Edgar Filing: DYNEGY INC /IL/

Amendment No. 1 for Form 10-Q for quarter ending September 30, 2005

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

Amendment No. 1

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: 1-15659

DYNEGY INC.

(Exact name of registrant as specified in its charter)


Illinois		74-2928353
(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 x No ¨

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: Class A common stock, no par value per share, 304,810,628 shares outstanding as of November 4, 2005; Class B common stock, no par value per share, 96,891,014 shares outstanding as of November 4, 2005.

DYNEGY INC.

TABLE OF CONTENTS


		Page
PART I. FINANCIAL INFORMATION

Item 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (unaudited):

Condensed Consolidated Balance Sheets (Restated): September 30, 2005 and December 31, 2004		4
Condensed Consolidated Statements of Operations: For the three and nine months ended September 30, 2005 (Restated) and 2004		5
Condensed Consolidated Statements of Cash Flows: For the nine months ended September 30, 2005 (Restated) and 2004		6
Condensed Consolidated Statements of Comprehensive Income (Loss): For the three and nine months ended September 30, 2005 (Restated) and 2004		7
Notes to Condensed Consolidated Financial Statements		8

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		47
Item 4. CONTROLS AND PROCEDURES		81

PART II. OTHER INFORMATION
Item 6. EXHIBITS		83

DYNEGY INC. FORM 10-Q/A

INTRODUCTORY NOTE

Dynegy Inc. is filing this Amendment No. 1 on Form 10-Q/A (“Amendment No. 1”) to reflect the effect of a $13 million decrease to our income from discontinued operations for the nine months ended September 30, 2005 and a $13 million increase to our net deferred tax liability at September 30, 2005 on our historical consolidated financial statements and related information, as reported in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, which was originally filed on November 9, 2005 (the “Original Filing”).

The aforementioned item includes items previously announced by us in our Current Report on Form 8-K dated May 1, 2006 and is discussed in more detail in the Explanatory Note to the accompanying unaudited condensed consolidated financial statements. This Amendment No. 1 also reflects restatements made to our unaudited condensed consolidated balance sheet as of September 30, 2005 and December 31, 2004 as further discussed in the Explanatory Note beginning on page F-10 of our Form 10-K for the year ended December 31, 2005. The following items of the Original Filing are amended by this Amendment No. 1:

Item 1. Condensed Consolidated Financial Statements

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 4. Controls and Procedures

Item 6. Exhibits

Unaffected items have not been repeated in this Amendment No. 1.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER THE DATE OF THE ORIGINAL FILING, WITH THE EXCEPTION OF THE ITEM DISCUSSED ABOVE. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR ANNUAL REPORT ON FORM 10-K FOR THE PERIOD ENDED DECEMBER 31, 2005 AND OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE NOVEMBER 9, 2005.

DEFINITIONS

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


ARB		Accounting Research Bulletin
ARO		Asset retirement obligation
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
CUSA		Chevron U.S.A. Inc., a wholly owned subsidiary of Chevron Corporation
DGC		Dynegy Global Communications
DHI		Dynegy Holdings Inc., our primary financing subsidiary
DMG		Dynegy Midwest Generation, Inc.
DMS		Dynegy Midstream Services
DMSLP		Dynegy Midstream Services, Limited Partnership
DNE		Dynegy Northeast Generation
DPM		Dynegy Power Marketing Inc.
EITF		Emerging Issues Task Force
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas, Inc.
ERISA		The Employee Retirement Income Security Act of 1974, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FIN		FASB Interpretation
GAAP		Generally Accepted Accounting Principles of the United States of America
GCF		Gulf Coast Fractionators
GEN		Our power generation business segment
ICC		Illinois Commerce Commission
ISO		Independent System Operator
KW—yr		Kilowatt year
KWh		Kilowatt hour
LNG		Liquefied natural gas
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
Original Filing		Quarterly Report on Form 10-Q for the quarter ended September 30, 2005, filed on November 9, 2005
PJM		PJM Interconnection, LLC
POL		Percentage of liquids
POP		Percentage of proceeds
PRB		Powder River Basin coal
REG		Our regulated energy delivery business segment
RMR		Reliability Must Run
RTO		Regional Transmission Organization
SEC		U.S. Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SPDES		State Pollutant Discharge Elimination System
SPE		Special Purpose Entity
SPN		Second Priority Notes
VaR		Value at Risk
VEBA		Voluntary Employees’ Benefit Association
VESCO		Venice Energy Services Company, LLC
VIE		Variable Interest Entity

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

See Explanatory Note

(unaudited) (in millions, except share data)


	September 30, 2005			December 31, 2004
	(Restated)
ASSETS
Current Assets
Cash and cash equivalents	$	187		$	628
Restricted cash		72			—
Accounts receivable, net of allowance for doubtful accounts of $158 and $159, respectively		634			810
Accounts receivable, affiliates		12			14
Inventory		172			233
Assets from risk-management activities		1,259			565
Deferred income taxes		750			62
Prepayments and other current assets		279			428
Assets held for sale (Note 3)		518			—

Total Current Assets		3,883			2,740

Property, Plant and Equipment		6,478			7,822
Accumulated depreciation		(1,136	)		(1,692	)

Property, Plant and Equipment, Net		5,342			6,130
Other Assets
Unconsolidated investments		291			421
Restricted investments		84			—
Intangible assets		403			—
Assets from risk-management activities		283			313
Goodwill		—			15
Deferred income taxes		16			15
Other long-term assets		178			209
Assets held for sale (Note 3)		1,171			—

Total Assets	$	11,651		$	9,843

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	468		$	561
Accounts payable, affiliates		15			23
Accrued interest		123			118
Accrued liabilities and other current liabilities		277			450
Liabilities from risk-management activities		1,316			616
Notes payable and current portion of long-term debt		77			34
Liabilities held for sale (Note 3)		251			—

Total Current Liabilities		2,527			1,802

Long-term debt		4,824			4,132
Long-term debt to affiliates		200			200

Long-Term Debt		5,024			4,332
Other Liabilities
Liabilities from risk-management activities		329			395
Deferred income taxes		1,046			499
Other long-term liabilities		388			353
Liabilities held for sale (Note 3)		19			—

Total Liabilities		9,333			7,381

Minority Interest		107			106
Commitments and Contingencies (Note 10)
Redeemable Preferred Securities, redemption value of $400 at September 30, 2005 and December 31, 2004, respectively		400			400
Stockholders’ Equity
Class A Common Stock, no par value, 900,000,000 shares authorized at September 30, 2005 and December 31, 2004; 304,595,236 and 285,012,203 shares issued and outstanding at September 30, 2005 and December 31, 2004, respectively		2,947			2,859
Class B Common Stock, no par value, 360,000,000 shares authorized at September 30, 2005 and December 31, 2004; 96,891,014 shares issued and outstanding at September 30, 2005 and December 31, 2004		1,006			1,006
Additional paid-in capital		48			41
Subscriptions receivable		(8	)		(8	)
Accumulated other comprehensive loss, net of tax		(28	)		(13	)
Accumulated deficit		(2,086	)		(1,861	)
Treasury stock, at cost, 1,686,715 shares at September 30, 2005 and 1,679,183 shares at December 31, 2004		(68	)		(68	)

Total Stockholders’ Equity		1,811			1,956

Total Liabilities and Stockholders’ Equity	$	11,651		$	9,843

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

See Explanatory Note

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2005			2004			2005			2004
							(Restated)
Revenues	$	770		$	668		$	1,691		$	2,124
Cost of sales, exclusive of depreciation shown separately below		(572	)		(443	)		(1,482	)		(1,432	)
Depreciation and amortization expense		(56	)		(58	)		(165	)		(183	)
Impairment and other charges		—			(3	)		(6	)		(78	)
Loss on sale of assets, net		(1	)		(24	)		(1	)		(39	)
General and administrative expenses		(76	)		(75	)		(421	)		(231	)

Operating income (loss)		65			65			(384	)		161
Earnings from unconsolidated investments		7			99			14			187
Interest expense		(99	)		(115	)		(284	)		(386	)
Other income and expense, net		—			3			9			10
Minority interest expense		—			(3	)		—			(4	)

Income (loss) from continuing operations before income taxes		(27	)		49			(645	)		(32	)
Income tax benefit (expense) (Note 13)		13			(7	)		228			75

Income (loss) from continuing operations		(14	)		42			(417	)		43
Income from discontinued operations, net of tax benefit (expense) of $(26), $(24), $54, and $(102), respectively (Notes 3 and 13)		43			36			209			113

Net income (loss)		29			78			(208	)		156
Less: preferred stock dividends		6			6			17			17

Net income (loss) applicable to common stockholders	$	23		$	72		$	(225	)	$	139

Earnings (Loss) Per Share (Note 9):
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	(0.05	)	$	0.10		$	(1.13	)	$	0.07
Income from discontinued operations		0.11			0.09			0.54			0.30

Basic earnings (loss) per share	$	0.06		$	0.19		$	(0.59	)	$	0.37

Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	(0.05	)	$	0.09		$	(1.13	)	$	0.07
Income from discontinued operations		0.11			0.07			0.54			0.30

Diluted earnings (loss) per share	$	0.06		$	0.16		$	(0.59	)	$	0.37

Basic shares outstanding		390			379			383			378
Diluted shares outstanding		516			504			509			380

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

See Explanatory Note

(unaudited) (in millions)


	Nine Months Ended September 30,
	2005			2004
	(Restated)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(208	)	$	156
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		212			279
Impairment and other charges		(1	)		83
Earnings from unconsolidated investments, net of cash distributions		47			(82	)
Risk-management activities		(11	)		(24	)
Gain on sale of assets, net		(9	)		(14	)
Deferred income taxes		(284	)		27
Liability associated with gas transportation contracts (Note 3)		—			(148	)
Legal and settlement charges		110			—
Independence toll settlement charge		169			—
Other		13			8
Changes in working capital:
Accounts receivable		(199	)		150
Inventory		(9	)		(70	)
Prepayments and other assets		101			(125	)
Accounts payable and accrued liabilities		(113	)		(123	)
Changes in non-current assets		(4	)		(17	)
Changes in non-current liabilities		8			20

Net cash provided by (used in) operating activities		(178	)		120

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(132	)		(221	)
Proceeds from asset sales, net		106			527
Business acquisition costs, net of cash acquired		(120	)		—

Net cash provided by (used in) investing activities		(146	)		306

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from long-term borrowings		—			588
Repayments of long-term borrowings		(40	)		(520	)
Proceeds from issuance of capital stock		2			5
Dividends and other distributions, net		(22	)		(22	)
Other financing, net		(39	)		(27	)

Net cash provided by (used in) financing activities		(99	)		24

Effect of exchange rate changes on cash		—			(1	)
Net increase (decrease) in cash and cash equivalents		(423	)		449
Cash and cash equivalents, beginning of period		628			477
Less: Cash classified as held for sale at end of period (Note 3)		(18	)		—

Cash and cash equivalents, end of period	$	187		$	926

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

See Explanatory Note

(unaudited) (in millions)


	Three Months Ended September 30,
	2005			2004
Net income	$	29		$	78
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 $23, respectively)		—			39

Other comprehensive income (loss), net of tax		(5	)		42

Comprehensive income	$	24		$	120


	Nine Months Ended September 30,
	2005			2004
	(Restated)
Net income (loss)	$	(208	)	$	156
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 $24, respectively)		—			41

Other comprehensive loss, net of tax		(15	)		(4	)

Comprehensive income (loss)	$	(223	)	$	152

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

PLEASE NOTE THAT THESE FINANCIAL STATEMENTS AND THE NOTES THERETO DO NOT REFLECT EVENTS OCCURRING AFTER NOVEMBER 9, 2005 (THE DATE OF THE ORIGINAL FILING) WITH THE EXCEPTION OF THE ITEM DISCUSSED IN THE EXPLANATORY NOTE BELOW. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE NOVEMBER 9, 2005.

EXPLANATORY NOTE

This Amendment No. 1 to our Quarterly Report on Form 10-Q for the period ended September 30, 2005 includes a restatement of our unaudited condensed consolidated financial statements for the nine month period ended September 30, 2005. The restatement relates to our deferred income tax accounts. In the second quarter 2005, we recognized a $125 million tax benefit in anticipation of our sale of DMSLP. This benefit resulted from a reduction in the valuation allowance related to our capital loss carryforwards expected to be used against capital gains generated by the sale of DMSLP. We recently identified that a portion of the capital loss carryforwards had been previously used and therefore was not available for use against those capital gains. Because we mistakenly used these unavailable capital loss carryforwards against capital gains generated by the sale of DMSLP, income from discontinued operations during the second quarter of 2005 was overstated by $13 million, and the net deferred tax liability was understated by $13 million at September 30, 2005.

The restatement effects Note 1—Accounting Policies, Note 3—Discontinued Operations, Dispositions and Contract Terminations, Note 13—Income Taxes and Note 14—Segment Information. The restatement had no effect on our previously reported loss from continuing operations or net cash provided by (used in) operating activities, investing activities or financing activities for the three and nine months ended September 30, 2005. This Amendment No. 1 also reflects restatements made to our unaudited condensed consolidated balance sheet as of September 30, 2005 and December 31, 2004 as further discussed in the Explanatory Note beginning on page F-10 of our Form 10-K for the year ended December 31, 2005. A synopsis of the aggregate financial impact of these restatements on the amounts originally reported in the Original Filing is as follows:

RESTATED SELECTED BALANCE SHEET DATA


	September 30, 2005
	(in millions)
Deferred income taxes
As previously reported	$	(1,131	)
Adjustment (1)		98
Restatement effect		(13	)

As restated	$	(1,046	)

Total Liabilities
As previously reported	$	(9,418	)
Adjustment (1)		98
Restatement effect		(13	)

As restated	$	(9,333	)

Stockholders’ Equity
As previously reported	$	(1,735	)
Adjustment (1)		(89	)
Restatement effect		13

As restated	$	(1,811	)

(1)	Adjustment relates to a prior restatement of the deferred tax liability balances, as further described in the Explanatory Note beginning on page F-10 of our Form 10-K for the year ended December 31, 2005.

RESTATED SELECTED RESULTS OF OPERATIONS DATA


	Three Months Ended September 30, 2005		Nine Months Ended September 30, 2005
	(in millions)
Income from discontinued operations
As previously reported	$	43	$	222
Restatement effect		—		(13	)

As restated	$	43	$	209

Net income (loss)
As previously reported	$	29	$	(195	)
Restatement effect		—		(13	)

As restated	$	29	$	(208	)

Net income (loss) applicable to common shareholders
As previously reported	$	23	$	(212	)
Restatement effect		—		(13	)

As restated	$	23	$	(225	)

Net income (loss) per diluted share
As previously reported	$	0.06	$	(0.55	)
Restatement effect		—		(0.04	)

As restated	$	0.06	$	(0.59	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Note 1—Accounting Policies

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

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/A 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 3—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 stock-

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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

Had compensation cost for all stock options granted prior to January 1, 2003 been determined on a fair value basis consistent with SFAS No. 123, our net income (loss) and basic and diluted earnings (loss) per share amounts would have approximated the following pro forma amounts for the three- and 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	$	29		$	78		$	(208	)	$	156
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	)		(6	)		(5	)		(22	)

Pro forma net income (loss)	$	29		$	73		$	(208	)	$	137

Earnings (loss) per share:
Basic—as reported	$	0.06		$	0.19		$	(0.59	)	$	0.37
Basic—pro forma	$	0.06		$	0.18		$	(0.59	)	$	0.32
Diluted—as reported	$	0.06		$	0.16		$	(0.59	)	$	0.37
Diluted—pro forma	$	0.06		$	0.15		$	(0.59	)	$	0.28

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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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 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.

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

With regard to the four natural gas-fired merchant facilities located in New York, we had the option to elect to decommission any or all of these facilities within a 180-day period after the January 31, 2005 closing date. Prior to expiration of the option period, which ended on July 30, 2005, we elected to decommission all four of the natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon will direct the decommissioning, sale, or other disposal of the facilities. Further, Exelon is obligated to indemnify us with respect to all operations prior to February 1, 2005, and subsequent to our election to decommission or sell the facilities and must provide written consent for any payments or actions outside the ordinary course of operations. On June 1 and August 4, 2005, we entered into agreements, as directed by Exelon, to sell our ownership and operating interests in the four natural gas-fired power generation peaking facilities to Alliance Energy Group LLC. The transactions, which were approved by the FERC and the New York Public Service Commission, closed on October 31, 2005 and had no impact on our unaudited condensed consolidated financial statements, as Exelon received the proceeds from the sale. As a result of the rights retained by Exelon with respect to these facilities, we are not the primary beneficiary of these VIEs, and have not consolidated them in accordance with the provisions of FIN No. 46(R). Please see Note 2—Acquisition—Sithe Energies for further discussion regarding this acquisition.

The hydroelectric generation facilities have commitments and obligations that are off-balance sheet with respect to Dynegy arising under operating leases for equipment and long-term power purchase agreements with local utilities. As of September 30, 2005, the equipment leases have remaining terms from two to sixteen years and involve future lease payments of $131 million over the terms of the leases. Additionally, each of these facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account, which we refer to as the “Tracking Account,” was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. Two of the four hydroelectric facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs, exclusive of lease or interest costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of September 30, 2005 was approximately $255 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts may cause the facilities to operate at a net cash deficit. As discussed above, the obligations of the four hydroelectric facilities are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of these facilities.

Accounting Principles Not Yet Adopted

SFAS No. 123(R). In December 2004, the FASB issued SFAS No. 123(R), “Share-Based Payment,” which revises SFAS No. 123. SFAS No. 123(R) is effective for January 1, 2006 for all calendar year-end companies. SFAS No. 123(R) requires companies to expense the fair value of employee stock options and other forms of stock-based compensation. We expect to adopt the provisions of SFAS No. 123(R) on January 1, 2006. SFAS No. 123(R) describes several transition methods, and we expect to apply the modified prospective method of adoption. Under this method, compensation expense will be recognized for the remaining portion of outstanding, unvested awards at the date of adoption.

As noted in “Employee Stock Options” above, 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—Acquisition

Sithe Energies. On January 31, 2005, we acquired 100% of the outstanding common shares of ExRes, the parent company of Sithe Energies and Independence. The results of the operations of ExRes have been included in our consolidated financial statements since that date. Through this acquisition, we acquired the 1,021 MW Independence power generation facility located near Scriba, New York, as well as four natural gas-fired merchant facilities in New York and four hydroelectric generation facilities in Pennsylvania. We have not consolidated the entities that own these four natural gas-fired facilities and four hydroelectric generation facilities, in accordance with the provisions of FIN No. 46(R). See Note 1—Accounting Policies—Accounting Principle Adopted—FIN No. 46(R) for additional discussion of these facilities. In addition to these power plants, we acquired the 750 MW firm capacity sales agreement between Independence and Con Edison, a subsidiary of Consolidated Edison, Inc. This agreement, which runs through 2014, will provide us with annual cash receipts of approximately $100 million, subject to the restrictions on distribution under Independence’s indebtedness. Independence holds power tolling,

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

financial swap and other contracts with other Dynegy subsidiaries. As a result of the acquisition, these contracts have become intercompany agreements, and their financial statement impact has been substantially eliminated. This transaction enabled us to address one of our outstanding power tolling arrangements and to expand our generation capacity in a market where we have an existing presence.

The aggregate purchase price was comprised of (i) $135 million cash, which was reduced by a purchase price adjustment of approximately $2 million; (ii) transaction costs of approximately $16 million, approximately $3 million of which were paid in 2004 and (iii) the assumption of $919 million of face value project debt, which was recorded at its fair value of $797 million as of January 31, 2005. Please see Note 7—Debt—Independence Debt for additional information regarding the debt assumed.

The allocation of purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques. The acquisition resulted in an excess of the fair value of assets acquired over cost of the acquisition. This excess was then allocated to property plant and equipment and intangible assets acquired, including intangibles arising from contracts with us, on a pro-rata basis. The following table summarizes the fair values of the assets and liabilities acquired at the date of acquisition, January 31, 2005 (in millions):


Other current assets	$	87
Restricted cash and investments		132
Property, plant and equipment		350
Assets from risk-management activities		62
Intangible assets		654

Total assets acquired	$	1,285

Current liabilities	$	(96	)
Deferred income taxes		(184	)
Other long-term liabilities		(59	)
Long-term debt		(797	)

Total liabilities assumed	$	(1,136	)

Net assets acquired	$	149

Included in the assets acquired are restricted cash and investments of approximately $132 million. The restricted investments include Federal Home Loan Bank Bonds, U.S. Treasury Bonds, and high-grade short-term commercial paper. The restricted cash and investments are related to a sinking fund required by Independence’s debt instruments, including a major overhaul reserve, a debt service reserve, a principal payment reserve, an interest reserve and a project restoration reserve. Restrictions on the cash and investments are scheduled to be lifted at the end of the project financing term in 2014. For further discussion, please see Note 7—Debt—Independence Debt.

Of the $654 million of acquired intangible assets, $485 million was allocated to the firm capacity sales agreement with Con Edison. This asset will be amortized on a straight-line basis over the ten-year remaining life of the contract as a reduction to revenue in our unaudited condensed consolidated statements of operations, through October 2014. In addition, Independence holds a power tolling contract, and a gas supply agreement with another of our subsidiaries, which were valued at $153 million and $16 million, respectively, as of January 31, 2005. Upon completion of our purchase of Independence, the power tolling agreement and the gas supply agreement were effectively settled, which resulted in a 2005 charge equal to their fair values, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination.”

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

As a result, we recorded a first quarter 2005 pre-tax charge of $183 million, which is included in cost of sales on our unaudited condensed consolidated statements of operations. In the three and nine months ended September 30, 2005, we revised the determination of the tax basis of the assets and liabilities acquired, and revised our purchase price allocation, resulting in additional excess of the fair value of the assets acquired over the cost of the acquisition. Accordingly, in the three and nine months ended September 30, 2005, we reversed $1 million and $14 million of the $183 million pre-tax charge recorded in the first quarter, resulting in a net pre-tax charge of $169 million for the nine months ended September 30, 2005 in accordance with EITF Issue 04-01. As a result, we made revisions to our deferred income taxes ($85 million decrease to liabilities), intangible assets ($55 million decrease to assets), and property, plant and equipment balances ($30 million decrease to assets). Upon settlement of the power tolling and gas supply agreements, the firm capacity sales agreement with Con Edison is the only remaining intangible asset associated with the acquisition of ExRes, which is included in intangibles and prepaids and other current assets on our unaudited condensed consolidated balance sheets.

We have exercised our right to require Exelon to decommission, sell, or otherwise dispose of all four natural gas-fired merchant facilities owned by ExRes. Under the terms of the purchase agreement, Exelon will direct the disposition of these facilities, and will indemnify us with respect to all past and present operations. On June 1 and August 4, 2005 we entered into agreements, as directed by Exelon, to sell our ownership and operating interests in the four natural gas-fired power generation peaking facilities in upstate New York to Alliance Energy Group LLC, which includes our 80% interest in an 84 MW plant in Massena and our 85% interest in an 83 MW plant in Ogdensburg. The transactions, which were approved by the FERC and the New York Public Service Commission, closed on October 31, 2005 and had no impact on our unaudited condensed consolidated financial statements as Exelon received the proceeds from the sale. Further, Exelon is entitled to cause us to decommission, sell, or bankrupt any or all of the four hydroelectric facilities owned by ExRes, for which we have been indemnified for any losses.

Note 3— Discontinued Operations, Dispositions and Contract Terminations

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

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 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 7—Debt—DMSLP for a discussion of the permitted use of proceeds.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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 13—Income Taxes—Balance Sheet Classification.

SFAS No. 144 also requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of NGL’s property, plant and equipment, effective June 1, 2005. Depreciation and amortization expense related to NGL totaled $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.

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 13—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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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 communications business and our U.K. CRM business, which have been accounted for as discontinued operations under SFAS No. 144.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

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			DGC			NGL		Total
Three Months Ended September 30, 2005
Revenue	$	—		$	—		$	1,193	$	1,193
Income (loss) from operations before taxes		(2	)		—			71		69
Income (loss) from operations after taxes		(4	)		(2	)		49		43
Three Months Ended September 30, 2004
Revenue	$	—		$	—		$	996	$	996
Income (loss) 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 (loss) from operations after taxes		(1	)		—			210		209
Nine Months Ended September 30, 2004
Revenue	$	—		$	—		$	2,663	$	2,663
Income from operations before taxes		17			3			195		215
Income (loss) from operations after taxes		(9	)		2			120		113

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 currency 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 5—Risk Management Activities and Accumulated Other Comprehensive Loss—Net Investment Hedges in Foreign Operations for further discussion. Also in the first quarter 2004, we recognized $3 million of pre-tax income associated with DGC’s receipt of $3 million from a third party in settlement of a prior contractual claim. In the second quarter 2004, we recognized a tax expense of $20 million in U.K. CRM related to charges resulting from the conclusion of prior year tax audits. Please see Note 13—Income Taxes—Prior Year Tax Audits for further discussion.

Dispositions and Contract Terminations

Sale of Illinois Power. On September 30, 2004, we sold all of our outstanding common and preferred shares of Illinois Power Company, which formerly comprised our REG segment, as well as our 20% interest in the Joppa power generation facility, to Ameren Corporation for $2.3 billion. The $2.3 billion sale price consisted of Ameren’s assumption of $1.8 billion of Illinois Power’s debt and preferred stock obligations, cash proceeds of approximately $375 million and an additional $100 million of cash placed in escrow, which we received on July 27, 2005.

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Further, on September 30, 2004, we entered into a two-year power purchase agreement with Illinois Power, now known as AmerenIP. Under the terms of this agreement, which became effective January 1, 2005, we have agreed to provide Illinois Power with up to 2,800 MWs of capacity at $48 per KW-yr and up to 11.5 million MWh of energy each year at a fixed price of $30 per MWh. We also agreed to sell 300 MW of capacity in 2005 and 150 MW of capacity in 2006 to Illinois Power at a fixed price of $16 per KW-yr with an option to purchase energy at market-based prices.

During the first quarter 2004, Illinois Power met the held for sale classification requirements of SFAS No. 144, and continued to meet the requirements through the closing of the sale on September 30, 2004. SFAS No. 144 requires that long-lived assets not be depreciated or amortized while they are classified as held for sale. As such, we discontinued depreciation and amortization of Illinois Power’s property, plant and equipment and regulatory assets, effective February 1, 2004. Depreciation and amortization expense related to Illinois Power totaled $10 million in the nine-month period ended September 30, 2004. In addition, SFAS No. 144 requires a loss to be recognized in the amount by which assets held for sale less liabilities held for sale are in excess of fair value less costs to sell. Accordingly, for the three-month periods ended March 31, 2004 and June 30, 2004, we recorded pre-tax losses on the sale of $21 million and $48 million, respectively. The first quarter charge, which was primarily associated with the expected transaction costs and an impairment of assets, is reflected in Loss on sale of assets, net, and Impairment and other charges on the unaudited condensed consolidated statements of operations. The second quarter charge is reflected in Impairments and other charges on our unaudited condensed consolidated statements of operations. Finally, in the three month period ended September 30, 2004, we recorded a pre-tax loss on the sale of $24 million. The change is reflected in Loss on sale of assets, net on the unaudited condensed consolidated statements of operations.

Further, pursuant to SFAS No. 144, we are not reporting the results of Illinois Power’s operations as a discontinued operation. If we were to account for Illinois Power as a discontinued operation, its results of operations would be condensed into income from discontinued operations, net of taxes, on our unaudited condensed consolidated statements of operations, and prior periods would be required to be restated to conform to this presentation. To qualify for discontinued operations classification, SFAS No. 144 and subsequent interpretations, specifically EITF Issue 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations,” require that the seller have no significant continuing involvement with the business being sold. As noted above, we have contracted to sell capacity and energy to Illinois Power for two years beginning in January 2005. Consequently, because we still have significant continuing involvement with Illinois Power, we will continue to include the historical results of Illinois Power’s operations as part of our continuing operations. Additionally, power sales to Illinois Power occurring subsequent to the disposition will be reported in our consolidated statements of operations as third party sales. Approximately $154 million and $337 million of revenues, derived from power sales to Illinois Power occurring subsequent to the disposition, are reflected in our continuing operations for the three and nine-month periods ending September 30, 2005.

Joppa. In the third quarter 2004, we recorded a pre-tax gain of $75 million upon the closing of the sale of our 20% interest in the Joppa power generating facility. The gain is included in Earnings from unconsolidated investments on the unaudited condensed consolidated statements of operations.

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

upon project development milestones. In March 2004, we sold our remaining financial interest in this project, which included rights to future contingent payments under the 2003 agreement, for $17 million and recognized a pre-tax gain of $17 million on the sale. This gain is included in Income from discontinued operations on our unaudited condensed consolidated statements of operations.

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

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

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

Note 4—Restructuring Charges

In the three and nine months ended September 30, 2004, we recorded pre-tax charges relating to our interest in Illinois Power totaling $24 million and $93 million, respectively. For further discussion, please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Dispositions and Contract Terminations—Sale of Illinois Power. In addition, 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

In October 2002, we announced a restructuring plan designed to improve operational efficiencies and performance across our lines of business. The following is a schedule of 2005 activity for the liabilities recorded in connection with this restructuring:


	Severance		Cancellation Fees and Operating Leases			Total
	(in millions)
Balance at December 31, 2004	$	3	$	25		$	28
2005 adjustments to liability		—		(1	)		(1	)
Cash payments		—		(7	)		(7	)

Balance at September 30, 2005	$	3	$	17		$	20

We expect the $17 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 5—Risk Management Activities and Accumulated Other Comprehensive Loss

The nature of our business necessarily involves market and financial risks. We enter into financial instrument contracts in an attempt to mitigate or eliminate these various risks. These risks and our strategy for mitigating them are more fully described in Note 5—Risk Management Activities and Financial Instruments beginning on page F-33 of our Form 10-K.

Cash Flow Hedges. We enter into financial derivative instruments that qualify as cash flow hedges. Instruments related to our GEN and NGL businesses are entered into for purposes of hedging future fuel requirements and sales commitments and locking in future margin.

During the three and 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 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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 stockholders’ 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 stockholders’ equity.

Note 6—Unconsolidated Investments

A summary of our unconsolidated investments is as follows:


	September 30, 2005			December 31, 2004
	(in millions)
Equity affiliates:
GEN investments	$	291		$	337
NGL investments		77			78

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

		368			421
Less: Unconsolidated investments held for sale at end of period		(77	)		—

Total unconsolidated investments	$	291		$	421

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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	$	291	$	102	$	626	$	228
Operating income		56		23		121		50
Net income		51		21		92		39

Earnings from unconsolidated investments of $14 million for the nine months ended September 30, 2005, include the $21 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 $187 million for the nine months ended September 30, 2004, include the $39 million above, $123 million from West Coast Power and gains on the sales of our 20% interest in the Joppa facility, our equity investment in Oyster Creek and our equity investment in Hartwell of $75 million, $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, $7 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.

During the first quarter 2004, we sold our interest in our power generating facility located in Jamaica. Net proceeds associated with the sale were approximately $5.5 million, and we did not recognize a gain or loss on the sale.

In the 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Note 7—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 3—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. Net sale proceeds that are not applied or invested in the manner described above will constitute Excess Proceeds. If the Excess Proceeds exceed $50 million, we must, within 365 days from closing of the sale, offer to repurchase or redeem the SPNs from the holders thereof at a price equal to 100% of the principal amount plus accrued and unpaid interest. If the SPN holders decline pro rata repayment at par, then such proceeds can be used for any other purposes not otherwise restricted by 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 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 $17 million related to the Independence Senior Notes due 2007 and $5 million related to the term loan during the first nine months of 2005.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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.

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

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


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

Total Independence Debt	$	919	$	(122	)	$	797

Principal payments on the Independence senior notes, which we refer to as the “senior debt,” are due semiannually through 2013 and principal payments on the subordinated debt begin in 2015. Annual maturities of the Independence debt, as of September 30, 2005, are as follows: 2005—$17 million; 2006—$37 million; 2007—$40 million; 2008—$44 million; 2009—$57 million; and thereafter—$707 million. The senior debt and subordinated debt are secured by substantially all of the assets of Independence, but are not guaranteed by us or DHI. The difference of $122 million between the face value and the fair value of the Independence Debt that was recognized upon the acquisition of ExRes will be accreted into interest expense over the life of the debt.

The terms of the indenture governing the senior debt, among other things, prohibit cash distributions by Independence to its affiliates, including Dynegy, unless certain project reserve accounts are funded to specified levels and the required debt service coverage ratio is met. The indenture also includes other covenants and restrictions, relating to, among other things, prohibitions on asset dispositions and fundamental changes, reporting requirements and maintenance of insurance. As of September 30, 2005, Independence had current restricted cash of $72 million as reflected on our unaudited condensed consolidated balance sheets. As of September 30, 2005, Independence had short-term and long-term restricted investment balances of $2 million and $84 million, respectively. The restricted investment balances are included in prepayments and other current assets and restricted investments, respectively, on our unaudited condensed consolidated balance sheets.

Note 8—Related Party Transactions

We engage in transactions with Chevron Corporation, which we refer to as “Chevron,” and its affiliates, including purchases and sales of natural gas and natural gas liquids, which we believe are executed on terms that are fair and reasonable. Please see Note 12—Related Party Transactions—Transactions with ChevronTexaco beginning on page F-47 of our Form 10-K for further discussion.

Series C Convertible Preferred Stock. As discussed in Note 14—Redeemable Preferred Securities—Series C Convertible Preferred Stock beginning on page F-54 of our Form 10-K, in August 2003, we issued to CUSA 8 million shares of our Series C convertible preferred stock due 2033, which we refer to as our “Series C preferred

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

stock.” We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. We made semi-annual dividend payments of $11 million in February and August 2005.

Note 9—Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
	(in millions, except per share amounts)
Income (loss) from continuing operations	$	(14	)	$	42	$	(417	)	$	43
Preferred stock dividends		6			6		17			17

Loss from continuing operations for basic loss per share		(20	)		36		(434	)		26
Effect of dilutive securities:
Interest on convertible subordinated debentures (2)		2			2		5			—
Dividends on Series C preferred stock (2)		6			6		17			—

Income (loss) from continuing operations for diluted loss per share	$	(12	)	$	44	$	(412	)	$	26

Basic weighted-average shares		390			379		383			378
Effect of dilutive securities:
Stock options		2			2		2			2
Convertible subordinated debentures (2)		55			54		55			—
Series C preferred stock (2)		69			69		69			—

Diluted weighted-average shares		516			504		509			380

Loss per share from continuing operations:
Basic	$	(0.05	)	$	0.10	$	(1.13	)	$	0.07

Diluted (1)	$	(0.05	)	$	0.09	$	(1.13	)	$	0.07

(1)

When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share,” prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding and the loss from continuing operations for basic loss per share amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2005.

(2)

The diluted shares for the nine months ended September 30, 2004 do not include the effect of the preferential conversion to Class B common stock of the Series C convertible preferred stock held by a Chevron subsidiary and the interest on the convertible subordinated debentures, as such inclusion would be anti-dilutive.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Note 10—Commitments and Contingencies

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

We record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable under SFAS No. 5, “Accounting for Contingencies.” For environmental matters, we record liabilities when remedial efforts are probable and the costs can be reasonably estimated. Please see Note 2—Accounting Policies—Contingencies, Commitments, Guarantees and Indemnifications beginning on page F-16 of our Form 10-K for further discussion of our reserve policies. Environmental reserves do not reflect management’s assessment of the insurance coverage that may be applicable to the matters at issue, whereas litigation reserves do reflect such potential coverage. We cannot make any assurances that the amount of any reserves or potential insurance coverage will be sufficient to cover the cash obligations we might incur as a result of litigation or regulatory proceedings, payment of which could be material.

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

Summary of Recent Developments. As described in greater detail below, the following significant developments involving our material legal proceedings occurred since the filing of our Form 10-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 our shareholder class action litigation. Pursuant to the settlement agreement, we made an aggregate settlement payment of $468 million (consisting of $150 million funded by insurance proceeds, two cash payments by DHI totaling $250 million and the issuance of 17,578,781 shares of Class A common stock). Further, the lead plaintiff agreed to submit a list of at least five qualified director candidates from which we will select two new members for Dynegy’s Board of Directors to replace two directors who were defendants in the litigation.

•

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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

Shareholder Litigation. In April 2005, we settled a class action lawsuit filed on behalf of purchasers of our publicly traded securities from January 2000 to July 2002 seeking unspecified compensatory damages and other relief. The lawsuit as filed principally alleged that we and certain of our current and former officers and directors violated the federal securities laws in connection with our disclosures, including accounting disclosures, regarding Project Alpha (a structured natural gas transaction entered into by us in April 2001), round-trip trading, the submission of false trade reports to publications that calculate natural gas index prices, the alleged manipulation of the California power market and the restatement of our financial statements for 1999-2001. The Regents of the University of California were lead plaintiff and Lerach Coughlin Stoia & Robbins, LLP was class counsel. Reserves were provided in connection with this litigation.

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

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

•

An aggregate settlement payment by Dynegy of $468 million, comprised of a $150 million cash payment funded by insurance proceeds, a $250 million cash payment by DHI, and the issuance to the plaintiffs of $68 million in Dynegy’s Class A common stock, consisting of 17,578,781 shares based on a calculation using a volume weighted average stock price for the 20 trading days ending April 15, 2005. We were required to make two payments totaling $250 million during 2005, consisting of an initial payment of $175 million, which we paid in May 2005, followed by a second payment of $75 million plus interest upon court approval, which we paid in July 2005. The appeal period for the litigation expired on August 8, 2005, and, as required by the settlement, we 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 we will select two new members for Dynegy’s Board of Directors to replace two directors who were defendants in the litigation. We will also nominate such directors for election at our next meeting of shareholders at which directors are elected.

In addition, we were named as a nominal defendant in several derivative lawsuits brought by shareholders on Dynegy’s behalf against certain of our former officers and current and former directors whose claims are similar to those described above. These lawsuits were consolidated into two groups—one pending in federal court and the other pending in Texas state court. In February 2005, the plaintiffs voluntarily dismissed the federal derivative matter. In April 2005, the parties to the shareholder derivative litigation pending in Texas state court reached a settlement, and the court approved the settlement agreement in July 2005. Under this settlement agreement, Dynegy agreed to effect certain corporate governance changes, many of which 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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

approximately $5 million. The ongoing corporate changes relate to director qualifications, the involvement of a lead independent director, the structure and function of certain Board committees and other governance enhancements.

Dynegy and the other defendants did not admit any liability in connection with either of the settlements described above, and there were no findings of any violations of the federal securities laws. We reversed pre-tax charges of $4 million ($3 million after-tax) and recorded pre-tax charges of $236 million ($165 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. The reversal of the pre-tax charge in the three months ended September 30, 2005 is a result of depreciation in our stock price from $4.86 on June 30, 2005 to $4.62 on August 12, 2005, the date on which the settlement shares were issued.

ERISA/Illinois Power 401(k) Litigation. In January 2005, three DMG union employees who are participating in the DMG 401(k) Savings Plan for Employees Covered Under a Collective Bargaining Agreement (formerly known as the Illinois Power Company Incentive Savings Plan For Employees Covered Under a Collective Bargaining Agreement), which we refer to as the “DMG 401(k) Plan,” purporting to represent all DMG and Illinois Power employees who held Dynegy common stock through the DMG 401(k) Plan during the period from February 2000 through the present, filed a lawsuit in federal court in the Southern District of Illinois against us, Illinois Power Company, DMG and several individual defendants. The complaint alleges violations of ERISA in connection with the DMG 401(k) Plan that are similar to the claims made in the ERISA litigation we settled in December 2004, including claims that certain of our former and current officers (who are past and present members of our Benefit Plans Committee) breached their fiduciary duties to the plan’s participants and beneficiaries in connection with the plan’s investment in Dynegy common stock – in particular with respect to our financial statements, Project Alpha, round trip trades and gas price index reporting. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorney’s fees and other costs. Our motion to transfer this litigation to the Southern District of Texas was denied in October 2005. However, our 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 us 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 we settled in December 2004 and the ERISA litigation referenced in the preceding paragraph, including claims that certain of our former and current officers (who are past and present members of our Benefit Plans Committee) breached their fiduciary duties to the plan’s participants and beneficiaries in connection with the plan’s investment in Dynegy common stock – in particular with respect to our financial statements, Project Alpha, round trip trades and gas price index reporting. The lawsuit seeks unspecified damages for the losses to the plan, as well as attorney’s fees and other costs. We are preparing our 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Enron/NNG VEBA Litigation. Prior to our acquisition of NNG from Enron, NNG employees were participants in a post-retirement medical plan maintained by Enron. The plan’s assets were maintained in a VEBA trust, along with the assets of other Enron companies whose plans were included in the same VEBA trust (the “Enron VEBA”). Enron filed for bankruptcy in December 2001. When we acquired NNG in January 2002, the assets of the Enron VEBA had not been distributed to its participant companies, though we and NNG made the appropriate requests for such a distribution. In July 2002, we estimated that approximately $25.4 million of the assets of the Enron VEBA were attributable to the NNG employees who participated in the post-retirement medical plan. On July 1, 2002, as part of our sale of NNG to Mid American Energy Holdings Company, NNG established a separate VEBA trust solely for its plan participants (the “NNG VEBA”). As a condition of the sale agreement, we placed $25.4 million into escrow under terms providing that if Enron did not release NNG’s share of the VEBA assets by August 2004, NNG was entitled to the escrowed money to fund the NNG VEBA. As Enron did not release the funds from the Enron VEBA as of August 2004, NNG placed our escrowed funds into the NNG VEBA. Pursuant to the escrow agreement, once the Enron VEBA releases NNG’s funds to the NNG VEBA, we will be entitled to be reimbursed an equivalent amount, up to $25.4 million.

In June 2005, in accordance with the terms of the escrow agreement, NNG, the NNG VEBA trustee and the NNG VEBA participants as a class filed a class action lawsuit in Nebraska federal court against various Enron related parties, including the individual members of the Enron Benefit Plan Committee, alleging a breach of fiduciary duty under ERISA and seeking immediate disbursement of the Enron VEBA assets. 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 us, even though we 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 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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 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 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.

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

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For the Interim Periods Ended September 30, 2005 and 2004

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 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.

Enron Trade Credit Litigation. Shortly before their bankruptcy filing in the fourth quarter 2001, we determined that Enron Corp. and its affiliates had net exposure to us, including certain liquidated damages and other amounts relating to the termination of commercial transactions among the parties, of approximately $84 million. This exposure was calculated by setting off approximately $230 million owed from Dynegy entities to Enron entities against approximately $314 million owed from Enron entities to Dynegy entities. The master netting agreement between Enron and us and the valuation of the commercial transactions covered by the agreement, which valuation is based principally on the parties’ assessment of market prices for such period, remain subject to dispute. Assuming the master netting agreement is enforceable, we have engaged in an ongoing process with Enron to reconcile the differences between our respective valuations of the transactions and accounts receivable. As a result of ongoing refinement of the values of past transactions, we reduced the $84 million amount that we originally believed we were owed by Enron to approximately $57 million, including the liabilities under the gas transportation

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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. Our 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 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 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,

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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 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 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.

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For the Interim Periods Ended September 30, 2005 and 2004

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.

Stumpf Litigation. We and two former subsidiaries are defendants in a lawsuit filed in New York by Stumpf AG and two of its affiliates stemming from the shutdown of our Vienna telecommunications office in the spring of 2001. The plaintiffs are seeking $29 million in compensatory and unspecified punitive damages, alleging breach of contract, tortious interference and alter ego-based claims primarily relating to the termination of real property leases to which our former Austrian subsidiary was a party. These claims are based on similar lawsuits filed in Austria against our former Austrian subsidiary, which was sold to a third party in January 2003. All of these lawsuits pending in Austria have been stayed. This former subsidiary is in liquidation and one of its liquidators admitted, for purposes of the liquidation, the plaintiffs’ claims in the amount of $30 million. Although this lawsuit was initially stayed pending the Austrian insolvency proceeding, the stay was lifted and we filed our answer in May 2004. The parties are engaged in ongoing discovery. In December 2004, the plaintiffs filed a motion for partial summary judgment on issues of liability. Oral argument on plaintiffs’ motion was held in June 2005. An order is expected in fourth quarter of 2005.

We continue to oppose these claims and believe we have meritorious defenses. Although it is not possible to predict with certainty whether we will incur any liability in connection with these lawsuits, we do not believe that any liability we might incur as a result of these lawsuits would have a material adverse effect on our financial condition, results of operations or cash flows. Reserves have been provided in connection with this litigation.

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

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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 on 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 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 our former natural gas traders was indicted on three counts of knowingly causing the transmission of false trade reports used to calculate the index price of natural gas and four counts of wire fraud. In December 2004, a second indictment was filed against this same individual and other individuals, not related to Dynegy, alleging conspiracy to falsely report gas prices to various index publications. A 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 our activities in the California energy markets in November 2002. We continue to cooperate fully with the U.S. Attorney’s office in its investigation of these matters, including production of substantial documents responsive to the subpoena and other requests for information. We cannot predict the ultimate outcome of this investigation.

Department of Labor Investigation. In August 2002, the U.S. Department of Labor commenced an official investigation pursuant to Section 504 of ERISA with respect to the benefit plans we maintain and our ERISA affiliates. We cooperated with the Department of Labor throughout this investigation, which focused on a review of plan documentation, plan reporting and disclosure, plan record keeping, plan investments and investment options, plan fiduciaries and third-party service providers, plan contributions and other operational aspects of the plans. In February 2005, we received a letter from the Department of Labor indicating that, as a result of our recent settlement in the ERISA litigation, it intended to take no further action with respect to its investigation of the Dynegy Inc. 401(k) Plan. However, its investigation is ongoing as it relates to the Illinois Power 401(k) Plans and the recent litigation relating to those plans described above.

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

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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 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, Indian Basin and PESA. We carry reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

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

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considers the probability of an adverse outcome as only reasonably possible. We intend to contest any proposed disallowances.

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 11—Regulatory Issues

We are subject to regulation by various federal, state, local and foreign agencies, including extensive rules and regulations governing transportation, transmission and sale of energy commodities as well as the discharge of materials into the environment or otherwise relating to environmental protection. Compliance with these regulations requires general and administrative, capital and operating expenditures including those related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities and remediation obligations. In addition, the U.S. Congress 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 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

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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 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, as well as the entities we acquired in January 2005 in connection with the Sithe Energies acquisition, timely resubmitted their applications to the FERC. On June 16, 2005, the FERC issued an order accepting the updated market power analyses submitted by Sithe Energies and Dynegy. Our next triennial market power analysis is due June 16, 2008. 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 our responsibility. FERC is not expected to rule on whether the specific charges may be shifted to us and, if applicable, the amount that we are 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.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Note 12—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans, which are more fully described in Note 19—Employee Compensation, Savings and Pension Plans beginning on page F-73 of our Form 10-K.

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


	Pension Benefits						Other Benefits
	Three Months Ended September 30,
	2005			2004			2005		2004
	(in millions)
Service cost benefits earned during period	$	2		$	6		$	1	$	1
Interest cost on projected benefit obligation		3			10			—		3
Expected return on plan assets		(2	)		(12	)		—		(2	)
Recognized net actuarial loss		—			4			—		2
Settlement and curtailment (gain) loss		—			144			1		(8	)

Total net periodic benefit cost	$	3		$	152		$	2	$	(4	)


	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2005			2004			2005		2004
	(in millions)
Service cost benefits earned during period	$	8		$	18		$	2	$	4
Interest cost on projected benefit obligation		7			31			2		9
Expected return on plan assets		(6	)		(37	)		—		(5	)
Recognized net actuarial loss		2			12			—		4
Settlement and curtailment (gain) loss		—			144			1		(8	)

Total net periodic benefit cost	$	11		$	168		$	5	$	4

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.

Sale of Illinois Power. As a result of the sale of Illinois Power to Ameren, the number of participants in our various defined benefit pension plans and post-retirement benefit plans was reduced substantially. Consequently, our 2005 net periodic benefit cost is substantially lower than the cost for 2004. In addition, in connection with the sale, we agreed to transfer a portion of the assets in certain of our defined benefit plans to other plans maintained by Ameren. An initial asset transfer to Ameren of $411 million was made in November 2004, an additional transfer of approximately $67 million was made in the first quarter 2005 and a final transfer of approximately $1 million was made in the third quarter 2005.

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Note 13—Income Taxes

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

Effective Tax Rate. The income tax benefit (expense) included in our income (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)	$	13		$	(7	)	$	228		$	75
Effective tax rate		48	%		14	%		35	%		234	%

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

Capital Loss Valuation Allowance. In the second quarter of 2005 and in anticipation of the sale of DMSLP, as further discussed in Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids, we reduced the valuation allowance related to our capital loss carryforward by $112 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	$	(112	)	$	(23	)	$	(1	)	$	(136	)
Acquisition of Sithe Energies		(17	)		—			(12	)		(29	)
Tax benefit from discontinued operations		112			—			—			112

Balance as of September 30, 2005	$	(17	)	$	(23	)	$	(13	)	$	(53	)

Previously, as a result of the asset sales discussed in Note 3—Discontinued Operations, Dispositions and Contract Terminations—Dispositions and Contract Terminations, as well as other transactions occurring in 2004, we reduced the valuation allowance related to our capital loss carryforward by $24 million and $71 million in the three and nine months ended September 30, 2004, respectively. This benefit is reflected in income tax benefit (expense) on our unaudited condensed consolidated statements of operations.

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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	$	750		$	62
Non-current		16			15
Deferred tax liabilities:
Non-current		(1,046	)		(499	)

Net deferred tax liability	$	(280	)	$	(422	)

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 $940 million of our net operating loss carryforwards and approximately $300 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 14—Segment Information

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

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

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

In accordance with SFAS No. 144, results associated with our NGL segment, primarily consisting of DMSLP, have been reclassified to discontinued operations for all periods presented. These results include revenues and cost of sales arising from intersegment transactions, which will cease after the sale of DMSLP. NGL processes natural gas and sells this natural gas to CRM for resale to third parties. NGL also purchases natural gas from CRM and electricity from GEN. As the intersegment revenues and cost of sales included in NGL’s results were reclassified to discontinued operations, the effects of these intersegment transactions, eliminated in consolidation, including the

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

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:

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

(in millions)


	GEN			NGL			REG		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	719		$	—		$	—	$	39		$	—		$	758
Other		16			—			—		(4	)		—			12

		735			—			—		35			—			770
Intersegment revenues		(2	)		—			—		2			—			—

Total revenues	$	733		$	—		$	—	$	37		$	—		$	770

Depreciation and amortization	$	(53	)	$	—		$	—	$	—		$	(3	)	$	(56	)
Operating income (loss)	$	115		$	—		$	—	$	(18	)	$	(32	)	$	65
Earnings from unconsolidated investments		7			—			—		—			—			7
Other items, net		2			—			—		(5	)		3			—
Interest expense																(99	)

Loss from continuing operations before taxes																(27	)
Income tax benefit																13

Loss from continuing operations																(14	)
Income from discontinued operations, net of taxes																43

Net income															$	29

Identifiable assets:
Domestic	$	7,827		$	1,705		$	15	$	1,394		$	561		$	11,502
Other		25			—			—		124			—			149

Total	$	7,852		$	1,705		$	15	$	1,518		$	561		$	11,651

Unconsolidated investments	$	291		$	77		$	—	$	—		$	—		$	368
Capital expenditures	$	(22	)	$	(16	)	$	—	$	—		$	(1	)	$	(39	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	273		$	—		$	377		$	32		$	—		$	682
Other		—			—			—			(14	)		—			(14	)

		273			—			377			18			—			668
Intersegment revenues		153			—			6			(9	)		(150	)		—

Total revenues	$	426		$	—		$	383		$	9		$	(150	)	$	668

Depreciation and amortization	$	(50	)	$	—		$	—		$	(1	)	$	(7	)	$	(58	)
Operating income (loss)	$	71		$	—		$	83		$	(32	)	$	(57	)	$	65
Earnings from unconsolidated investments		99			—			—			—			—			99
Other items, net		—			—			2			(3	)		1			—
Interest expense																	(115	)

Income from continuing operations before taxes																	49
Income tax expense																	(7	)

Income from continuing operations																	42
Income from discontinued operations, net of taxes																	36

Net income																$	78

Identifiable assets:
Domestic	$	6,449		$	1,809		$	18		$	1,667		$	560		$	10,503
Other		3			4			—			192			29			228

Total	$	6,452		$	1,813		$	18		$	1,859		$	589		$	10,731

Unconsolidated investments	$	381		$	78		$	—		$	—		$	—		$	459
Capital expenditures	$	(20	)	$	(14	)	$	(31	)	$	—		$	(5	)	$	(70	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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

(in millions)


	GEN			NGL			REG		CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	1,592		$	—		$	—	$	99		$	—		$	1,691
Other		46			—			—		(46	)		—			—

		1,638			—			—		53			—			1,691
Intersegment revenues		(28	)		—			—		28			—			—

Total revenues	$	1,610		$	—		$	—	$	81		$	—		$	1,691

Depreciation and amortization	$	(150	)	$	—		$	—	$	(1	)	$	(14	)	$	(165	)
Operating income (loss)	$	194		$	—		$	—	$	(225	)	$	(353	)	$	(384	)
Earnings from unconsolidated investments		14			—			—		—			—			14
Other items, net		4			—			—		(5	)		10			9
Interest expense																(284	)

Loss from continuing operations before taxes																(645	)
Income tax benefit																228

Loss from continuing operations																(417	)
Income from discontinued operations, net of taxes																209

Net loss															$	(208	)

Identifiable assets:
Domestic	$	7,827		$	1,705		$	15	$	1,394		$	561		$	11,502
Other		25			—			—		124			—			149

Total	$	7,852		$	1,705		$	15	$	1,518		$	561		$	11,651

Unconsolidated investments	$	291		$	77		$	—	$	—		$	—		$	368
Capital expenditures	$	(87	)	$	(39	)	$	—	$	—		$	(6	)	$	(132	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

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

(in millions)


	GEN			NGL			REG			CRM			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	373		$	—		$	1,146		$	687		$	—		$	2,206
Other		2			—			—			(84	)		—			(82	)

		375			—			1,146			603			—			2,124
Intersegment revenues		903			—			19			(431	)		(491	)		—

Total revenues	$	1,278		$	—		$	1,165		$	172		$	(491	)	$	2,124

Depreciation and amortization	$	(145	)	$	—		$	(10	)	$	(1	)	$	(27	)	$	(183	)
Impairment and other charges		—			—			(54	)		—			(24	)		(78	)
Operating income (loss)	$	159		$	—		$	158		$	45		$	(201	)	$	161
Earnings from unconsolidated investments		187			—			—			—			—			187
Other items, net		—			—			3			(1	)		4			6
Interest expense																	(386	)

Loss from continuing operations before taxes																	(32	)
Income tax benefit																	75

Income from continuing operations																	43
Income from discontinued operations, net of taxes																	113

Net income																$	156

Identifiable assets:
Domestic	$	6,449		$	1,809		$	18		$	1,667		$	560		$	10,503
Other		3			4			—			192			29			228

Total	$	6,452		$	1,813		$	18		$	1,859		$	589		$	10,731

Unconsolidated investments	$	381		$	78		$	—		$	—		$	—		$	459
Capital expenditures	$	(78	)	$	(41	)	$	(92	)	$	—		$	(10	)	$	(221	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited and Restated)

For the Interim Periods Ended September 30, 2005 and 2004

Note 15—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 3 — 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 7—Debt—Amended and Restated Credit Facility for further discussion of our amended credit facility.

DYNEGY 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. As discussed in the Introductory Note to this Amendment No. 1, the financial information contained in this Form 10-Q/A has been revised to reflect the restatement items described in the Explanatory Note to the accompanying unaudited condensed consolidated financial statements. 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.

PLEASE NOTE THAT THE INFORMATION CONTAINED IN THIS AMENDMENT NO. 1, INCLUDING THE UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND THE NOTES THERETO, DOES NOT REFLECT EVENTS OCCURRING AFTER NOVEMBER 9, 2005 (THE DATE OF THE ORIGINAL FILING), WITH THE EXCEPTION OF THE ITEM DISCUSSED IN THE EXPLANATORY NOTE. SUCH EVENTS INCLUDE, AMONG OTHERS, THE EVENTS DESCRIBED IN OUR ANNUAL REPORT ON FORM 10-K FOR THE PERIOD ENDED DECEMBER 31, 2005 AND OUR CURRENT REPORTS ON FORM 8-K AND ANY AMENDMENTS THERETO. FOR A DESCRIPTION OF THESE EVENTS, PLEASE READ OUR EXCHANGE ACT REPORTS FILED SINCE NOVEMBER 9, 2005.

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 two remaining power tolling arrangements (excluding the Independence toll, which is now part of our GEN segment) as well as our gas transportation contracts and legacy gas and power trading positions. Our consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

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 7—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 four most important power pricing markets that impact our power generation business are PJM, MISO, New York Zone G and New York Zone A. 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 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. Our acquisition of Sithe Energies in January 2005 achieved both sector growth and restructuring of a significant toll obligation by transforming it into an intercompany agreement. Through this transaction, we acquired more than 1,000 MW of low heat rate efficient generation facilities. In addition to the power plants, we acquired a 750 MW firm capacity sales agreement with Con Edison which runs through 2014. Over its term, this contract essentially offsets the principal and interest payments associated with the debt we assumed in this acquisition.

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

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

With these three accomplishments, our self-restructuring phase essentially came to a close, and we 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 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids for further discussion. We expect to net 95% of the cash proceeds from the sale of DMSLP, as the anticipated taxable gain will be largely offset by net operating losses and capital loss carry-forwards.

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) 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 our acquisition of Sithe Energies and its Northeast power generation assets.

We 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.

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 $59 million in 2006, $42 million in 2007, $269 million in 2008, $57 million in 2009, $688 million in 2010 and $3,193 million thereafter.

Our aggregate maturities for long-term debt, including the current portion and excluding our Central Hudson leveraged lease and our Series C preferred stock, as of September 30, 2005, were approximately $5.1 billion. This includes the approximately $797 million of debt acquired with our 2005 acquisition of the Independence facility, which had a face value of $919 million at acquisition. Please see Note 2—Acquisition—Sithe Energies and Note 7—Debt—Independence Debt for further discussion of this transaction.

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.

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	$	230		$	260	$	192
CRM		97			86		94
NGL		44	(1)		159		167
REG		—			—		10
Other		10			7		7

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.

(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 $68 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. Finally, the remaining $10 million in collateral postings at our REG segment has been eliminated since December 31, 2004.

We have transitioned counterparty collateral demands from cash postings to letters of credit in order to replenish our cash balances after taking into account (i) the closing of the Sithe Energies acquisition in January 2005, for which we paid $120 million, net of transaction costs and cash acquired and (ii) our payment of $175 million in May 2005 and $80 million in July 2005 in connection with the settlement of the shareholder class action and derivative litigation.

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

However, we have assumed additional contractual obligations as a result of the Sithe Energies acquisition, including (i) two additional gas supply agreements under which we are obligated for $191 million through 2015, (ii) $919 million of face value project debt, which was recorded at its fair value of $797 million and (iii) an operating lease related to the Sithe Energies New York City office space, which extends through 2011. We expect our future payments of $37 million under this lease to be partially offset by $19 million in future sublease rentals. Please see Note 2—Acquisition—Sithe Energies and Note 7—Debt—Independence Debt for further discussion.

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

As of September 30, 2005, the equipment leases have remaining terms from two to sixteen years and involve a maximum aggregate obligation of $131 million over the terms of the leases. Each of the hydroelectric generation facilities is party to a long-term power purchase agreement with a local utility. Under the terms of each of these agreements, a project tracking account, which we refer to as a “Tracking Account,” was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. Two of the four facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs, exclusive of lease or interest costs. The remaining two facilities are anticipated to begin reducing the Tracking Accounts in 2006. The aggregate balance of the Tracking Accounts as of September 30, 2005 was approximately $255 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts may cause the facilities to operate at a net cash deficit.

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

On October 31, 2005, we (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 7—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.

Dividends on Preferred and Common Stock

Dividend payments on our common stock are at the discretion of our Board of Directors. We did not declare or pay a dividend on common stock during the first nine months of 2005 and do not foresee a declaration of dividends in the near term, particularly given our financial condition and the dividend restrictions contained in our financing agreements.

We accrue dividends on our Series C preferred stock at a rate of 5.5% per annum. These dividends are payable on the Series C preferred stock in February and August of each year, but we may defer payments for up to 10 consecutive semi-annual periods. If the holders of the Series C preferred stock do not receive the full dividends to which they are entitled on any specified dividend payment date, then such unpaid dividends will be deferred, will cumulate and will accrue additional dividends at the rate of 5.5% per annum. In February and August 2005, we made semi-annual dividend payments of $11 million. Please see Note 14—Redeemable Preferred Securities—Series C Convertible Preferred Stock beginning on page F-54 of our Form 10-K for further discussion.

Pursuant to the indenture governing DHI’s SPNs, following the August 2005 expiration of the two-year grace period provided therein, we are permitted to pay dividends on the Series C preferred stock only if we meet or exceed the fixed charge coverage ratio specified in such indenture. As a result, we may be required to defer payment of dividends on the Series C preferred stock beginning in February 2006.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and, as of October 31, 2005, available capacity under our Amended and Restated Credit Facility. Please see Note 7—Debt—Amended and Restated Credit Facility for further discussion of our amended credit facility.

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		1,511	(1)		205	(1)(2)		628	(1)(2)

Total available liquidity	$	1,535		$	580	(3)	$	1,234

(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 3—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) cash paid for the Sithe acquisition of $120 million, net of cash acquired, (ii) our payments of $255 million in connection with the settlement of the shareholder class action litigation and derivative litigation (iii) capital expenditures of $132 million and (iv) debt payments of $40 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 7—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 $178 million for the nine months ended September 30, 2005. This consisted of $595 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 $773 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.

For 2005, we have projected operating cash outflows of $98 to $88 million. This projection, which is subject to change based on a number of factors, many of which are beyond our control, reflects $745 to $750 million in forecasted operating cash flows from our GEN and NGL business segments, offset by projected cash outflows of $76 million from our CRM business segment and $767 to $762 million in corporate-level expenses, including $435 million of interest.

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 7—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.

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 $1,511 million and $205 million, respectively, as compared to $628 million at the end of 2004. This increase in cash on hand 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 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 7—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.

Asset Sale Proceeds. As further discussed in Note 3—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.

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

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 (other than Illinois Power) was not material and was more than offset by net gains on sale in 2004. However, beginning in 2005, the lost earnings of approximately $15 million annually from such assets, before consideration of interest savings, will no longer be offset by gains on sale.

Capital-Raising Transactions. As part of our ongoing efforts to move toward a capital structure that is more closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we will continue to consider additional capital-raising transactions both in the near- and long-term. The timing of any capital-raising transaction may be impacted by unforeseen events, such as strategic growth opportunities, legal judgments or regulatory requirements, which could necessitate additional capital in the near-term.

These transactions may include capital markets transactions. Our ability to issue public securities is enhanced by our effective shelf registration statement, under which we have approximately $430 million in remaining availability. 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, our non-investment grade credit ratings, significant debt maturities, long-term business prospects and other factors beyond our control. Any issuance of equity would likely have other effects as well, including shareholder dilution. Further, our ability to issue debt securities is limited by our financing agreements, including our SPN indenture. Please see Note 7—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, REG and CRM. Other reported results include corporate overhead and our discontinued communications business. All direct general and administrative expenses and other income (expense) items incurred by us on behalf of our subsidiaries are charged to the applicable subsidiary as incurred.

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

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		REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	115	$	—	$	—	$	(18	)	$	(32	)	$	65
Earnings from unconsolidated investments		7		—		—		—			—			7
Other items, net		2		—		—		(5	)		3			—
Interest expense														(99	)

Loss from continuing operations before taxes														(27	)
Income tax benefit														13

Loss from continuing operations														(14	)
Income from discontinued operations, net of taxes														43

Net income													$	29

Quarter Ended September 30, 2004


	GEN		NGL		REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	71	$	—	$	83	$	(32	)	$	(57	)	$	65
Earnings from unconsolidated investments		99		—		—		—			—			99
Other items, net		—		—		2		(3	)		1			—
Interest expense														(115	)

Income from continuing operations before taxes														49
Income tax expense														(7	)

Income from continuing operations														42
Income from discontinued operations, net of taxes														36

Net income													$	78

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		11.2		9.6
Million megawatt hours generated—net		11.0		9.1
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
New York—Zone A	$	91	$	48
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)		262.8		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


	Quarter Ended September 30,
	2005	2004
Regulated Energy Delivery (3)
Electric sales in KWH (millions):
Residential	—	1,592
Commercial	—	1,217
Industrial	—	1,168
Transportation of customer-owned electricity	—	975
Other	—	99

Total electric sales	—	5,051

Gas sales in Therms (millions):
Residential	—	20
Commercial	—	11
Industrial	—	11
Transportation of customer-owned gas	—	46

Total gas delivered	—	88

Cooling degree days—actual (4)	—	559
Cooling degree days—10-year rolling average	—	862
Heating degree days—actual (5)	—	49
Heating degree days—10-year rolling average	—	59

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

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

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

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

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

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


	Quarter Ended September 30, 2005
	GEN			NGL		REG			CRM			Other		Total
	(in millions)
Legal and settlement charges	$	—		$	—	$	—		$	(29	)	$	4	$	(25	)
Discontinued operations		—			71		—			(2	)		—		69

Total	$	—		$	71	$	—		$	(31	)	$	4	$	44


	Quarter Ended September 30, 2004
	GEN			NGL		REG			CRM			Other		Total
	(in millions)
Impairment of West Coast Power	$	(45	)	$	—	$	—		$	—		$	—	$	(45	)
Loss on sale of Illinois Power		—			—		(24	)		—			—		(24	)
Gain on sale of Joppa		75			—		—			—			—		75
Gain on sale of Oyster Creek		15			—		—			—			—		15
Taxes		—			—		—			—			13		13
Discontinued operations		—			61		—			(1	)		—		60

Total	$	45		$	61	$	(24	)	$	(1	)	$	13	$	94

Operating Income

Operating income was $65 million for the quarter ended September 30, 2005, compared to operating income of $65 million for the quarter ended September 30, 2004.

GEN. Operating income for our GEN segment was $115 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.

The decrease in earnings in the Midwest was more than offset in the Northeast region, where results increased $49 million, from $11 million for the three months ended September 30, 2004 to $60 million for the same period in 2005. Beginning in February 2005, our Northeast region’s results include earnings from the Independence facility. See Note 2—Acquisition—Sithe Energies for further discussion of the acquisition of Independence. Earnings for the Independence facility were $19 million in the third quarter of 2005. In addition, earnings at our existing Northeast facilities increased $31 million from the third quarter 2004 to 2005, as a 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 from $14 million for the three months ended September 30, 2004 to $17 million for the same period in 2005. The increase is primarily the result of expense associated with the New York City office lease we acquired in our Sithe Energies acquisition. Depreciation expense increased from $50 million for the third quarter 2004 to $53 million for the third quarter 2005, primarily as a result of depreciation associated with the Independence facility acquired in 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.

REG. Operating income for the REG segment was $83 million for the quarter ended September 30, 2004. We sold Illinois Power to Ameren on September 30, 2004. Income for the 2004 period includes a $24 million charge related to an asset impairment at Illinois Power.

CRM. Operating loss for the CRM segment was $18 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 a $21 million gain related to the termination of a contract to sell emissions allowances. However, this gain was more than 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 gains 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 $32 million for the quarter ended September 30, 2005, compared to a loss of $57 million for the quarter ended September 30, 2004. Results for 2005 include $4 million of income associated with the recent settlement of our shareholder class action litigation. For more information, please see Note 10—Commitment and Contingencies—Shareholder Litigation. 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.

Earnings from Unconsolidated Investments

Our earnings from unconsolidated investments were approximately $7 million for the quarter ended September 30, 2005, compared to $99 million for the quarter ended September 30, 2004. In the third quarter 2004, we sold our investments in the Joppa and Oyster Creek generating facilities, resulting in gains of $75 million and $15 million, respectively. 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, 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 zero for the quarter ended September 30, 2005, and the quarter ended September 30, 2004.

Interest Expense

Interest expense totaled $99 million for the quarter ended September 30, 2005, compared to $115 million for the quarter ended September 30, 2004. The significant decrease is primarily attributable to the sale of Illinois Power in September 2004, partially offset by interest on our Independence debt.

Income Tax Benefit (Expense)

We reported an income tax benefit during the quarter ended September 30, 2005 of $13 million compared to an expense of $7 million for the quarter ended September 30, 2004. The income tax expense in 2004 includes a $13 million benefit associated primarily with reducing a valuation allowance related to our capital loss carryforward. We reduced the valuation allowance related to our capital loss carryforward as a result of capital gains expected to be recognized from anticipated non-core asset sales in 2004. Excluding these items, the 2004 effective tax rate would be 41%. The 2005 effective tax rate was 48%. 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 (loss) 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

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 3—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 28% 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.

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. This financial data has been restated to reflect the impact of the item described in the Explanatory Note to the unaudited condensed consolidated financial statements. The restatement relates to our deferred income tax accounts. Please read the Explanatory Note for further discussion.

Nine Months Ended September 30, 2005


	GEN		NGL		REG		CRM			Other and Eliminations			Total
	(in millions)												(Restated)
Operating income (loss)	$	194	$	—	$	—	$	(225	)	$	(353	)	$	(384	)
Earnings from unconsolidated investments		14		—		—		—			—			14
Other items, net		4		—		—		(5	)		10			9
Interest expense														(284	)

Loss from continuing operations before taxes														(645	)
Income tax benefit														228

Loss from continuing operations														(417	)
Income from discontinued operations, net of taxes														209

Net loss													$	(208	)

Nine Months Ended September 30, 2004


	GEN		NGL		REG		CRM			Other and Eliminations			Total
	(in millions)
Operating income (loss)	$	159	$	—	$	158	$	45		$	(201	)	$	161
Earnings from unconsolidated investments		187		—		—		—			—			187
Other items, net		—		—		3		(1	)		4			6
Interest expense														(386	)

Loss from continuing operations before taxes														(32	)
Income tax benefit														75

Income from continuing operations														43
Income from discontinued operations, net of taxes														113

Net income													$	156

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		28.7		29.3
Million megawatt hours generated—net		27.8		27.8
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
New York—Zone A	$	70	$	52
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)		266.4		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


Regulated Energy Delivery (3)
Electric sales in KWH (millions):
Residential	—	4,182
Commercial	—	3,389
Industrial	—	3,859
Transportation of customer-owned electricity	—	2,407
Other	—	287

Total electric sales	—	14,124

Gas sales in Therms (millions):
Residential	—	214
Commercial	—	85
Industrial	—	40
Transportation of customer-owned gas	—	171

Total gas delivered	—	510

Cooling degree days—actual (4)	—	932
Cooling degree days—10-year rolling average	—	1,236
Heating degree days—actual (5)	—	3,145
Heating degree days—10-year rolling average	—	3,190

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

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

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

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

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

The following tables summarize significant items on a pre-tax basis, with the exception of the 2005 and 2004 tax items, affecting net income (loss) for the periods presented.


	Nine Months Ended September 30, 2005
	GEN		NGL		REG		CRM			Other			Total
	(in millions)
Legal and settlement charges	$	—	$	—	$	—	$	(29	)	$	(249	)	$	(278	)
Independence toll settlement charge		—		—		—		(169	)		—			(169	)
Discontinued operations		—		152		—		3			—			155
Taxes		—		—		—		—			112			112

Total	$	—	$	152	$	—	$	(195	)	$	(137	)	$	(180	)


	Nine Months Ended September 30, 2004
	GEN			NGL		REG			CRM		Other			Total
	(in millions)
Legal and settlement charges	$	2		$	—	$	(1	)	$	—	$	(57	)	$	(56	)
Impairment of Illinois Power		—			—		(54	)		—		—			(54	)
Impairment of West Coast Power		(45	)		—		—			—		—			(45	)
Loss on sale of Illinois Power		—			—		(39	)		—		—			(39	)
Acceleration of financing costs		—			—		—			—		(14	)		(14	)
Gas transportation contracts		—			—		—			88		—			88
Gain on sale of Joppa		75			—		—			—		—			75
Taxes		—			—		—			—		43			43
Gain on sale of Oyster Creek		15			—		—			—		—			15
Discontinued operations		—			195		—			17		3			215

Total	$	47		$	195	$	(94	)	$	105	$	(25	)	$	228

Operating Income (Loss)

Operating loss was $384 million for the nine months ended September 30, 2005, compared to operating income of $161 million for the nine months ended September 30, 2004.

GEN. Operating income for the GEN segment was $194 million for the nine months ended September 30, 2005, compared to $159 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 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 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 of net 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 $71 million for the same period in 2005. Beginning in February 2005, our Northeast region’s results include earnings from the Independence facility. See Note 2—Acquisition—Sithe Energies for further discussion of the acquisition of Independence. The Independence facility contributed earnings of $23 million for the nine months ended September 30, 2005. Additionally, earnings from our Roseton and Danskammer facilities were up $20 million, as average on-peak prices were up 41% 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 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 $53 million for the same period in 2005. The increase is primarily the result of expense associated with the New York City office we received in our Sithe Energies acquisition. Depreciation expense increased from $145 million for the nine months ended September 30, 2004 to $150 million for the nine months ended September 30, 2005, primarily as a result of depreciation associated with the Independence facility acquired in 2005. Earnings from 2005 also include a $6.7 million charge related to the write-off of an environmental project and a $2 million charge associated with the sale of decommissioned and scrapped transformers from our Renaissance facility.

REG. Operating income for the REG segment was $158 million for the nine months ended September 30, 2004. The 2004 period includes a $39 million charge related to the sale of Illinois Power and a $54 million charge for the impairment of assets associated with this segment.

CRM. Operating loss for the CRM segment was $225 million for the nine months ended September 30, 2005, compared to operating income of $45 million in 2004.

Results for 2005 were negatively impacted by a $169 million charge associated with the Sithe Energies acquisition. Prior to the acquisition, Independence held a power tolling contract and a gas supply agreement with our CRM segment. Upon completion of the purchase, these contracts became intercompany agreements under our GEN segment, and were effectively eliminated on a consolidated basis, resulting in the $169 million charge upon completion of the acquisition. Results for 2005 also reflect $63 million of fixed payments on our remaining power tolling arrangements in excess of realized margins on power generated and sold and a $29 million charge related to increased 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. These losses were partly offset by 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.

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 $353 million for the nine months ended September 30, 2005, compared to a loss of $201 million for the nine months ended September 30, 2004. Results for 2005 include a $236 million charge associated with the recent settlement of our shareholder class action litigation and other legal settlement charges totaling $13 million. For more information, please see Note 10—Commitment and Contingencies—Shareholder Litigation. Results for 2004 include approximately $57 million of expenses related to increased legal and severance reserves. The increased legal reserves resulted from additional activities during the quarter that affected management’s assessment of the probable and estimable loss associated with the applicable proceedings. In addition, 2005 results benefited from lower compensation, insurance and external consultant costs compared to the same period in 2004.

Earnings from Unconsolidated Investments

Our earnings from unconsolidated investments were approximately $14 million for the nine months ended September 30, 2005, compared to $187 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 $92 million, from our investments in the Michigan, Hartwell, Joppa, 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 $9 million of income for the nine months ended September 30, 2005, compared to an expense of $6 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 $284 million for the nine months ended September 30, 2005, compared to $386 million for the nine months ended September 30, 2004. The significant decrease is primarily attributable to the sale of Illinois Power in September 2004.

Income Tax Benefit

We reported an income tax benefit during the nine months ended September 30, 2005 of $228 million compared to a benefit of $75 million for the nine months ended September 30, 2004. The 2005 effective tax rate was 35%, compared to 234% in 2004. The 2004 tax benefit includes a $58 million benefit related to a reduction in a deferred tax capital losses valuation allowance associated with anticipated gains on asset sales and a $3 million benefit related to the release of reserves upon the conclusion of prior year tax audits. Please see Note 13—Income Taxes for further discussion. Excluding these items from the 2004 calculation would result in an effective tax rate of 44%. In general, differences between these effective rates and the statutory rate of 35% result primarily from the effect of certain foreign and state income taxes and permanent differences attributable to book-tax basis differences.

Discontinued Operations

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

Nine Months Ended September 30, 2005


	U.K. CRM			DGC		NGL			Total
	(in millions)								(Restated)
Operating income 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 benefit										54

Income from discontinued operations									$	209

Nine Months Ended September 30, 2004


	U.K. CRM		DGC		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		3		(15	)		(11	)
Interest expense included in income from discontinued operations									(16	)

Income from discontinued operations before taxes									215
Income tax expense									(102	)

Income from discontinued operations								$	113

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.

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 24% 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 offset by foreign currency exchange losses. During 2004, U.K. CRM recognized $17 million of translation gains on the repatriation of cash from the U.K. Also during 2004, DGC recognized $3 million of pre-tax income associated with the receipt from a third party of a prior contractual claim.

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.

Income Tax Benefit (Expense) From Discontinued Operations. The income tax benefit in 2005 includes a $112 million benefit associated with reducing a valuation allowance related to our capital loss carryforward, which primarily relates to our third quarter 2002 sale of NNG. We reduced the valuation allowance related to our capital loss carryforward as a result of capital gains expected to be recognized from our anticipated sale of DMSLP. For further information regarding the sale, please see Note 3—Discontinued Operations, Dispositions and Contract Terminations—Discontinued Operations—Natural Gas Liquids. The income tax expense in 2004 includes $20 million in tax expenses related to the conclusion of prior year tax audits. Please see Note 13—Income Taxes—Prior Year Tax Audits for further discussion. Excluding these items, the 2005 and 2004 effective tax rates would be 37% and 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 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 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 3— 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 43 of our Form 10-K and Item 1. Business—Segment Discussion—Customer Risk Management beginning on page 18 of our Form 10-K. In addition to our Sterlington tolling arrangement, 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		REG		CRM			Other and Eliminations			Consolidated
	(in millions)
For the nine months ended September 30, 2005	$	354	$	241	$	—	$	(64	)	$	(709	)	$	(178	)

For the nine months ended September 30, 2004	$	351	$	194	$	213	$	(179	)	$	(459	)	$	120

Operating Cash Flow. Our cash flow used in operations totaled $178 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 $354 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 $64 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 $709 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 provided by operating activities totaled $120 million for the nine months ended September 30, 2004. During the period, our GEN, NGL and REG 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; and REG provided cash flow from operations of $213 million due primarily to positive earnings for the period. 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 $459 million in cash due primarily to interest payments to service debt, settlement payments and general and administrative expenses.

Capital Expenditures and Investing Activities. Cash used in investing activities during the nine months ended September 30, 2005 totaled $146 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. The cost to acquire Sithe Energies, net of cash proceeds, totaled $120 million. Proceeds from asset sales totaled $106 million, which primarily consisted of a $100 million return of funds held in escrow related to the sale of Illinois Power and $10 million due to the sale of land at our Port Everglades facility, offset by a $5 million payment to Ameren associated with the working capital adjustment related to the sale of Illinois Power.

Net cash provided by investing activities during the nine months ended September 30, 2004 totaled $306 million. Capital spending of $221 million was comprised primarily of $78 million, $41 million and $92 million in the GEN, NGL and REG 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 segment related primarily to maintenance capital projects and wellconnects, as well as approximately $15 million on developmental projects. Capital spending in our REG segment related primarily to projects intended to maintain system reliability and new business services. Proceeds from asset sales of $527 million consisted primarily of $217 million from the sale of Illinois Power, net of cash retained by Illinois Power of

$52 million; $132 million from the sale of our equity investments in the Oyster Creek, Hartwell and Michigan Power generating facilities; $99 million from the sale of Joppa; $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 $99 million. Repayments of long-term debt totaled $40 million for the nine months ended September 30, 2005 and consisted of the following: (i) payments of $18 million on a maturing series of DHI senior notes; (ii) payments of $17 million on the Independence Senior Notes due 2007 and (iii) payments of $5 million on the term loan. Cash used in financing activities also includes semi-annual dividend payments of $22 million on our Series C preferred stock.

Net cash provided by financing activities during the nine months ended September 30, 2004 totaled $24 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 $520 million for the nine months ended September 30, 2004 and consisted of the following: (i) payments of $95 million on a maturing series of Illinova senior notes; (ii) payments of $65 million on Illinois Power’s transitional funding trust notes; (iii) payments of $185 million under our ABG Gas Supply financing; (iv) payments of $78 million on the Tilton capital lease; and (v) payments of $97 million on the ChevronTexaco junior notes. Net cash provided by financing activities was also offset by semi-annual dividend payments of $22 million on our Series C preferred stock.

RISK-MANAGEMENT DISCLOSURES

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


	As of and for the Nine Months Ended September 30, 2005
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2005	$	(133	)
Risk-management losses recognized through the income statement in the period, net		(13	)
Cash paid related to risk-management contracts settled in the period, net		116
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(73	)

Fair value of portfolio at September 30, 2005	$	(103	)

Income Statement Reconciliation
Risk-management losses recognized through the income statement in the period, net	$	(13	)
Physical business recognized through the income statement in the period, net (3)		(129	)
Non-cash adjustments and other		7

Net recognized operating income	$	(135	)

Cash Flow Statement
Cash paid related to risk-management contracts settled in the period, net	$	(116	)
Estimated cash received related to physical business settled in the period, net (3)		(129	)
Timing and other, net (4)		99

Cash received during the period	$	(146	)

Risk-management cash flow adjustment for the nine months ended September 30, 2005 (5)	$	(11	)

(1)	Our modeling methodology has been consistently applied.

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

(3)	This amount includes capacity payments on our power tolling arrangements and the $169 million pre-tax charge for the Independence toll settlement.

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

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

The net risk management liability of $103 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(3)			2006			2007			2008			2009			Thereafter
	(in millions)
September 30, 2005 (2)	$	(36	)	$	(17	)	$	24		$	(38	)	$	(9	)	$	1		$	3
December 31, 2004		(96	)		(7	)		(8	)		(48	)		(21	)		(10	)		(2	)

Increase (4)	$	60		$	(10	)	$	32		$	10		$	12		$	11		$	5

(1)

The table reflects the fair value of our risk-management asset position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management liabilities at September 30, 2005 of $103 million on the unaudited condensed consolidated balance sheets include the $36 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2)

Our mark-to-market values at September 30, 2005 were derived solely from market quotations instead of the combination of long-term valuation models and market quotations used at December 31, 2004. Following our Sithe Energies acquisition and the resulting restructuring of the Independence toll, we no longer use long-term valuation models, as our risk-management portfolio can be fully valued based on market quotations.

(3)	Amounts represent 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.

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

Cash Flow Components of Net Risk-Management Assets


	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)	$	20	$	(18	)	$	2		$	29		$	(39	)	$	(10	)	$	1		$	4
December 31, 2004							(5	)		(7	)		(51	)		(23	)		(12	)		(1	)

Increase (2)						$	7		$	36		$	12		$	13		$	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.

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

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

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

•

projected operating or financial results, 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;

•

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;

•

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 85 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/A. Many of these factors will be important in determining our actual future results. Consequently, no forward-looking statement can be guaranteed. Our actual future results may vary materially from those expressed or implied in any forward-looking statements.

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

RECENT ACCOUNTING PRONOUNCEMENTS

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

CRITICAL ACCOUNTING POLICIES

Please see “Critical Accounting Policies” beginning on page 74 of our Form 10-K for a complete description of our critical accounting policies, with respect to which there have been no material changes since the filing of our Form 10-K.

Item 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, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the third quarter 2005 relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002.

Based on this evaluation, our CEO and CFO concluded that, as of September 30, 2005, as a result of the material weakness identified as of December 31, 2004 and discussed below, our disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods. As we will be unable to confirm whether we have remediated this material weakness until preparation of our 2005 annual tax provision, we anticipate that such material weakness will continue to exist through the end of 2005. Due to the material weakness related to our tax accounting and tax reconciliation process, procedures and controls, in preparing our financial statements at and for the three- and 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–Management’s Report on Internal Control over Financial Reporting beginning on page 86 of our Form 10-K, as of December 31, 2004, there was a material weakness in our internal control over financial reporting related to our tax accounting and tax reconciliation processes, procedures and controls.

During 2005, actions were taken to remediate the material weakness reported in our 2004 Form 10-K, including: (i) increased levels of review in the preparation of the quarterly and annual tax provisions; (ii) formalized processes, procedures and documentation standards relating to the income tax provision; and (iii) restructured our Tax Department to ensure appropriate segregation of duties regarding preparation and review of the quarterly and annual tax provision. Despite these efforts, when making management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, we determined that those controls were still not operating effectively.

In addition to continuing the enhanced processes implemented in 2004 and 2005 and described above, during 2006, we plan to take the following steps in an attempt to remediate the material weakness as of December 31, 2005: (i) implement new processes around the analysis of the income tax provision, including detailed reconciliations between book basis and tax basis of significant tax sensitive balance sheet accounts; (ii) implement additional procedures around the identification, analysis and recording of the tax effects of significant transactions; and (iii) further formalize and document the procedures around the preparation and review of the tax provision and tax accounts. We will not be able to conclude that the material weakness has been successfully remediated, and we cannot assure you we will be able to make such conclusion, until the testing of controls demonstrates that such controls have operated effectively for a sufficient period of time.

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.

Recent Development. In addition, subsequent to the filing of our Annual Report on Form 10-K for the year ended December 31, 2005, we identified another adjustment related to our deferred income tax accounts. Accordingly, in this Form 10-Q/A, we have restated our consolidated financial statements. In addition, we have restated our consolidated financial statements included in our Annual Report on Form 10-K/A for the year ended December 31, 2005. For further information, please see the Explanatory Note in the accompanying unaudited condensed consolidated financial statements. We have concluded that this adjustment was a result of the material weakness discussed above.

DYNEGY INC.

PART II. OTHER INFORMATION

Item 6—EXHIBITS

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


*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.

*10.2		Steam and Electric Power Sales Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company.

*10.3		Services Agreement for CLI Facility dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company.

*10.4		Amended and Restated Lease and Easement Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company.

*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.

*10.6		First Amendment to October 18, 2002 Employment Agreement dated August 17, 2005 between Bruce A. Williamson and Dynegy Inc.

10.7		Second Amendment to October 18, 2002 Employment Agreement dated September 15, 2005 between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.8		First Amendment to the Dynegy Inc. Executive Severance Pay Plan dated September 15, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.9		Second Amendment to the Dynegy Inc. Executive Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).



10.10		Second Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated September 15, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.11		Third Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).

10.12		First Amendment to the Dynegy Inc. Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).

10.13		First Amendment to the First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).

10.14		First Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors dated September 15, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.15		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.

*	Previously filed.

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

DYNEGY INC.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	DYNEGY INC.

Date: May 1, 2006	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

EXHIBIT INDEX

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


*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.

*10.2		Steam and Electric Power Sales Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company.

*10.3		Services Agreement for CLI Facility dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company.

*10.4		Amended and Restated Lease and Easement Agreement dated as of September 6, 2005 between Cogen Lyondell, Inc. and Lyondell Chemical Company.

*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.

*10.6		First Amendment to October 18, 2002 Employment Agreement dated August 17, 2005 between Bruce A. Williamson and Dynegy Inc.

10.7		Second Amendment to October 18, 2002 Employment Agreement dated September 15, 2005 between Bruce A. Williamson and Dynegy Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.8		First Amendment to the Dynegy Inc. Executive Severance Pay Plan dated September 15, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.9		Second Amendment to the Dynegy Inc. Executive Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).

10.10		Second Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated September 15, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.11		Third Amendment to the Second Supplement to the Dynegy Inc. Executive Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).

10.12		First Amendment to the Dynegy Inc. Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).

10.13		First Amendment to the First Supplemental Plan to the Dynegy Inc. Severance Pay Plan dated October 31, 2005 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on November 4, 2005, File No. 1-15659).



10.14		First Amendment to the Dynegy Inc. Deferred Compensation Plan for Certain Directors dated September 15, 2005 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2005, File No. 1-15659).

10.15		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.

*	Previously filed.