exit from four long-term natural gas transportation contracts. This was partially offset by the return of cash collateral. Other and Eliminations includes a use of approximately $691 million in cash primarily due to our payments of $255 million in connection with the settlement of the shareholder class action litigation, interest payments to service debt, pension plan contributions, state tax payments and general and administrative expenses.

Our net cash used in operating activities totaled $62 million for the nine months ended September 30, 2004. During the period, our GEN and NGL segments provided positive cash flow from operations. GEN provided cash flow from operations of $351 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 $194 million due primarily to positive earnings, partially offset by increased prepayments due to higher sales. Our CRM segment used approximately $179 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 a cash payment of $20 million associated with our exit from four long-term natural gas transportation contracts. Other and Eliminations includes a use of approximately $428 million in cash due primarily to interest payments to service debt, settlement payments and general and administrative expenses.

Capital Expenditures and Investing Activities. Cash provided by investing activities during the nine months ended September 30, 2005 totaled $73 million. Capital spending of $132 million was primarily comprised of $87 million and $39 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. Proceeds from asset sales primarily consisted of $10 million due to the sale of land at our Port Everglades facility.

Net cash used in investing activities during the nine months ended September 30, 2004 totaled $150 million. Capital spending of $129 million was comprised primarily of $78 million and $41 million in the GEN and NGL segments, respectively. The capital spending for our GEN segment related primarily to maintenance capital projects, as well as approximately $16 million related to developmental projects. Capital spending in our NGL

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segment related primarily to maintenance capital projects and wellconnects, as well as approximately $15 million on developmental projects. Proceeds from asset sales of $197 million consisted primarily of $132 million from the sale of our equity investments in the Oyster Creek, Hartwell and Michigan Power generating facilities; $48 million from the sale of Indian Basin; and $17 million from the sale of our remaining financial interest in the Hackberry LNG project.

Financing Activities. Cash used in financing activities during the nine months ended September 30, 2005 totaled $36 million. Repayments of long-term debt totaled $23 million for the nine months ended September 30, 2005 and consisted of the following: (i) payments of $18 million on a maturing series of our senior notes and (ii) payments of $5 million on the term loan.

Net cash provided by financing activities during the nine months ended September 30, 2004 totaled $300 million. The cash provided was due primarily to proceeds from our $600 million secured term loan, net of issuance costs of $19 million, which was offset by repayments of long-term debt. Repayments of long-term debt totaled $265 million for the nine months ended September 30, 2004 and consisted of the following: (i) payments of $185 million under our ABG Gas Supply financing and (ii) payments of $78 million on the Tilton capital lease.

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 Nine Months Ended September 30, 2005
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2005	$	(133	)
Risk-management gains recognized through the income statement in the period, net		54
Cash paid related to risk-management contracts settled in the period, net		134
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(134	)
Fair value of portfolio at September 30, 2005	$	(79	)
Income Statement Reconciliation
Risk-management gains recognized through the income statement in the period, net	$	54
Physical business recognized through the income statement in the period, net (3)		(47	)
Non-cash adjustments and other		7
Net recognized operating income	$	14
Cash Flow Statement
Cash paid related to risk-management contracts settled in the period, net	$	(134	)
Estimated cash paid related to physical business settled in the period, net (3)		(47	)
Timing and other, net (4)		99
Cash paid during the period	$	(82	)
Risk-management cash flow adjustment for the nine months ended September 30, 2005 (5)	$	(96	)

(1) Our modeling methodology has been consistently applied.

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

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

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

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

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The net risk management liability of $79 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 September 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(2)			2006			2007			2008			2009			Thereafter
	(in millions)
September 30, 2005	$	(13	)	$	(24	)	$	19		$	(41	)	$	(8	)	$	3		$	38
December 31, 2004		(96	)		(7	)		(8	)		(48	)		(21	)		(10	)		(2	)
Increase	$	83		$	(17	)	$	27		$	7		$	13		$	13		$	40

(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 September 30, 2005 of $79 million on the unaudited condensed consolidated balance sheets include the $13 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2) Amounts represent October 1 to December 31, 2005 values in the September 30, 2005 row and January 1 to December 31, 2005 values in the December 31, 2004 row.

Cash Flow Components of Net Risk-Management Assets

	Nine Months Ended September 30, 2005		Three Months Ended December 31, 2005			Total 2005			2006			2007			2008			2009			Thereafter
	(in millions)
September 30, 2005 (1)	$	38	$	(25	)	$	13		$	24		$	(42	)	$	(9	)	$	1		$	4
December 31, 2004							(5	)		(7	)		(51	)		(23	)		(12	)		(1	)
Increase						$	18		$	31		$	9		$	14		$	13		$	5

(1) The cash flow values for 2005 reflect realized cash flows for the nine months ended September 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.

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The following table provides an assessment of net contract values by year as of September 30, 2005, based on our valuation methodology.

Net Fair Value of Risk-Management Portfolio

	Total			2005			2006		2007			2008			2009		Thereafter
	(in millions)
Market Quotations (1)	$	(50	)	$	(24	)	$	19	$	(41	)	$	(8	)	$	1	$	3
Prices Based on Models		37			—			—		—			—			2		35
Total	$	(13	)	$	(24	)	$	19	$	(41	)	$	(8	)	$	3	$	38

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

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q 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 capture opportunities presented by rising commodity prices;

• our ability to achieve fuel-related and other targeted cost savings;

• 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 with industry participants;

• our ability to build coal and fuel oil inventories;

• our ability to decrease the sale of energy products through forward sales or similar transactions;

• beliefs about the pricing market;

• 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;

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• beliefs about the expected incremental annual operating income for the ERCOT region for 2006;

• the effects of the DMSLP disposition;

• 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, the volatility 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;”

• the effects of industry-wide increases in labor and benefit costs;

• the effects of hedge ineffectiveness;

• the effects of competition in our business line;

• our ability to use the proceeds from the sale of DMSLP in a manner that achieves our financial goals;

• the availability of, and our ability to strengthen our position as an independent power producer, attract private equity capital to the business or consolidate or participate in a strategic combination opportunity 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 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;

• 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 liability management strategies and procedures and the ability of our counterparties to satisfy their financial commitments;

• deviations from expected energy purchases by our capacity customers;

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

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• our ability to conserve coal selectively;

• the availability and the cost of fuel;

• operational factors affecting the start up or ongoing commercial operations of our power generation facilities, including catastrophic weather-related damage, regulatory approvals, physical delivery risks, 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, mainly limited to maintenance, safety, environmental and reliability projects, and costs (including general and administrative expenses) tightly, and generate earnings and cash flow from our business in relation to our substantial debt and other obligations;

• our ability to control costs through disciplined management and safe efficient operations;

• 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 73 of our Form 10-K;

• regulatory or legislative developments that affect the demand and pricing for energy generally, increase the environmental compliance cost for our facilities, ability to maintain permits 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 business, 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.

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RECENT ACCOUNTING PRONOUNCEMENTS

See Note 1 to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us.

CRITICAL ACCOUNTING POLICIES

Please see “Critical Accounting Policies” beginning on page 62 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.

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Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please see Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on page 70 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 September 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

	September 30, 2005		December 31, 2004
	(in millions)
One Day VaR—95% Confidence Level	$	7	$	5
One Day VaR—99% Confidence Level	$	10	$	7
Average VaR for the Year-to-Date Period—95% Confidence Level	$	5	$	4

Credit Risk. The following table represents our credit exposure at September 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	$	238	$	—	$	238
Commercial/Industrial/End Users		81		35		116
Utility and Power Generators		47		24		71
Oil and Gas Producers		7		—		7
Total	$	373	$	59	$	432

Of the $59 million in credit exposure to non-investment grade counterparties, approximately 58% is collateralized or subject to other credit exposure protection. The $24 million in non-investment grade quality credit exposure is with Independence, which is one of our affiliates.

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of September 30, 2005, our fixed rate debt instruments as a percentage of total debt instruments was approximately 69%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of September 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 September 30, 2006 would either decrease or increase income before taxes by approximately $15.3 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.

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Derivative Contracts. The notional financial contract amounts associated with our commodity risk-management, interest rate and foreign currency exchange contracts were as follows at September 30, 2005 and December 31, 2004, respectively:

Notional Contract Amounts

	September 30, 2005		December 31, 2004
Natural Gas (Trillion Cubic Feet)		0.543		1.084
Electricity (Million Megawatt Hours)		26.924		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 third quarter 2005, an evaluation was carried out under the supervision and with the participation of our management and the management of Dynegy, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprise’s 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 Dynegy’s disclosure committee in an effort to ensure that information required to be disclosed in the consolidated entity’s 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 third quarter 2005 relating to our participation in Dynegy’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Finally, this evaluation considered the material weaknesses in tax accounting and tax reconciliation processes, procedures and controls disclosed by Dynegy in Item 9A of its 2004 Form 10-K beginning on page 85 and the resulting ineffectiveness of Dynegy’s disclosure controls and procedures and internal control over financial reporting as of the end of the third quarter 2005.

Based on this evaluation, our CEO and CFO concluded that, as of September 30, 2005, as a result of (i) Dynegy’s material weakness and resulting ineffective disclosure controls and procedures referenced above and (ii) 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 nine-month periods ended September 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–Changes in Internal Control beginning on page 74 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 the consolidated entity’s 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

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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.

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DYNEGY HOLDINGS INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

See Note 8 to the accompanying unaudited condensed consolidated financial statements for discussion of the material legal proceedings to which we are a party.

Item 6—EXHIBITS

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

10.1	Partnership Interest Purchase Agreement dated as of August 2, 2005 among Dynegy Inc, Dynegy Holdings Inc., Dynegy Midstream Holdings, Inc., and Dynegy Midstream G.P., Inc. as Sellers and Targa Resources, Inc., Targa Resources Partners OLP LP, and Targa Midstream GP, LLC as Buyers (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.2	Steam and Electric Power Sales Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.3	Services Agreement for CLI Facility dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.4	Amended and Restated Lease and Easement Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.5	Guaranty Agreement dated as of September 6, 2005 by Dynegy Holdings Inc. on behalf of Cogen Lyondell, Inc. in favor of Lyondell Chemical Company (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.6	Second Amended and Restated Credit Agreement dated as of October 31, 2005 among Dynegy Holdings Inc., as Borrower, and Dynegy Inc., as Parent Guarantor (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, 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.

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*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.

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DYNEGY HOLDINGS 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 HOLDINGS INC.
Date: November 14, 2005	By:	/s/    NICK J. CARUSO
		Nick J. Caruso
		Executive Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

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EXHIBIT INDEX

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

10.1	Partnership Interest Purchase Agreement dated as of August 2, 2005 among Dynegy Inc, Dynegy Holdings Inc., Dynegy Midstream Holdings, Inc., and Dynegy Midstream G.P., Inc. as Sellers and Targa Resources, Inc., Targa Resources Partners OLP LP, and Targa Midstream GP, LLC as Buyers (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.2	Steam and Electric Power Sales Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.3	Services Agreement for CLI Facility dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.4	Amended and Restated Lease and Easement Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.5	Guaranty Agreement dated as of September 6, 2005 by Dynegy Holdings Inc. on behalf of Cogen Lyondell, Inc. in favor of Lyondell Chemical Company (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q for the Quarter Ended September 30, 2005 of Dynegy Inc., File No. 1-15659).
10.6	Second Amended and Restated Credit Agreement dated as of October 31, 2005 among Dynegy Holdings Inc., as Borrower, and Dynegy Inc., as Parent Guarantor (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, 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.

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