Edgar Filing: DYNEGY INC.

Filed by Bowne Pure Compliance

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2007


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

For the transition period from to

DYNEGY INC.
DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)


	Commission	State of	I.R.S. Employer
Entity	File Number	Incorporation	Identification No.
Dynegy Inc.	001-33443	Delaware	20-5653152
Dynegy Holdings Inc.	000-29311	Delaware	94-3248415

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.



Dynegy Inc.		Yes þ No o
Dynegy Holdings Inc.		Yes þ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.


	Large accelerated filer	Accelerated filer	Non-accelerated filer
Dynegy Inc.	þ	o	o
Dynegy Holdings Inc.	o	o	þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).



Dynegy Inc.		Yes o No þ
Dynegy Holdings Inc.		Yes o No þ

Indicate the number of shares outstanding of Dynegy Inc.’s classes of common stock, as of the latest practicable date: Class A common stock, $0.01 par value per share, 500,281,206 shares outstanding as of November 1, 2007; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of November 1, 2007. All of Dynegy Holdings Inc.’s outstanding common stock is owned indirectly by Dynegy Inc.

This combined Form 10-Q is separately filed by Dynegy Inc. and Dynegy Holdings Inc. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.

DYNEGY INC. and DYNEGY HOLDINGS INC.

TABLE OF CONTENTS


		Page

PART I. FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.:

Condensed Consolidated Balance Sheets—Dynegy Inc.: September 30, 2007 and December 31, 2006			4

Condensed Consolidated Statements of Operations—Dynegy Inc.: For the three and nine months ended September 30, 2007 and 2006			5

Condensed Consolidated Statements of Cash Flows—Dynegy Inc.: For the nine months ended September 30, 2007 and 2006			6

Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Inc.: For the three and nine months ended September 30, 2007 and 2006			7

Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.: September 30, 2007 and December 31, 2006			8

Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.: For the three and nine months ended September 30, 2007 and 2006			9

Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.: For the nine months ended September 30, 2007 and 2006			10

Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Holdings Inc.: For the three and nine months ended September 30, 2007 and 2006			11

Notes to Condensed Consolidated Financial Statements			12

Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—DYNEGY INC. AND DYNEGY HOLDINGS INC.		52

Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.		86

Item 4.	CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.		87

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.		89

Item 1A.	RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.		89

Item 2.	UNREGISTERED SALES OF SECURITIES AND USE OF PROCEEDS—DYNEGY INC.		89

Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS—DYNEGY INC.		89

Item 6.	EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.		91

Exhibit 31.1
Exhibit 31.1(a)
Exhibit 31.2
Exhibit 31.2(a)
Exhibit 32.1
Exhibit 32.1(a)
Exhibit 32.2
Exhibit 32.2(a)

EXPLANATORY NOTE

This report includes the combined filing of Dynegy Inc. (“Dynegy”) and Dynegy Holdings Inc. (“DHI”). DHI is the principal subsidiary of Dynegy, providing approximately 100% of Dynegy’s total consolidated revenue for the nine-month period ended September 30, 2007 and constituting approximately 100% of Dynegy’s total consolidated asset base as of September 30, 2007 except for Dynegy’s 50% interest in DLS Power Holdings, LLC and DLS Power Development Company, LLC. Unless the context indicates otherwise, throughout this report, the terms “the Company”, “we”, “us”, “our” and “ours” are used to refer to both Dynegy and DHI and their direct and indirect subsidiaries, including Dynegy Illinois Inc. (“Dynegy Illinois”) before it became a wholly owned subsidiary of Dynegy by way of the merger of Merger Sub Co., then Dynegy’s wholly owned subsidiary, with and into Dynegy Illinois. Discussions or areas of this report that apply only to Dynegy or DHI will clearly be noted in such section.

DEFINITIONS

As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below.


APB		Accounting Principles Board
ARO		Asset retirement obligation
Cal ISO		The California Independent System Operator
CARB		California Air Resources Board
CDWR		California Department of Water Resources
CEC		California Energy Commission
CFTC		Commodity Futures Trading Commission
CO₂		Carbon Dioxide
CPUC		California Public Utilities Commission
CRA		Canada Revenue Agency
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., Dynegy’s primary financing subsidiary
DMG		Dynegy Midwest Generation, Inc.
DMSLP		Dynegy Midstream Services L.P.
DMT		Dynegy Marketing and Trade
DNE		Dynegy Northeast Generation
DPM		Dynegy Power Marketing Inc.
EBITDA		Earnings Before Interest, Taxes, Depreciation and Amortization
EITF		Emerging Issues Task Force
EMA		Energy management agreement
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
FSP		FASB Staff Position
GAAP		Generally Accepted Accounting Principles of the United States of America
GEN		Our power generation business
GEN-MW		Our power generation business — Midwest segment
GEN-NE		Our power generation business — Northeast segment
GEN-SO		Our power generation business — South segment, which was renamed GEN-WE
GEN-WE		Our power generation business — West segment
ICC		Illinois Commerce Commission
IMA		In-market asset availability
IP		Illinois Power
IRS		Internal Revenue Service
ISO		Independent System Operator
LNG		Liquefied natural gas
LTSA		Long term service agreement
MISO		Midwest Independent Transmission Operator, Inc.
MMBtu		Millions of British thermal units
MW		Megawatts
MWh		Megawatt hour
NGL		Our former natural gas liquids business segment
NNG		Northern Natural Gas Company
NOL		Net operating loss
NO_x		Nitrogen Oxide
NPDES		National Pollutant Discharge Elimination System
NRG		NRG Energy, Inc.
NYSDEC		New York State Department of Environmental Conservation
PRB		Powder River Basin coal
PUHCA		Public Utility Holding Company Act of 1935, as amended
RGGI		Regional Greenhouse Gas Initiative
SAB		SEC Staff Accounting Bulletin
SEC		U.S. Securities and Exchange Commission
SFAS		Statement of Financial Accounting Standards
SPN		Second Priority Senior Secured Notes
SPDES		State Pollutant Discharge Elimination System
VaR		Value at Risk
VIE		Variable Interest Entity

PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited) (in millions, except share data)


	September 30,
	2007			December 31, 2006
ASSETS
Current Assets
Cash and cash equivalents	$	638		$	371
Restricted cash		140			280
Accounts receivable, net of allowance for doubtful accounts of $21 and $48, respectively		386			257
Accounts receivable, affiliates		—			1
Inventory		197			194
Assets from risk-management activities		509			701
Deferred income taxes		22			93
Prepayments and other current assets		160			92
Assets held for sale (Note 3)		58			—

Total Current Assets		2,110			1,989

Property, Plant and Equipment		10,579			6,473
Accumulated depreciation		(1,604	)		(1,522	)

Property, Plant and Equipment, Net		8,975			4,951
Other Assets
Unconsolidated investments		96			—
Restricted cash and investments		912			83
Assets from risk-management activities		230			16
Goodwill		532			—
Intangible assets		321			347
Deferred income taxes		6			12
Other long-term assets		222			139

Total Assets	$	13,404		$	7,537


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	307		$	172
Accrued interest		130			66
Accrued liabilities and other current liabilities		252			231
Liabilities from risk-management activities		502			629
Notes payable and current portion of long-term debt		53			68
Liabilities held for sale (Note 3)		2			—

Total Current Liabilities		1,246			1,166

Long-term debt		5,691			2,990
Long-term debt, affiliates		200			200

Long-Term Debt		5,891			3,190
Other Liabilities
Liabilities from risk-management activities		220			35
Deferred income taxes		1,087			469
Other long-term liabilities		421			410

Total Liabilities		8,865			5,270

Minority Interest		(14	)		—
Commitments and Contingencies (Note 11)
Stockholders’ Equity
Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at September 30, 2007; 502,672,821 shares issued and outstanding at September 30, 2007; and no par value, 900,000,000 shares authorized at December 31, 2006; 403,137,339 shares issued and outstanding at December 31, 2006		5			3,367
Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at September 30, 2007; 340,000,000 shares issued and outstanding at September 30, 2007; and no par value, 360,000,000 shares authorized at December 31, 2006; 96,891,014 shares issued and outstanding at December 31, 2006		3			1,006
Additional paid-in capital		6,457			39
Subscriptions receivable		(7	)		(8	)
Accumulated other comprehensive income (loss), net of tax		(16	)		67
Accumulated deficit		(1,818	)		(2,135	)
Treasury stock, at cost, 2,448,380 shares at September 30, 2007 and 1,787,004 shares at December 31, 2006, respectively		(71	)		(69	)

Total Stockholders’ Equity		4,553			2,267

Total Liabilities and Stockholders’ Equity	$	13,404		$	7,537

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited) (in millions, except per share data)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Revenues	$	1,046		$	508		$	2,379		$	1,427
Cost of sales, exclusive of depreciation shown separately below		(649	)		(319	)		(1,478	)		(907	)
Depreciation and amortization expense		(92	)		(54	)		(232	)		(164	)
Impairment and other charges		—			(96	)		—			(107	)
Gain on sale of assets, net		4			—			4			3
General and administrative expenses		(62	)		(59	)		(163	)		(160	)

Operating income (loss)		247			(20	)		510			92
Earnings from unconsolidated investments		8			4			6			6
Interest expense		(117	)		(105	)		(268	)		(310	)
Debt conversion costs		—			(2	)		—			(249	)
Minority interest income (expense)		1			—			(8	)		—
Other income and expense, net		16			11			34			41

Income (loss) from continuing operations before income taxes		155			(112	)		274			(420	)
Income tax (expense) benefit (Note 14)		(59	)		41			(95	)		150

Income (loss) from continuing operations		96			(71	)		179			(270	)
Income (loss) from discontinued operations, net of tax expense of $93, $8, $97 and $1, respectively (Notes 3 and 14)		124			2			131			(6	)

Income (loss) before cumulative effect of change in accounting principle		220			(69	)		310			(276	)
Cumulative effect of change in accounting principle, net of tax expense of zero		—			—			—			1

Net income (loss)		220			(69	)		310			(275	)
Less: preferred stock dividends		—			—			—			9

Net income (loss) applicable to common stockholders	$	220		$	(69	)	$	310		$	(284	)

Earnings (Loss) Per Share (Note 10):
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.11		$	(0.14	)	$	0.25		$	(0.63	)
Income (loss) from discontinued operations		0.15			—			0.18			(0.01	)
Cumulative effect of change in accounting principle		—			—			—			—


Basic earnings (loss) per share	$	0.26		$	(0.14	)	$	0.43		$	(0.64	)


Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.11		$	(0.14	)	$	0.25		$	(0.63	)
Income (loss) from discontinued operations		0.15			—			0.18			(0.01	)
Cumulative effect of change in accounting principle		—			—			—			—


Diluted earnings (loss) per share	$	0.26		$	(0.14	)	$	0.43		$	(0.64	)


Basic shares outstanding		836			495			721			446
Diluted shares outstanding		838			497			723			512

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited) (in millions)


	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	310		$	(275	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		239			206
Impairment and other charges		—			107
Earnings from unconsolidated investments, net of cash distributions		(6	)		(6	)
Risk-management activities		(137	)		(70	)
Gain on sale of assets, net		(214	)		(3	)
Deferred income taxes		172			(147	)
Cumulative effect of change in accounting principle, net of tax		—			(1	)
Legal and settlement charges		29			14
Sithe subordinated debt exchange charge		—			36
Debt conversion costs		—			249
Other		22			39
Changes in working capital:
Accounts receivable		(64	)		353
Inventory		(5	)		12
Prepayments and other assets		(43	)		119
Accounts payable and accrued liabilities		109			(817	)
Changes in non-current assets		(45	)		11
Changes in non-current liabilities		(1	)		(7	)

Net cash provided by (used in) operating activities		366			(180	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(236	)		(92	)
Unconsolidated investments		(7	)		—
Proceeds from asset sales, net		466			18
Business acquisitions, net of cash acquired		(128	)		—
Net proceeds from exchange of unconsolidated investments, net of cash acquired		—			165
Decrease (increase) in restricted cash and restricted investments		(598	)		125
Other investing		—			(3	)

Net cash provided by (used in) investing activities		(503	)		213

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		2,705			1,071
Repayments of long-term borrowings		(2,300	)		(1,780	)
Debt conversion costs		—			(249	)
Redemption of Series C Preferred		—			(400	)
Proceeds from issuance of capital stock		4			183
Dividends and other distributions, net		—			(17	)
Other financing, net		(5	)		(2	)

Net cash provided by (used in) financing activities		404			(1,194	)

Net increase (decrease) in cash and cash equivalents		267			(1,161	)
Cash and cash equivalents, beginning of period		371			1,549

Cash and cash equivalents, end of period	$	638		$	388

Other non-cash investing activity:
Noncash construction expenditures	$	13		$	—

Other non-cash financing activity:
Conversion of Convertible Subordinated Debentures due 2023	$	—		$	225
Sithe subordinated debt exchange charge, net		—			122

See the notes to condensed consolidated financial statements.

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited) (in millions)


	Three Months Ended
	September 30,
	2007			2006
Net income (loss)	$	220		$	(69	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(15	)		38
Reclassification of mark-to-market losses to earnings, net		12			2

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $3 and ($23), respectively)		(3	)		40
Recognized prior service cost and actuarial loss		1			—
Foreign currency translation adjustment		2			(1	)
Unrealized gain on securities, net:
Unrealized gain on securities		6			—
Less: Reclassification adjustments for gains realized in net income (loss)		(4	)		—

Net unrealized gains, net (net of tax expense of $1)		2			—

Other comprehensive income, net of tax		2			39

Comprehensive income (loss)	$	222		$	(30	)


	Nine Months Ended
	September 30,
	2007			2006
Net income (loss)	$	310		$	(275	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(74	)		63
Reclassification of mark-to-market gains to earnings, net		(16	)		(10	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $54 and ($31), respectively)		(90	)		53
Recognized prior service cost and actuarial loss		3			—
Foreign currency translation adjustment		4			2
Unrealized gain on securities, net:
Unrealized gain on securities		4			—
Less: Reclassification adjustments for gains realized in net income (loss)		(4	)		—

Net unrealized gain, net (net of tax of zero)		—			—

Other comprehensive income (loss), net of tax		(83	)		55

Comprehensive income (loss)	$	227		$	(220	)

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited) (in millions)


	September 30,			December 31,
	2007			2006
ASSETS
Current Assets
Cash and cash equivalents	$	594		$	243
Restricted cash		140			280
Accounts receivable, net of allowance for doubtful accounts of $14 and $48 respectively		391			263
Accounts receivable, affiliates		—			7
Inventory		197			194
Assets from risk-management activities		509			701
Deferred income taxes		—			48
Prepayments and other current assets		160			92
Assets held for sale (Note 3)		58			—

Total Current Assets		2,049			1,828

Property, Plant and Equipment		10,579			6,473
Accumulated depreciation		(1,604	)		(1,522	)

Property, Plant and Equipment, Net		8,975			4,951
Other Assets
Unconsolidated investments		35			—
Restricted cash and investments		912			83
Assets from risk-management activities		230			16
Long-term accounts receivable, affiliate		784			781
Goodwill		532			—
Intangible assets		321			347
Deferred income taxes		6			12
Other long-term assets		211			118

Total Assets	$	14,055		$	8,136


LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable	$	307		$	172
Accrued interest		130			66
Accrued liabilities and other current liabilities		243			230
Deferred income taxes		45			—
Liabilities from risk-management activities		502			629
Notes payable and current portion of long-term debt		53			68
Liabilities held for sale (Note 3)		2			—

Total Current Liabilities		1,282			1,165

Long-term debt		5,691			2,990
Long-term debt to affiliates		200			200

Long-Term Debt		5,891			3,190
Other Liabilities
Liabilities from risk-management activities		220			35
Deferred income taxes		818			325
Other long-term liabilities		417			385

Total Liabilities		8,628			5,100

Minority Interest		(14	)		—
Commitments and Contingencies (Note 11)
Stockholder’s Equity
Capital Stock, $1 par value, 1,000 shares authorized at September 30, 2007 and December 31, 2006, respectively		—			—
Additional paid-in capital		5,684			3,543
Accumulated other comprehensive income (loss), net of tax		(16	)		67
Accumulated deficit		(227	)		(574	)

Total Stockholder’s Equity		5,441			3,036

Total Liabilities and Stockholder’s Equity	$	14,055		$	8,136

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited) (in millions)


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Revenues	$	1,046		$	508		$	2,379		$	1,427
Cost of sales, exclusive of depreciation shown separately below		(649	)		(319	)		(1,478	)		(907	)
Depreciation and amortization expense		(92	)		(54	)		(232	)		(164	)
Impairment and other charges		—			(96	)		—			(107	)
Gain on sale of assets, net		4			—			4			3
General and administrative expenses		(62	)		(58	)		(144	)		(158	)

Operating income (loss)		247			(19	)		529			94
Earnings from unconsolidated investments		12			4			12			6
Interest expense		(117	)		(105	)		(268	)		(303	)
Debt conversion costs		—			(2	)		—			(204	)
Minority interest income (expense)		1			—			(8	)		—
Other income and expense, net		17			9			33			36

Income (loss) from continuing operations before income taxes		160			(113	)		298			(371	)
Income tax (expense) benefit (Note 14)		(62	)		43			(94	)		132

Income (loss) from continuing operations		98			(70	)		204			(239	)
Income (loss) from discontinued operations, net of tax expense of $93, $7, $98 and $1, respectively (Notes 3 and 14)		124			3			130			(6	)

Net income (loss)	$	222		$	(67	)	$	334		$	(245	)

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited) (in millions)


	Nine Months Ended
	September 30,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	334		$	(245	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		239			203
Impairment and other charges		—			107
Earnings from unconsolidated investments, net of cash distributions		(12	)		(6	)
Risk-management activities		(137	)		(70	)
Gain on sale of assets, net		(214	)		(3	)
Deferred income taxes		161			(130	)
Legal and settlement charges		29			14
Sithe subordinated debt exchange charge		—			36
Debt conversion costs		—			205
Other		20			38
Changes in working capital:
Accounts receivable		(64	)		353
Inventory		(5	)		12
Prepayments and other assets		(43	)		95
Accounts payable and accrued liabilities		111			(805	)
Changes in non-current assets		(43	)		11
Changes in non-current liabilities		(1	)		(7	)

Net cash provided by (used in) operating activities		375			(192	)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(236	)		(92	)
Proceeds from asset sales, net		466			15
Business acquisitions, net of cash acquired		16			—
Net proceeds from exchange of unconsolidated investments, net of cash acquired		—			165
Decrease in restricted cash and restricted investments		(598	)		125
Affiliate transactions		(11	)		2
Other investing		—			(3	)

Net cash provided by (used in) investing activities		(363	)		212

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		2,705			1,071
Repayments of long-term borrowings		(2,025	)		(1,780	)
Debt conversion costs		—			(203	)
Borrowings from affiliate, net of affiliate		—			(120	)
Dividend to affiliate		(342	)		(50	)
Other financing, net		1			(1	)

Net cash provided by (used in) financing activities		339			(1,083	)

Net increase (decrease) in cash and cash equivalents		351			(1,063	)
Cash and cash equivalents, beginning of period		243			1,326


Cash and cash equivalents, end of period	$	594		$	263

Other non-cash investing activity:
Noncash construction expenditures	$	13		$	—

Other non-cash financing activity:
Sithe subordinated debt exchange charge, net	$	—		$	122

See the notes to condensed consolidated financial statements.

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(unaudited) (in millions)


	Three Months Ended
	September 30,
	2007			2006
Net income (loss)	$	222		$	(67	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(15	)		38
Reclassification of mark-to-market gains to earnings, net		12			2

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $3 and ($23), respectively)		(3	)		40
Recognized prior service cost and actuarial loss		1			—
Foreign currency translation adjustment		2			(1	)
Unrealized gain on securities, net:
Unrealized gain on securities		6			—
Less: Reclassification adjustments for gains realized in net income (loss)		(4	)		—

Net unrealized gains, net (net of tax expense of $1)		2			—

Other comprehensive income, net of tax		2			39

Comprehensive income (loss)	$	224		$	(28	)


	Nine Months Ended
	September 30,
	2007			2006
Net income (loss)	$	334		$	(245	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		(74	)		63
Reclassification of mark-to-market gains to earnings, net		(16	)		(10	)

Changes in cash flow hedging activities, net (net of tax benefit (expense) of $54 and ($31), respectively)		(90	)		53
Recognized prior service cost and actuarial loss		3			—
Foreign currency translation adjustment		4			2
Unrealized gain on securities, net:
Unrealized gain on securities		4			—
Less: Reclassification adjustments for gains realized in net income (loss)		(4	)		—

Net unrealized gains, net (net of tax of zero)		—			—

Other comprehensive income (loss), net of tax		(83	)		55

Comprehensive income (loss)	$	251		$	(190	)

See the notes to condensed consolidated financial statements.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Note 1—Accounting Policies

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end condensed consolidated balance sheet data was derived from audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in Dynegy’s Form 10-K for the year ended December 31, 2006 filed on February 27, 2007, as amended on April 30, 2007, and DHI’s Form 10-K for the year ended December 31, 2006 filed on March 14, 2007, which we refer to as each registrant’s “Form 10-K”.

In April 2007, Dynegy completed its acquisition of 11 power generation facilities and a 50% interest in certain power generation development projects from LS Power Associates, L.P. Dynegy’s interests in the 11 power generation facilities were subsequently contributed to DHI. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

In April 2007, Dynegy contributed to DHI its interest in Dynegy New York Holdings Inc. (“New York Holdings”). This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings were recorded by DHI at Dynegy’s historical cost on the acquisition date. This Form 10-Q with respect to DHI reflects the contribution as though DHI had owned New York Holdings in all periods presented. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions—Sithe Assets Contribution for further discussion.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal and recurring nature that, in the opinion of management, are necessary for a fair statement of the results for the interim periods. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make estimates and judgments that affect our reported financial position and results of operations. These estimates and judgments also impact the nature and extent of disclosure, if any, of our contingent liabilities. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments prior to their publication. Estimates and judgments are based on information available at the time such estimates and judgments are made. Adjustments made with respect to the use of these estimates and judgments often relate to information not previously available. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are primarily used in (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing goodwill and tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications and (vi) 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.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Goodwill and Other Intangible Assets

Goodwill represents, at the time of an acquisition, the amount of purchase price paid in excess of the fair value of net assets acquired. We follow the guidance set forth in SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”), when assessing the carrying value of our goodwill. Accordingly, we will evaluate our goodwill for impairment on an annual basis and when events warrant an assessment. Our evaluation is based, in part, on our estimate of future cash flows. The estimation of fair value is highly subjective, inherently imprecise and can change materially from period to period based on, among other things, an assessment of market conditions, projected cash flows and discount rates.

Intangible assets represent the fair value of assets, apart from goodwill, that arise from contractual rights or other legal rights. In accordance with SFAS No. 141, “Business Combinations” (“SFAS No. 141”), we record only those intangible assets that are distinctly separable from goodwill and can be sold, transferred, licensed, rented, or otherwise exchanged in the open market. Additionally, we recognize intangible assets for those assets that can be exchanged in combination with other rights, contracts, assets or liabilities.

In accordance with SFAS No. 142, we initially record and measure intangible assets based on the fair value of those rights transferred in the transaction in which the assets were acquired. Those measurements are based on quoted market prices for the assets, if available, or measurement techniques based on the best information available such as a present value of future cash flows measurement. Present value measurement techniques involve judgments and estimates made by management about prices, cash flows, discount factors and other variables and the actual value realized from those assets could vary materially from these judgments and estimates. We amortize intangible assets based on the useful life of the respective asset as measured by either the life of the contract or right that the asset is derived from. If the intangible asset does not have a finite life based on the contractual or legal right, an estimate is made of the useful life based on the pattern in which the economic benefits of the asset are expected to be consumed. Intangible assets are subject to impairment testing on an annual basis or as events warrant, and an impairment loss is recognized if the carrying amount of an intangible exceeds its fair value. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

Accounting Principles Adopted

FIN No. 48. On July 12, 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN No. 48”), which provides clarification of SFAS 109, “Accounting for Income Taxes” with respect to the recognition of income tax benefits of uncertain tax positions in the financial statements. FIN No. 48 requires that uncertain tax positions be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard. We adopted the provisions of FIN No. 48 on January 1, 2007 and recorded a decrease of $7 million and $13 million, respectively, to Dynegy’s and DHI’s accumulated deficits as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48.

As of January 1, 2007, Dynegy and DHI had approximately $111 million and $75 million, respectively, of unrecognized tax benefits, of which $67 million and $37 million, respectively, would impact their effective tax rates.

As of September 30, 2007, Dynegy and DHI had approximately $30 million and $15 million, respectively, of unrecognized tax benefits, of which $25 million and $11 million, respectively, would impact their effective tax rates if recognized. The changes to Dynegy’s and DHI’s unrecognized tax benefits during the nine months ended September 30, 2007 primarily resulted from effective settlement of an IRS audit for the tax years 2001 and 2002 and a CRA tax audit for the tax years 2002 to 2004. The adjustments to our reserves for uncertain tax positions as a result of these settlements had an insignificant impact on our net income.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Additionally, in conjunction with the adoption of FIN No. 48, as of January 1, 2007, we reduced our regular federal tax NOL carryforwards by $253 million, from $948 million to $695 million. The reduction was offset by corresponding changes to our net deferred tax liability and reserve for uncertain tax positions.

We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. Dynegy had approximately $4 million and $5 million accrued for the payment of interest and penalties at September 30, 2007 and January 1, 2007, respectively. DHI had approximately $4 million and $6 million accrued for the payment of interest and penalties at September 30, 2007 and January 1, 2007, respectively.

We expect that our unrecognized tax benefits could continue to change due to the settlement of audits and the expiration of statutes of limitation in the next twelve months; however, we do not anticipate any such change to have a significant impact on our results of operations, our financial position or cash flows.

Dynegy files a consolidated income tax return in the U.S. federal jurisdiction, and we file other income tax returns in various states and foreign jurisdictions. DHI is included in Dynegy’s consolidated federal tax returns. With few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 2004. The IRS commenced an examination of Dynegy’s U.S. consolidated income tax returns for 2004 and 2005 in the second quarter 2006 and fieldwork is anticipated to be completed by the end of 2007. During the third quarter 2007, Dynegy finalized its IRS examination for 2001 through 2002 and effectively settled all audit issues related to the CRA audit of its Canadian income tax returns for 2002 through 2004.

Accounting Principles Not Yet Adopted

SFAS No. 157. On September 15, 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. SFAS No. 157 does not require any new fair value measurements; however, the application of SFAS No. 157 will change current practice for some entities. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial statements.

SFAS No. 159. On February 15, 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure eligible items at fair value at specified election dates. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We are currently evaluating the impact of this statement on our financial statements.

Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions

LS Power Business Combination. On March 29, 2007, at a special meeting of the shareholders of Dynegy Illinois, the shareholders of Dynegy Illinois (i) adopted the Plan of Merger, Contribution and Sale Agreement, dated as of September 14, 2006 (the “Merger Agreement”), by and among Dynegy, Dynegy Illinois, Falcon Merger Sub Co., an Illinois corporation and a then-wholly owned subsidiary of Dynegy (“Merger Sub”), LSP Gen Investors, L.P., LS Power Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P. and LS Power Associates, L.P. (“LS Associates” and, collectively, the “LS Contributing Entities”) and (ii) approved the merger of Merger Sub with and into Dynegy Illinois (the “Merger”).

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

On April 2, 2007, in accordance with the Merger Agreement, (i) the Merger was effected, as a result of which Dynegy Illinois became a wholly owned subsidiary of Dynegy and each share of the Class A common stock and Class B common stock of Dynegy Illinois outstanding immediately prior to the Merger was converted into the right to receive one share of the Class A common stock of Dynegy, and (ii) the LS Contributing Entities transferred all of the interests owned by them in entities that own 11 power generation facilities to Dynegy (the “Contributed Entities”).

As part of the transactions contemplated by the Merger Agreement, LS Associates transferred its interests in certain power generation development projects to DLS Power Holdings, LLC, a newly formed Delaware limited liability company (“DLS Power Holdings”), and contributed 50% of the membership interests in DLS Power Holdings to Dynegy. In addition, immediately after the completion of the Merger, LS Associates and Dynegy each contributed $5 million to DLS Power Holdings as their initial capital contributions, and also contributed their respective interests in certain additional power generation development projects to DLS Power Holdings. In connection with the formation of DLS Power Holdings, LS Associates formed DLS Power Development Company, LLC, a Delaware limited liability company (“DLS Power Development”). LS Associates and Dynegy each now own 50% of the membership interests in DLS Power Development.

The aggregate purchase price payable under the Merger Agreement was comprised of (i) $100 million cash, (ii) 340 million shares of the Class B common stock of Dynegy, (iii) the issuance of a promissory note in the aggregate principal amount of $275 million (the “Note”) (which was simultaneously issued and repaid in full without interest or prepayment penalty), (iv) the issuance of an additional $70 million of project-related debt (the “Griffith Debt”) (which was simultaneously issued and repaid in full without interest or prepayment penalty) via an indirect wholly owned subsidiary, and (v) transaction costs of approximately $52 million, approximately $8 million of which were paid in 2006. The Class B common stock issued by Dynegy was valued at $5.98 per share, which represents the average closing price of Dynegy’s common stock on the New York Stock Exchange for the two days prior to, including, and two days subsequent to the September 15, 2006 public announcement of the Merger, or approximately $2,033 million. Dynegy funded the cash payment and the repayment of the Note and the Griffith Debt using cash on hand and borrowings by DHI (and subsequent permitted distributions to Dynegy) of (i) an aggregate $275 million under the Revolving Facility (as defined below) and (ii) an aggregate $70 million under the new Term Loan B (as defined below). Please read Note 6—Debt—Fifth Amended and Restated Credit Facility for further discussion. We paid a premium over the fair value of the net tangible and identified intangible assets acquired due to the (i) scale and diversity of assets acquired in key regions of the United States; (ii) financial stability, and (iii) proven nature of the LS Power asset development platform that were subsequently contributed to DLS Power Holdings and DLS Power Development.

The application of purchase accounting under SFAS No. 141 requires that the total purchase price be allocated to the fair value of assets acquired and liabilities assumed based on their fair values at the acquisition date, with amounts exceeding the fair values being recorded as goodwill in accordance with SFAS No. 142. The allocation process requires an analysis of acquired fixed assets, contracts, and contingencies to identify and record the fair value of all assets acquired and liabilities assumed. Dynegy’s allocation of the purchase price to specific assets and liabilities is based, in part, upon outside appraisals using customary valuation procedures and techniques.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

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


Cash	$	16
Restricted cash and investments (including $37 million current)		91
Accounts receivable		52
Inventory		37
Assets from risk management activities (including $11 million current)		37
Prepaids and other current assets		21
Property, plant and equipment		4,223
Goodwill		594
Unconsolidated investments		83
Other		48

Total assets acquired	$	5,202

Current liabilities and accrued liabilities	$	(92	)
Liabilities from risk management activities (including $14 million current)		(75	)
Long-term debt (including $32 million current)		(1,898	)
Deferred income taxes		(533	)
Other		(96	)
Minority interest		22

Total liabilities and minority interest assumed	$	(2,672	)

Net assets acquired	$	2,530

The purchase price allocation is preliminary, as Dynegy is finalizing its valuation of deferred taxes acquired. Dynegy expects to complete the purchase price allocation in the fourth quarter 2007. However, the differences between the final and preliminary purchase price allocations, if any, are not expected to have a material effect on Dynegy’s financial position or results of operations. During the third quarter 2007, Dynegy revised the determination of the tax basis of the assets acquired and the liabilities assumed and revised its purchase price allocation. The revision reduced the excess of the fair value of the assets acquired and the liabilities assumed. Accordingly, in the third quarter 2007, Dynegy reduced deferred income taxes and decreased goodwill by approximately $72 million.

As noted above, Dynegy recorded preliminary goodwill of approximately $594 million. Of the goodwill recorded, $76 million was assigned to the GEN-MW reporting unit, $387 million was assigned to the GEN-WE reporting unit and $131 million was assigned to the GEN-NE reporting unit.

Dynegy recorded net intangible liabilities of $7 million. This consisted of intangible assets of $32 million in GEN-WE offset by intangible liabilities of $4 million and $35 million, respectively, in GEN-NE and GEN-MW. The intangible assets primarily relate to power tolling agreements that are being amortized over their respective contract terms ranging from 6 months to 7 years. Aggregate amortization expense associated with the above intangibles recorded in the six months ended September 30, 2007 was approximately $5 million. The estimated amortization expense for the three months ended December 31, 2007 is approximately $3 million and for each of the five succeeding years is approximately $8 million, $8 million, $8 million, less than $1 million and less than $1 million, respectively.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Of the $39 million in intangible liabilities, $8 million relates to power tolling agreements which are being amortized over their respective contract terms ranging from 2 years to 10 years. Aggregate amortization income associated with the intangible power tolling agreements recorded in the six months ended September 30, 2007 was less than $2 million. The estimated amortization income for the three months ended December 31, 2007 is $1 million and for each of the five succeeding years is $4 million, $4 million, $2 million, $2 million and $2 million, respectively.

In addition, LSP Kendall Holding LLC, one of the entities transferred to Dynegy, and ultimately DHI, by the LS Contributing Entities pursuant to the Merger Agreement, was party to a power tolling agreement with another of our subsidiaries. This power tolling agreement had a fair value of approximately $31 million as of April 2, 2007, representing a liability from the perspective of LSP Kendall Holding LLC. Upon completion of the Merger Agreement, this power tolling agreement was effectively settled, which resulted in a second quarter 2007 gain equal to the fair value of this contract, in accordance with EITF Issue 04-01, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination” (“EITF Issue 04-1”). We recorded a second quarter 2007 pre-tax gain of approximately $31 million, included as a reduction to cost of sales on the unaudited condensed consolidated statements of operations.

The differences between the financial and tax bases of purchased intangibles and goodwill are not deductible for tax purposes. However, purchase accounting allows for the establishment of deferred tax liabilities on purchased intangibles (other than goodwill) that will be reflected as a tax benefit on our future consolidated statements of operations in proportion to and over the amortization period of the related intangible asset.

Dynegy’s results of operations include the results of the acquired entities for the period beginning April 2, 2007. The following table presents unaudited pro forma information for 2006, as if the acquisition had occurred on July 1, 2006:


	Three Months Ended
	September 30, 2006
	Actual			Pro Forma
	(in millions, except per
	share amounts)
Revenue	$	508		$	945
Loss before cumulative effect of a change in accounting principal		(69	)		(72	)
Net loss applicable to common stockholders		(69	)		(72	)

Basic and diluted loss per share before cumulative effect of accounting change	$	(0.14	)	$	(0.09	)
Basic and diluted loss per share		(0.14	)		(0.09	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

The following table presents unaudited pro forma information for 2007 and 2006, as if the acquisition had occurred on January 1, 2007 or 2006, respectively:


	Nine Months Ended				Nine Months Ended
	September 30, 2007				September 30, 2006
	Actual		Pro Forma		Actual			Pro Forma
	(in millions, except per share amounts)
Revenue	$	2,379	$	2,668	$	1,427		$	2,076
Income (loss) before cumulative effect of a change in accounting principal		310		261		(276	)		(264	)
Net income (loss) applicable to common stockholders		310		261		(284	)		(272	)

Basic earnings (loss) per share before cumulative effect of accounting change	$	0.43	$	0.36	$	(0.64	)	$	(0.35	)
Diluted earnings (loss) per share before cumulative effect of accounting change		0.43		0.36		(0.64	)		(0.35	)
Basic earnings (loss) per share		0.43		0.36		(0.64	)		(0.35	)
Diluted earnings (loss) per share		0.43		0.36		(0.64	)		(0.35	)

These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of Dynegy’s results if the Merger had occurred on July 1, 2006 for the three months ended September 30, 2006 or on January 1, 2007 and 2006, respectively, for the nine months ended September 30, 2007 and 2006. Pro forma adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the Merger in accordance with SFAS No. 141 and SFAS No. 142.

The consummation of the Merger Agreement with the LS Contributing Entities constituted a change in control as defined in our severance pay plans, as well as the various long-term incentive award grant agreements. As a result, all outstanding restricted stock and stock option awards previously granted to employees vested in full on April 2, 2007 upon the closing of the Merger Agreement. Specifically, the vesting of the restricted stock awards granted in 2005 and 2006 and the unvested tranches of stock option awards granted in those years were accelerated. Accordingly, we recorded a charge of approximately $6 million in the second quarter 2007, included in general and administrative expense on our unaudited condensed consolidated statement of operations.

LS Assets Contribution. In April 2007, in connection with the completion of the Merger Agreement, Dynegy contributed to Dynegy Illinois its interest in the Contributed Entities. Following such contribution, Dynegy Illinois contributed to DHI its interest in the Contributed Entities and, as a result, the Contributed Entities are subsidiaries of DHI. Accordingly, all of the entities acquired in the Merger are included within DHI with the exception of Dynegy’s 50% interests in DLS Power Holdings and DLS Power Development, which are directly owned by Dynegy.

DHI’s results of operations include the results of the acquired entities for the period beginning April 2, 2007. The following table presents unaudited pro forma information for 2006, as if the acquisition and subsequent contribution had occurred on April 1, 2006:


	Three Months Ended
	September 30, 2006
	Actual			Pro Forma
	(in millions)
Revenue	$	508		$	945
Net loss		(67	)		(70	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

The following table presents unaudited pro forma information for 2007 and 2006, as if the acquisition and subsequent contribution had occurred on January 1, 2007 or 2006, respectively:


	Nine Months Ended				Nine Months Ended
	September 30, 2007				September 30, 2006
	Actual		Pro Forma		Actual			Pro Forma
	(in millions)
Revenue	$	2,379	$	2,668	$	1,427		$	2,076
Net income (loss)		334		285		(245	)		(233	)

These unaudited pro forma results, based on assumptions deemed appropriate by management, have been prepared for informational purposes only and are not necessarily indicative of DHI’s results if the Merger had occurred on July 1, 2006 for the three months ended September 30, 2006 or on January 1, 2007 and 2006, respectively, for the nine months ended September 30, 2007 and 2006. Pro forma adjustments to the results of operations include the effects on depreciation and amortization, interest expense, interest income and income taxes. The unaudited pro forma condensed consolidated financial statements reflect the Merger in accordance with SFAS No. 141 and SFAS No. 142.

Sithe Assets Contribution. Also in April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings, together with its indirect interest in the subsidiaries of New York Holdings. New York Holdings, together with its wholly owned subsidiaries, owns various assets in the Northeast (the “Sithe Assets”). The Sithe Assets primarily consist of the Sithe/Independence Power Partners, L.P. (“Independence”), a 1,064 MW facility located in Scriba, New York, which Dynegy Illinois acquired in January 2005. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings were recorded by DHI at Dynegy’s historical cost on the date of contribution. In addition, DHI’s historical financial statements have been adjusted in all periods presented to reflect the contribution as though DHI had owned New York Holdings in all periods presented. Independence holds a power tolling contract with DHI. As a result of the contribution, our Independence toll has become an intercompany agreement in our GEN-NE segment and the financial statement impact has been eliminated. The Sithe Assets contributed to DHI also include four hydroelectric generation facilities in Pennsylvania. Please read Note 7—Variable Interest Entities for further information.

Note 3—Discontinued Operations

GEN-WE Discontinued Operations

CoGen Lyondell. On August 1, 2007, we completed our sale of our CoGen Lyondell power generation facility for approximately $470 million to EnergyCo., LLC (“EnergyCo”), a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. We recorded a $210 million gain related to the sale of the asset in the third quarter 2007. The gain includes the impact of allocating approximately $62 million of goodwill associated with the GEN-WE reporting unit to the CoGen Lyondell power generation facility. The amount of goodwill allocated to the CoGen Lyondell power generation facility was based on relative fair values of the CoGen Lyondell power generation facility and the portion of the GEN-WE reporting unit being retained.

The sale of the CoGen Lyondell power generation facility represented the sale of a significant portion of a reporting unit. As such, in accordance with SFAS No. 142, during the third quarter 2007, we tested the goodwill of the GEN-WE reporting unit for impairment. No impairment was indicated as a result of this test.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of CoGen Lyondell’s property, plant and equipment during the second quarter 2007. Depreciation and amortization expense related to CoGen Lyondell totaled approximately zero and $5 million in the three- and nine-month periods ended September 30, 2007, respectively, compared to approximately $3 million and $8 million in the three- and nine-month periods ended September 30, 2006, respectively. Also pursuant to SFAS No. 144, we are reporting the results of CoGen Lyondell’s operations in discontinued operations for all periods presented.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Calcasieu. On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”) for approximately $57 million, subject to regulatory approval and other closing conditions. The transaction is expected to close in early 2008. Beginning in the first quarter 2007, Calcasieu met the held for sale classification requirements of SFAS No. 144, and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets classified as assets held for sale at September 30, 2007 are approximately $57 million of property, plant and equipment, net, $1 million of inventory, $1 million of deferred tax liabilities, and $1 million of accrued liabilities and other current liabilities.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of Calcasieu’s property, plant and equipment during the first quarter 2007. Depreciation and amortization expense related to Calcasieu totaled zero and $1 million in the three- and nine-month periods ended September 30, 2007, respectively, compared to less than $1 million and approximately $2 million in the three- and nine-month periods ended September 30, 2006, respectively. Also pursuant to SFAS No. 144, we are reporting the results of Calcasieu’s operations in discontinued operations for all periods presented.

Other Discontinued Operations

Natural Gas Liquids. On October 31, 2005, we completed the sale of DMSLP, which comprised substantially all remaining operations of our NGL segment, to Targa Resources Inc. (“Targa”) and two of its subsidiaries for $2.44 billion in cash.

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

The following table summarizes information related to Dynegy’s discontinued operations:


	GEN-WE		CRM			NGL		Total

Three Months Ended September 30, 2007
Revenues	$	14	$	—		$	—	$	14
Income from operations before taxes		3		4			—		7
Income from operations after taxes		7		3			4		14
Gain on sale before taxes		210		—			—		210
Gain on sale after taxes		110		—			—		110

Three Months Ended September 30, 2006
Revenues	$	73	$	—		$	—	$	73
Income from operations before taxes		2		6			2		10
Income (loss) from operations after taxes		—		(2	)		4		2


	GEN-WE			CRM			NGL		Total

Nine Months Ended September 30, 2007
Revenues	$	81		$	—		$	—	$	81
Income from operations before taxes		3			15			—		18
Income from operations after taxes		2			11			8		21
Gain on sale before taxes		210			—			—		210
Gain on sale after taxes		110			—			—		110

Nine Months Ended September 30, 2006
Revenues	$	193		$	—		$	—	$	193
Income (loss) from operations before taxes		(13	)		5			3		(5	)
Income (loss) from operations after taxes		(9	)		(1	)		4		(6	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

The following table summarizes information related to DHI’s discontinued operations:


	GEN-WE		CRM		NGL		Total

Three Months Ended September 30, 2007
Revenues	$	14	$	—	$	—	$	14
Income from operations before taxes		3		4		—		7
Income from operations after taxes		7		3		4		14
Gain on sale before taxes		210		—		—		210
Gain on sale after taxes		110		—		—		110

Three Months Ended September 30, 2006
Revenues	$	73	$	—	$	—	$	73
Income from operations before taxes		2		6		2		10
Income from operations after taxes		—		1		2		3


	GEN-WE			CRM		NGL		Total

Nine Months Ended September 30, 2007
Revenues	$	81		$	—	$	—	$	81
Income from operations before taxes		3			15		—		18
Income from operations after taxes		2			10		8		20
Gain on sale before taxes		210			—		—		210
Gain on sale after taxes		110			—		—		110

Nine Months Ended September 30, 2006
Revenues	$	193		$	—	$	—	$	193
Income (loss) from operations before taxes		(13	)		5		3		(5	)
Income (loss) from operations after taxes		(9	)		1		2		(6	)

Note 4—Restructuring Charges

2005 Restructuring. In December 2005, in order to better align our corporate cost structure with a single line of business and as part of a comprehensive effort to reduce on-going operating expenses, we implemented a restructuring plan (the “2005 Restructuring Plan”). The 2005 Restructuring Plan resulted in a reduction of approximately 40 positions and was complete by June 30, 2006. We recognized a pre-tax charge, primarily in Other, of $11 million in the fourth quarter 2005. We recognized approximately $2 million of charges in the nine months ended September 30, 2006, when transitional services were completed by certain affected employees. These charges related entirely to severance costs.

2002 Restructuring. 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 2007 activity for the liabilities recorded in connection with this restructuring:


			Cancellation
			Fees and
			Operating
	Severance		Leases			Total
			(in millions)
Balance at December 31, 2006	$	3	$	7		$	10
Cash payments		—		(5	)		(5	)

Balance at September 30, 2007	$	3	$	2		$	5

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

We expect the $2 million accrual as of September 30, 2007 associated with cancellation fees and operating leases to be paid by the end of 2007, when the leases expire.

Note 5—Risk Management Activities

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 6—Risk Management Activities and Financial Instruments beginning on pages F-26 and F-21, respectively, of Dynegy’s and DHI’s Forms 10-K.

Cash Flow Hedges. We enter into financial derivative instruments that qualify, and that we may elect to designate, as cash flow hedges. Interest rate swaps have been used to convert floating interest rate obligations to fixed interest rate obligations. In the second quarter 2007, PPEA entered into three interest rate swap agreements with an initial aggregate notional amount of approximately $183 million. These interest rate swap agreements convert certain of Plum Point’s floating rate debt exposure (exclusive of the Tax Exempt Bonds) to a fixed interest rate of approximately 5.3%. These interest rate swap agreements expire in June 2040. For the three months ended June 30, 2007, we recorded $27 million of mark-to-market income related to these interest rate swap agreements as an offset to interest expense. Effective July 1, 2007, we designated these agreements as cash flow hedges. Therefore, the effective portion of the changes in value after that date are reflected in Other Comprehensive Income (Loss), and subsequently reclassified to interest expense contemporaneously with the related accruals of interest expense, or depreciation expense in the event the interest was capitalized, in either case to the extent of hedge effectiveness.

Instruments related to our GEN business, which are entered into for purposes of hedging future fuel requirements and sales commitments and securing commodity prices we consider favorable under the circumstances, have also historically been designated as cash flow hedges. Beginning on April 2, 2007, we chose to cease designating such instruments related to our GEN business as cash flow hedges, and thus apply mark-to-market accounting treatment prospectively. Accordingly, as values fluctuate from period to period due to market price volatility, value changes are reflected in the Statement of Operations. Pursuant to EITF Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”), all gains and losses on third party energy trading contracts, whether realized or unrealized, are presented net in the Statements of Operations. The balance in Other Comprehensive Income (Loss) at April 2, 2007 related to these instruments will be reclassified to future earnings contemporaneously with the related purchases of fuel and sales of electricity. As of September 30, 2007, this amount totaled $5 million pre-tax.

During the three and nine months ended September 30, 2007, we recorded a $1 million loss and $4 million of income, respectively, related to ineffectiveness from changes in the fair value of cash flow 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, 2006, we recorded $3 million and $7 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. During the three and nine months ended September 30, 2007 and 2006, zero and $1 million, respectively, were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

The balance in cash flow hedging activities, net at September 30, 2007, is expected to be reclassified to future earnings when the hedged transaction occurs. Of this amount, after-tax losses of approximately $15 million are currently estimated to be reclassified into earnings over the 12-month period ending September 30, 2008. The actual amounts that will be reclassified into 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, and that we designate, 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, 2007 and 2006, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and nine months ended September 30, 2007 and 2006, 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 have remaining investments in foreign subsidiaries, the net assets of which are exposed to currency exchange-rate volatility. As of September 30, 2007, we had no net investment hedges in place.

Note 6—Accumulated Other Comprehensive Income (Loss)

Accumulated other comprehensive income (loss), net of tax, is included in Dynegy’s stockholders’ equity and DHI’s stockholder’s equity on our unaudited condensed consolidated balance sheets, respectively, as follows:


	September 30,			December 31,
	2007			2006
	(in millions)
Cash flow hedging activities, net	$	(14	)	$	76
Foreign currency translation adjustment		27			23
Unrecognized prior service cost and actuarial loss		(40	)		(43	)
Available for sale securities		11			11

Accumulated other comprehensive income (loss), net of tax	$	(16	)	$	67

Note 7—Variable Interest Entities

Hydroelectric Generation Facilities. On January 31, 2005, Dynegy completed the acquisition of ExRes SHC, Inc. (“ExRes”), the parent company of Sithe Energies, Inc. and Independence. As further discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions—Sithe Assets Contribution, on April 2, 2007, Dynegy contributed its interest in the Sithe Assets to DHI. ExRes also owns through its subsidiaries four hydroelectric generation facilities in Pennsylvania. The entities owning these facilities meet the definition of VIEs. In accordance with the purchase agreement, Exelon Corporation (“Exelon”) has the sole and exclusive right to direct our efforts to decommission, sell, or otherwise dispose of the hydroelectric facilities owned through the VIEs. Exelon is obligated to reimburse ExRes for all costs, liabilities, and obligations of the entities owning these facilities, and to indemnify ExRes with respect to the past and present assets and operations of the entities. As a result, we are not the primary beneficiary of the entities and have not consolidated them in accordance with the provisions of FIN No. 46(R), “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (“FIN No. 46(R)”).

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

These hydroelectric generation facilities have commitments and obligations that are off-balance sheet with respect to us that arise under operating leases for equipment and long-term power purchase agreements with local utilities. As of September 30, 2007, the equipment leases have remaining terms from one to twenty-five years and involve a maximum aggregate obligation of $153 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 (the “Tracking Account”) was established to quantify the difference between (i) the facility’s fixed price revenues under the power purchase agreement and (ii) a percentage of the respective utility’s Public Utility Commission approved avoided costs associated with those power purchases plus accumulated interest on the balance. Each power purchase agreement calls for the hydroelectric facility to return to the utility the balance in the Tracking Account before the end of the facility’s life through decreased pricing under the respective power purchase agreement. If the decreased pricing does not reduce the tracking account to zero, a lump sum payment for the remainder of the balance will be due. All four hydroelectric facilities are currently in the Tracking Account repayment period of the contract, whereby balances are repaid through decreased pricing. This pricing cannot be decreased below a level sufficient to allow the facilities to recover their operating costs. The aggregate balance of the Tracking Accounts as of September 30, 2007, was approximately $345 million, and the obligations with respect to each Tracking Account are secured by the assets of the respective facility. The decreased pricing necessary to reduce the Tracking Accounts will make the continued sale of electricity from the facilities uneconomical. As discussed above, the obligations of the four hydroelectric facilities are non-recourse to us. Under the terms of the stock purchase agreement with Exelon, we are indemnified for any net cash outflow arising from ownership of these facilities.

PPEA Holding Company LLC. On April 2, 2007, in connection with the completion of the Merger Agreement, we acquired a 70% interest in PPEA Holding Company LLC (“PPEA”). PPEA owns and operates Plum Point Energy Associates, LLC (“Plum Point”). Plum Point is constructing a 665 MW coal fired power generation facility (the “Project”), located in Mississippi County, Arkansas, in which it owns an approximate 57% undivided interest. Plum Point is the Borrower under a $700 million term loan facility, a $17 million revolving credit facility, and a $102 million letter of credit facility securing $100 million of Tax Exempt Bonds (as discussed below in Note 8). The Project indebtedness is an obligation of Plum Point. The payment obligations of Plum Point in respect of the Bank Loan, the Revolver, and the LC Facility are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation, an independent third party insurance company. Plum Point is party to credit facilities and an insurance policy, which are secured by a security interest in all of Plum Point’s assets, contract rights and Plum Point’s undivided tenancy in common interest in the Project and PPEA’s interest in Plum Point. These assets consist primarily of $236 million of plant construction in progress at September 30, 2007. There are no guarantees of the indebtedness by any parties, and Plum Point’s creditors have no recourse against our general credit. However, as of September 30, 2007, we have posted a $30 million letter of credit to ensure our equity contribution to the Project. See Note 8—Debt—Plum Point Credit Agreement Facility for discussion of Plum Point’s borrowings. PPEA meets the definition of a VIE, and we have determined we are the primary beneficiary of this entity. As such, we have consolidated it in accordance with the provisions of FIN No. 46(R).

On October 25, 2007, we entered into an agreement to sell a non-controlling ownership interest in PPEA to certain affiliates of John Hancock Life Insurance Company (“Hancock”) for approximately $82 million, which is net of non-recourse project debt. The non-controlling interest to be purchased by Hancock represents approximately 125 MW of generating capacity in the Plum Point power generation facility. The transaction is subject to customary closing conditions and is expected to close in the fourth quarter 2007. Upon closing, we will own a 37% interest in PPEA, representing an equivalent of approximately 140 MW and will maintain construction and commercial control of the facility.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

DLS Power Holdings and DLS Power Development. As discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, on April 2, 2007, in connection with the transactions consummated by the Merger Agreement, Dynegy acquired a 50% interest in DLS Power Holdings and DLS Power Development. The purpose of DLS Power Development is to provide services to DLS Power Holdings and the project subsidiaries related to power project development and to evaluate and pursue potential new development projects. DLS Power Holdings and DLS Power Development meet the definition of VIEs, as they will require additional subordinated financial support from their owners to conduct normal on-going operations. However, Dynegy is not the primary beneficiary of the entities and, in accordance with the provisions of FIN No. 46(R), has not consolidated them. Dynegy accounts for its investments in DLS Power Holdings and DLS Power Development as equity method investments pursuant to APB 18, “The Equity Method of Accounting for Investments in Common Stock”. We believe that Dynegy’s maximum exposure to economic loss from this VIE is limited to $61 million, which represents its equity investment in these entities at September 30, 2007.

A substantial portion of the purchase price allocated to these investments, and the equity investment at September 30, 2007, represents Dynegy’s estimate of its proportionate share of the fair value of the underlying intangible assets associated with each of the development projects in excess of the equity of the underlying assets. Depending on the outcome of each development project, Dynegy could be required to record an impairment to its investment related to these intangible assets.

Sandy Creek. In connection with its acquisition of a 50% interest in DLS Power Holdings, as further discussed above, Dynegy acquired a 50% interest in Sandy Creek Holdings LLC (“SCH”), which owned all of Sandy Creek Energy Associates, LP (“SCEA”). SCEA owns the Sandy Creek Energy Station (“the Project”), which is a proposed 898 MW facility to be located in McLennan County, Texas. In August 2007, SCH became a stand-alone entity separate from DLS Power Holdings and its wholly owned subsidiaries, including SCEA, entered into various financing agreements to construct the Project and sold a 25% undivided interest in the Project to an unrelated third party as a result of which, SCEA currently owns a 75% interest in the Project.

Dynegy Sandy Creek Holdings, LLC (the “Dynegy Member”), an indirectly wholly owned subsidiary of Dynegy, and LSP Sandy Creek Member, LLC (the “LSP Member”) each own a 50% interest in SCH. In addition, Sandy Creek Services, LLC (“SC Services”) was formed to provide services to SCH. Dynegy Power Services and LSP Sandy Creek Services LLC each own a 50% interest in SC Services.

Dynegy’s 50% interest in SCH, as well as a related intangible asset of approximately $23 million, were subsequently contributed to a wholly owned subsidiary of DHI. This contribution was accounted for as a transaction between entities under common control. As such, DHI’s investment in SCH, as well as the related intangible asset, were recorded by DHI at Dynegy’s historical cost on the acquisition date. DHI’s investment in SCH is included in GEN-WE.

SCH and SC Services both meet the definition of a VIE, as they will require additional subordinated financial support to conduct their normal on-going operations. However, we are not the primary beneficiary of the entities, and, in accordance with FIN No. 46(R), do not consolidate them. We account for our investments in SCH and SC Services as equity method investments pursuant to APB 18. We believe that our maximum exposure to economic loss from these VIEs is limited to $358 million, which represents our $35 million equity investment in these entities at September 30, 2007 and supporting letters of credit totaling $323 million.

The financing agreements consist of a $200 million term loan and $800 million in construction loans with SCEA as borrower. The SCEA debt is secured by a pledge of SCEA’s assets and contract rights and SCEA’s undivided tenancy in common interest in the Project.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

In addition, SCH entered into a $200 million credit agreement with the Dynegy Member and the LSP Member, as defined below. The SCH debt is secured by a pledge of SCH’s indirect ownership interests in SCEA. The Dynegy Member’s 50% share of the credit agreement is supported by a letter of credit issued under DHI’s primary credit facility in the amount of $100 million. Such letter of credit may be drawn upon by the SCEA lenders if certain conditions are met. The Dynegy Member and the LS Member each agreed to make capital contributions of $223 million to fund project costs after the SCEA and SCH loans have been utilized and otherwise upon the occurrence of certain events and milestone dates. The Dynegy Member’s obligation to make such contributions is supported by a letter of credit in the amount of $223 million issued under DHI’s primary credit facility. Such letter of credit may be drawn upon by the SCEA lenders if certain conditions are met.

Upon the close of the financing agreements discussed above, SCEA sold a 25% undivided interest in the Project for approximately $30 million plus a related portion of accumulated and future construction costs. During the third quarter 2007, we recognized our share of the gain on the sale, which approximated $12 million, in Earnings from unconsolidated investments on the unaudited condensed consolidated statements of operations. During the third quarter 2007, SCEA received $24 million in cash proceeds, consisting of approximately $15 million of the purchase price and $9 million for its share of accumulated costs. The remainder of the purchase price, plus accrued interest, is expected to be collected in 2010. SCEA will distribute the proceeds from the sale to the Dynegy Member and the LSP Member during the fourth quarter 2007.

Note 8—Debt

Notes payable and long-term debt consisted of the following:


	September 30,		December 31,
	2007		2006
	(in millions)
Term Loan B, due 2013	$	70	$	—
Term Facility, floating rate due 2013		850		—
Term Facility, floating rate due 2012		—		200
Senior Notes, 6.875% due 2011		496		493
Senior Notes, 8.75% due 2012		493		488
Senior Unsecured Notes, 7.5% due 2015		550		—
Senior Unsecured Notes, 8.375% due 2016		1,047		1,047
Senior Debentures, 7.125% due 2018		173		173
Senior Unsecured Notes, 7.75% due 2019		1,100		—
Senior Debentures, 7.625% due 2026		172		173
Second Priority Senior Secured Notes, 9.875% due 2010		—		11
Subordinated Debentures payable to affiliates, 8.316%, due 2027		200		200
Sithe Senior Notes, 8.5% due 2007		—		39
Sithe Senior Notes, 9.0% due 2013		409		409
Plum Point Tax Exempt Bonds, floating rate due 2036		100		—
Plum Point Construction Loan, floating rate due 2010		263		—

		5,923		3,233

Unamortized premium on debt, net		21		25

		5,944		3,258

Less: Amounts due within one year, including non-cash amortization of basis adjustments		53		68

Total Long-Term Debt	$	5,891	$	3,190

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Aggregate debt maturities for the remainder of 2007, the next four years and thereafter of the principal amounts of all long-term indebtedness as of September 30, 2007 are as follows: 2007–$21 million, 2008–$50 million, 2009–$58 million, 2010–$63 million, 2011–$570 million and thereafter–$5,182 million.

Fifth Amended and Restated Credit Facility. On April 2, 2007, we entered into a fifth amended and restated credit facility (the “Fifth Amended and Restated Credit Facility”) with Citicorp USA, Inc. and JPMorgan Chase Bank, N.A., as co-administrative agents, JPMorgan Chase Bank, N.A., as collateral agent, Citicorp USA Inc., as payment agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as joint lead arrangers and joint book-runners, and the other financial institutions party thereto as lenders or letter of credit issuers.

The Fifth Amended and Restated Credit Facility amended DHI’s former credit facility (the Fourth Amended and Restated Credit Facility, which was last amended on July 11, 2006) by increasing the amount of the existing $470 million revolving credit facility (the “Revolving Facility”) to $850 million, increasing the amount of the existing $200 million term letter of credit facility (the “Term L/C Facility”) to $400 million and adding a $70 million senior secured term loan facility (“Term Loan B”).

Loans and letters of credit are available under the Revolving Facility and letters of credit are available under the Term L/C Facility for general corporate purposes. Letters of credit issued under DHI’s former credit facility have been continued under the Fifth Amended and Restated Credit Facility. The Term Loan B was used to pay a portion of the consideration under the Merger Agreement. In connection with the completion of the transactions contemplated by the Merger Agreement, an aggregate $275 million under the Revolving Facility, an aggregate $400 million under the Term L/C Facility (with the proceeds placed in a collateral account to support the issuance of letters of credit), and an aggregate $70 million under Term Loan B (representing all available borrowings under Term Loan B) were drawn.

The Fifth Amended and Restated Credit Facility is secured by certain assets of DHI and is guaranteed by Dynegy, Dynegy Illinois and certain subsidiaries of DHI. In addition, the obligations under the Fifth Amended and Restated Credit Facility and certain other obligations to the lenders thereunder and their affiliates are secured by substantially all of the assets of such guarantors. The Revolving Facility matures on April 2, 2012, and the Term L/C Facility and Term Loan B each mature on April 2, 2013. The principal amount of the Term L/C Facility is due in a single payment at maturity; the principal amount of Term Loan B is due in quarterly installments of $175,000 in arrears commencing December 31, 2007, with the unpaid balance due at maturity.

Borrowings under the Fifth Amended and Restated Credit Facility bear interest, at DHI’s option, at either the base rate, which is calculated as the higher of Citibank, N.A.’s publicly announced base rate and the federal funds rate in effect from time to time, or the Eurodollar rate (which is based on rates in the London interbank Eurodollar market), in each case plus an applicable margin.

The applicable margin for borrowings under the Revolving Facility depends on the Standard & Poor’s Ratings Services (“S&P”) and Moody’s Investors Service, Inc. (“Moody’s”) credit ratings of the Revolving Facility, with higher credit ratings resulting in a lower rate. The applicable margin for such borrowings will be either 0.125% or 0.50% per annum for base rate loans and either 1.125% or 1.50% per annum for Eurodollar loans, with the lower applicable margin being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher applicable margin being payable if such ratings are less than BB+ and Ba1. The applicable margins for the Term L/C Facility and Term Loan B are 0.50% for base rate loans and 1.50% for Eurodollar loans.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

An unused commitment fee of either 0.25% or 0.375% is payable on the unused portion of the Revolving Facility, with the lower commitment fee being payable if the ratings for the Revolving Facility by S&P and Moody’s are BB+ and Ba1 or higher, respectively, and the higher commitment fee being payable if such ratings are less than BB+ and Ba1.

The Fifth Amended and Restated Credit Facility contains mandatory prepayment provisions associated with specified asset sales and dispositions (including as a result of casualty or condemnation). The Fifth Amended and Restated Credit Facility also contains customary affirmative covenants and negative covenants and events of default. Subject to certain exceptions, DHI and its subsidiaries are subject to restrictions on incurring additional indebtedness, limitations on investments and limitations on dividends and other payments in respect of capital stock.

The Fifth Amended and Restated Credit Facility also contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter as specified below) that requires DHI and certain of its subsidiaries to maintain a ratio of secured debt to adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”) for DHI and its relevant subsidiaries of no greater than 2.75:1 (September 30, 2007 and thereafter through and including March 31, 2009); and 2.5:1 (June 30, 2009 and thereafter); and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of adjusted EBITDA to consolidated interest expense for DHI and its relevant subsidiaries as of the last day of the measurement periods ending September 30, 2007 and thereafter through and including December 31, 2008 of no less than 1.5:1; ending March 31, 2009 and June 30, 2009 of no less than 1.625:1; and ending September 30, 2009 and thereafter of no less than 1.75:1.

On May 24, 2007, we entered into an Amendment No. 1, dated as of May 24, 2007 (the “Credit Agreement Amendment”), to the Fifth Amended and Restated Credit Facility, which increased the amount of the existing $850 million Revolving Facility to $1.15 billion and increased the amount of the existing $400 million Term L/C Facility to $850 million; the Credit Agreement Amendment did not affect the Term Loan B. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement in the Fifth Amended and Restated Credit Facility to allow DHI to issue the Notes (as defined and discussed below).

Plum Point Credit Agreement Facility. The Plum Point Credit Agreement Facility (“Credit Agreement Facility”) consists of a $700 million construction loan (the “Construction Loan”), a $700 million term loan commitment (the “Bank Loan”), a $17 million revolving credit facility (the “Revolver”) and a $102 million backstop letter of credit facility (the “LC Facility”). The LC Facility was initially utilized to back-up the $101 million letter of credit issued under the then-existing LC Facility (the “Original LC”) for the benefit of the owners of the Tax Exempt Bonds described below. During the second quarter 2007, the Tax Exempt Bonds were repaid and reoffered and a new letter of credit in the amount of approximately $101 million was issued under the LC Facility in substitution for the Original LC in connection with which the Tax Exempt Bonds were remarketed. Borrowings under the Credit Agreement Facility bear interest, at Plum Point’s option, at either the base rate, which is determined as the greater of the Prime Rate or the Federal Funds Rate in effect from time to time plus ¹/2 of 1%, or the Adjusted LIBOR, which is equal to the product of the applicable LIBOR and any Statutory Reserves plus an applicable margin equal to 0.35%. In addition, Plum Point pays commitment fees equal to 0.125% per annum on the undrawn Bank Loan, Revolver and LC Facility commitments. Upon completion of the construction of the Plum Point Project, the Construction Loan will terminate and the debt thereunder will be replaced by the Bank Loan. The Bank Loan matures on the thirtieth anniversary of the later of the date on which substantial completion of the facility has occurred or the first date of commercial operation under any of the power purchase agreements then in effect. The current estimated date of completion of construction is in the second quarter 2010.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

The payment obligations of Plum Point in respect of the Bank Loan, the Revolver, the LC Facility, and associated interest rate hedging agreements (discussed below) are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation. Ambac Assurance Corporation also provided an unconditional commitment to issue, upon the closing of any refinancing of the Tax Exempt Bonds, a bond insurance policy insuring the Tax Exempt Bonds and a debt service reserve surety in an amount equal to the debt service reserve requirement with respect to such bonds. The credit facilities and insurance policy are secured by a mortgage and security interest (subject to permitted liens) in all of Plum Point’s assets and contract rights and Plum Point’s undivided tenancy in common interest in the Project and PPEA’s interest in Plum Point. Plum Point pays an additional 0.38% spread for the AMBAC insurance coverage which is deemed a cost of financing and included in interest expense.

In the second quarter 2007, Plum Point entered into three interest rate swap agreements with an initial aggregate notional amount of approximately $183 million and fixed interest rates of approximately 5.3%. These interest rate swap agreements convert Plum Point’s floating rate debt exposure (exclusive of that on the Tax Exempt Bonds) to a fixed interest rate. The interest rate swap agreements expire in June 2040. For the three months ended June 30, 2007, we recorded $27 million of mark-to-market income related to these interest rate swap agreements as an offset to our consolidated interest expense. Effective July 1, 2007, we designated these agreements as cash flow hedges. Therefore, the effective portion of the changes in value after that date are reflected in Other Comprehensive Income (Loss), and subsequently reclassified to interest expense contemporaneously with the related accruals of interest expense, or depreciation expense in the event the interest was capitalized, in either case to the extent of hedge effectiveness.

Plum Point Tax Exempt Bonds. On April 1, 2006, the City of Osceola (the “City”) loaned the $100 million in proceeds of a tax exempt bond issuance (the “Tax Exempt Bonds”) to Plum Point. The Tax Exempt Bonds were issued pursuant to and secured by a Trust Indenture dated April 1, 2006 between the City and Regions Bank as Trustee. The purpose of the Tax Exempt Bonds is to finance certain of Plum Point’s undivided interests in various sewage and solid waste collection and disposal facilities in the Plum Point facility. Interest expense on the Tax Exempt Bonds is based on a weekly variable rate and is payable monthly. The interest rate in effect at September 30, 2007 was 3.92%. The Tax Exempt Bonds mature on April 1, 2036.

Senior Unsecured Notes Offering. On May 24, 2007, DHI issued $1.1 billion aggregate principal amount of its 7.75% Senior Unsecured Notes due 2019 (the “2019 Notes) and $550 million aggregate principal amount of its 7.50% Senior Unsecured Notes due 2015 (the “2015 Notes” and, together with the 2019 Notes, the “Notes”) pursuant to the terms of a purchase agreement, dated as of May 17, 2007, by and among DHI and the several initial purchasers party thereto (the “Purchasers”). The Notes are DHI’s senior unsecured obligations and rank equal in right of payment to all of DHI’s existing and future senior unsecured indebtedness, and are senior to all of DHI’s existing, and any of its future, subordinated indebtedness. DHI’s secured debt and its other secured obligations are effectively senior to the Notes to the extent of the value of the assets securing such debt or other obligations. None of DHI’s subsidiaries have guaranteed the Notes and, as a result, all of the existing and future liabilities of DHI’s subsidiaries are effectively senior to the Notes. Dynegy has not guaranteed the Notes, and the assets and operations that Dynegy owns through its subsidiaries, other than DHI, do not support the Notes. In connection with the Notes, DHI entered into a registration rights agreement with the Purchasers of the Notes pursuant to which DHI agreed to offer to exchange the Notes for a new issue of substantially identical notes registered under the Securities Act of 1933. On October 15, 2007, pursuant to the registration rights agreement, DHI initiated the exchange offer, which is expected to be completed in the fourth quarter 2007.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

DHI used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger Agreement. Long-term debt assumed upon completion of the Merger Agreement and repaid from the proceeds of the sale of the Notes consisted of the following as of April 2, 2007:


	Face		Premium			Fair
	Value		Discount			Value
			(in millions)
Generation Facilities First Lien Term Loans due 2013	$	919	$	1		$	920
Generation Facilities Second Lien Term Loans due 2014		150		1			151
Kendall First Lien Term Loan due 2013		396		(5	)		391
Ontelaunee First Lien Term Loan due 2009		100		(1	)		99
Ontelaunee Second Lien Credit Agreement due 2009		50		1			51

Total debt repaid with proceeds from unsecured offering	$	1,615	$	(3	)	$	1,612

Outstanding letters of credit under the above mentioned LC facilities were transferred to, and became outstanding letters of credit under, the Fifth Amended and Restated Credit Facility as amended by the Credit Agreement Amendment. Continuing secured obligations of Dynegy Gen Finance Co LLC include financially settled heat rate options and a collateral posting arrangement that are secured by the assets of Dynegy Gen Finance Co LLC.

Repayments and Redemptions. On both January 2, 2007 and July 2, 2007, we made principal payments of $19 million on the Sithe Energies debt. On September 7, 2007, we completed the redemption of $11 million of DHI’s remaining outstanding 9.875% Second Priority Secured Notes due 2010 at a redemption price of 104.938% of the principal amount plus accrued and unpaid interest to the redemption date. On August 6, 2007, we repaid the aggregate $275 million borrowed under the Revolving Facility.

Note 9—Related Party Transactions

Equity Investments. We hold three investments in joint ventures in which LS Power or its affiliates are also investors. Dynegy has a 50% ownership interest in DLS Power Holdings and DLS Power Development. DHI has a 50% ownership interest in SCEA, which was contributed to it by Dynegy in August 2007. Please see Note 7—Variable Interest Entities for further discussion.

Other. On March 30, 2007, DHI paid a dividend of $50 million to Dynegy. In April 2007, DHI paid dividends of $275 million and $17 million to Dynegy.

On April 2, 2007, Dynegy contributed to Dynegy Illinois its interest in the Contributed Entities. Also in April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings, together with its indirect interest in the subsidiaries of New York Holdings. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

Note 10—Dynegy’s Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy 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 Dynegy 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.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

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					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007		2006
	(in millions, except per share amounts)
Income (loss) from continuing operations	$	96	$	(71	)	$	179	$	(270	)
Preferred stock dividends		—		—			—		(9	)

Income (loss) from continuing operations for basic earnings (loss) per share		96		(71	)		179		(279	)
Effect of dilutive securities:
Interest on convertible subordinated debentures		—		—			—		3
Dividends on Series C Preferred		—		—			—		9

Income (loss) from continuing operations for diluted earnings (loss) per share	$	96	$	(71	)	$	179	$	(267	)

Basic weighted-average shares		836		495			721		446
Effect of dilutive securities:
Stock options		2		2			2		2
Convertible subordinated debentures		—		—			—		27
Series C Preferred		—		—			—		37

Diluted weighted-average shares		838		497			723		512

Income (loss) per share from continuing operations:
Basic	$	0.11	$	(0.14	)	$	0.25	$	(0.63	)

Diluted (1)	$	0.11	$	(0.14	)	$	0.25	$	(0.63	)


(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, Dynegy has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2006.

Note 11—Commitments and Contingencies

Set forth below is a summary of certain ongoing legal proceedings. In accordance with SFAS No. 5, “Accounting for Contingencies” (“SFAS No. 5”), we record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. In all instances, management has assessed the matters below 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 prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

In addition to the matters discussed below, we are party to numerous legal proceedings arising in the ordinary course of business or related to discontinued business operations. In management’s judgment, which may prove to be materially inaccurate as indicated above, the disposition of these matters will not materially adversely affect our financial condition, results of operations or cash flows.

Gas Index Pricing Litigation. We and our former joint venture affiliate West Coast Power are named defendants in numerous lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications in the 2000-2002 timeframe. The cases are pending in California, Nevada and Alabama. In each of these suits, the plaintiffs allege that we, West Coast Power and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to natural gas index publications. All of the complaints rely heavily on prior FERC and Commodity Futures Trading Commission (“CFTC”) investigations into and reports concerning index manipulation in the energy industry. Except as specifically mentioned below, the parties are actively engaged in discovery.

	•		During the previous eighteen months, several cases pending in Nevada federal court were dismissed on defendants’ motions. Certain plaintiffs appealed to the Court of Appeals for the Ninth Circuit, which coordinated the cases before the same appellate panel. In September 2007, the Ninth Circuit reversed the dismissals and remanded the cases to their respective trial courts for further proceedings. We are a defendant in only one of the remanded cases. Several matters transferred to Nevada from other federal courts through the multi-district litigation process remain pending.

	•		Pursuant to various motions, the cases pending in California state court were coordinated before a single judge in San Diego (“Coordinated Gas Index Cases”). In August 2006, we entered into an agreement to settle the class action claims in the Coordinated Gas Index Cases for $30 million. In December 2006, the court granted final approval of the settlement and dismissed the class action claims. The settlement is without admission of wrongdoing, and we and West Coast Power continue to deny class plaintiffs’ allegations. The settlement did not include fourteen similar claims filed by individual plaintiffs in the Coordinated Gas Index Cases (the “Single Plaintiff Cases”).

	•		Also in August 2006, we entered into an agreement to settle the class action claims by California natural gas re-sellers and co-generators (to the extent they purchased natural gas to generate electricity for re-sale) pending in Nevada federal court for $2.4 million. The court granted preliminary approval of this settlement in May 2007, which we funded shortly thereafter, and final approval in October 2007. The settlement is without admission of wrongdoing, and we and West Coast Power continue to deny class plaintiffs’ allegations.

	•		In February 2007, a Tennessee state court case was also dismissed on defendants’ motion. In April 2007, the plaintiffs appealed the decision, and that appeal remains pending.

	•		In September 2007, we and the parties to the Alabama action entered into a confidential settlement agreement to resolve the litigation. The settlement is without admission of wrongdoing, and we continue to deny plaintiffs’ allegations.

	•		In October 2007, we, on behalf of ourselves and West Coast Power, entered into a confidential memorandum of understanding to settle the Single Plaintiff Cases. The execution of a formal agreement and funding are expected to occur in the fourth quarter 2007. The settlement is without admission of wrongdoing, and we continue to deny plaintiffs’ allegations.

During the three and nine months ended September 30, 2007 and 2006, we recorded legal and settlement charges of approximately $16 million, $16 million, $2 million and $25 million, respectively, as a result of the actions noted above. We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining individual matters as appropriate. Due to the uncertainty of litigation, we cannot predict whether we will incur any liability in connection with these lawsuits. However, given the nature of the claims, an adverse result in these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

California Market Litigation. We and various other power generators and marketers were defendants in numerous lawsuits alleging rate and market manipulation in California’s wholesale electricity market during the California energy crisis several years ago. The complaints generally alleged unfair, unlawful and deceptive trade practices in violation of the California Unfair Business Practices Act and sought injunctive relief, restitution and unspecified actual and treble damages. All of these cases have been dismissed on grounds of federal preemption except for one remaining action that is pending and fully briefed before the Ninth Circuit Court of Appeals.

We cannot predict with certainty whether we will incur any liability in connection with the remaining pending appeal; however, given the pattern of dismissal and success on appeal of related actions, we expect a similar outcome. Nonetheless, given the nature of this claim, an adverse result could have a material adverse effect on our financial condition, results of operations and cash flows.

Nevada Power Arbitration. Through one of our indirect subsidiaries, we hold an ownership interest in Nevada Cogeneration Associates #2 (“NCA#2”), in which our equal partner is a CUSA subsidiary. NCA#2 has a long-term power sale agreement with Nevada Power Company (“Nevada Power”) that extends through April 2023. In October 2007, Nevada Power initiated an arbitration against NCA#2 seeking a declaratory judgment that (i) Nevada Power’s methodology for calculating certain cumulative excess payments in the event of default or early termination by NCA#2 is correct and (ii) NCA#2 is obligated to repay to Nevada Power the full amount of any outstanding excess payments in the event of a default or early termination or upon the expiration of the agreement’s term in 2023. Currently, Nevada Power does not allege an event of default or early termination has occurred. Nonetheless, Nevada Power maintains that as of December 31, 2006, if an event of default had occurred, NCA#2 would have been required to pay approximately $120 million in cumulative excess payments. We previously disclosed that we agreed to guarantee 50% of the NCA#2 obligation which would be approximately $66 million, if NCA#2 had terminated the power sale agreement as of September 30, 2007. Nevada Power further alleges that the payment obligation could equal approximately $365 million in 2023, 50% of which would be our proportionate share. While there is a question of interpretation regarding the existence of an obligation to make payments upon the scheduled termination of the agreement, management does not expect that any such payments will be required. We believe Nevada Power’s claims are without merit and we intend to defend against them vigorously. However, given the amount in controversy, an adverse ruling could have a material adverse effect on our future financial condition, results of operations and cash flows. Prior to the initiation of arbitration, this matter was previously disclosed as “Black Mountain” in the Guarantees and Indemnification section below.

Illinois Auction Complaints. In March 2007, the Attorney General of the State of Illinois (the “IAG”) filed a complaint at FERC (the “IAG FERC Complaint”) against 16 electricity suppliers engaged in wholesale power sales, challenging the results of the Illinois reverse power procurement auction conducted in September 2006. DPM filed its motion to dismiss and answer the IAG FERC Complaint in June 2007.

In July 2007, the IAG filed a motion to suspend its complaint at FERC and legislative leaders from the State of Illinois, including the Speaker of the House and the Senate President, announced a comprehensive transitional rate relief package for electric consumers. This rate relief package and related agreements were subject to passage of certain legislation, which became law in August 2007.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

As a part of the rate relief package, we agreed to make payments of up to $25 million over a 29-month period. These payments will be contingent on certain conditions related to the absence of future electric rate and tax legislation in Illinois. We made a payment of $7.5 million in 2007 and anticipate making payments of $9.0 million in 2008 and $8.5 million in 2009. We recorded a $25 million expense in the second quarter of 2007 related to these payments, which is included in cost of sales on our unaudited condensed consolidated statement of operations. Our payment of $7.5 million in September 2007 is to be used for funding of the Illinois Power Agency, which is to be created as part of Illinois’ comprehensive rate relief package. Our expected payments for 2008 and 2009 will be made in monthly installments so long as Illinois does not impose an electric rate freeze or an additional tax on generators prior to December 2009, as further described in the rate relief package and related agreements. The monthly payments will be paid into an escrow account established to support rate relief activities for Ameren Illinois Utilities’ customers.

The rate relief package and related agreements have resulted in motions to dismiss with prejudice being filed in several ongoing court and regulatory proceedings including the IAG FERC Complaint, appeals of the original orders adopting the auction process and the auction improvements case. Some of these dismissals have already been entered, including the IAG FERC Complaint, while others remain pending. The FERC complaint was dismissed in October 2007.

Shortly after the IAG FERC Complaint was filed, two civil class action complaints against 21 wholesale electricity suppliers and utilities, including DPM, were filed in Illinois state court. The complaints largely mirror the IAG’s filing and seek unspecified actual and punitive damages. In April 2007, the cases were removed to federal court, and in June 2007, the defendants moved to dismiss plaintiffs’ claim on grounds of the filed rate doctrine and preemption. In October 2007, at the request of the Court, the parties provided supplemental briefs on the impact of the FERC dismissal order and the Illinois rate relief package. A decision on defendants’ motion to dismiss is expected in the fourth quarter 2007.

We believe that the civil plaintiffs’ claims are without merit and we intend to defend against them vigorously. However, given the gravity of their claims, an adverse ruling in some or all of these proceedings could have a material adverse effect on our financial condition, results of operations and cash flows.

New York Attorney General Subpoena. On September 17, 2007, Dynegy and four other companies received a subpoena from the Office of the New York Attorney General. The subpoena seeks information and documents related to, among other things: Dynegy’s evaluation, analysis and projections regarding climate change; the impact of climate change on Dynegy’s operations; development opportunities through the Company’s joint venture with LS Power; and alleged deficiencies in Dynegy’s SEC disclosures related to the foregoing. We are reviewing the subpoena and discussing its contents with the New York Attorney General’s office in anticipation of our responding as appropriate.

Illinova Arbitration. In June 2000, Dynegy’s subsidiary, Illinova Generating Company (“IGC”), sold a minority interest it held in a Cleburne, Texas generating plant to Ponderosa Pine Energy (“PPE”). Brazos Electric Cooperative, Inc. (“Brazos”), the party to an offtake agreement from the plant, brought legal action against PPE alleging that PPE’s purchase did not comply with the terms of Brazos’ offtake agreement. Brazos received a favorable arbitration award against PPE, which in turn sought recovery from IGC and the other former owners of the plant for indemnification. In May 2007, the panel in PPE’s arbitration action ruled that IGC and the other former owners of the plant must indemnify PPE for the Brazos arbitration award, with IGC’s portion being defined as approximately $17 million. Dynegy recognized a legal settlement charge of approximately $17 million in the first quarter 2007 relating to this adverse ruling. In May 2007, Dynegy paid the judgment under protest. PPE recently moved to enforce the arbitration award in state district court and the defendants have filed an opposition. A hearing on the pending motions is scheduled in November 2007.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Bridgeport RMR Agreement. The Bridgeport facility had been operating pursuant to the terms of a reliability-must-run (“RMR”) agreement, subject to the outcome of ongoing proceedings before the FERC to resolve the question of whether Bridgeport is eligible for an RMR agreement. On May 25, 2007, Bridgeport and the intervening parties submitted a Joint Offer of Settlement (the “Settlement”), which effectively terminated the RMR Agreement as of May 31, 2007. In addition, the Settlement stipulated that within 30 days of FERC approval, Bridgeport will refund ISO New England (“ISO-NE”) $12.5 million and any RMR revenues received by Bridgeport from the ISO-NE under the amended RMR agreement for the calendar months April 2007 and May 2007. We recorded a reserve of $12.5 million payable to the ISO-NE as part of the LS Power purchase price allocation, and reserved any RMR revenues received from the ISO-NE for April and May 2007. Under the Settlement, as of June 1, 2007, Bridgeport is no longer required to submit stipulated bids, which allows Bridgeport to more fully participate as a merchant generator in the ISO-NE market. The Settlement was certified as an uncontested settlement on June 29, 2007 by the Presiding Administrative Law Judge and was accepted by the FERC on August 3, 2007. Bridgeport funded the payments to ISO-NE in late August.

Danskammer State Pollutant Discharge Elimination System Permit. In January 2005, the New York State Department of Environmental Conservation (“NYSDEC”) issued a Draft Danskammer SPDES Permit renewal for the Danskammer plant, and an adjudicatory hearing was scheduled for the fall of 2005. Three environmental groups sought to impose a permit requirement that the Danskammer plant install a closed cycle cooling system in order to reduce the volume of water withdrawn from the Hudson River, thus reducing aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect best technology available (“BTA”) for minimizing adverse environmental impacts.

A formal evidentiary hearing was held in November and December 2005. The Deputy Commissioner’s decision directing that the NYSDEC staff issue the revised Draft Danskammer SPDES Permit was issued in May 2006. In June 2006, the NYSDEC issued the revised Danskammer SPDES Permit with conditions generally favorable to us. While the revised Danskammer SPDES Permit does not require installation of a closed cycle cooling system, it does require aquatic organism mortality reductions resulting from NYSDEC’s determination of BTA requirements under its regulations. In July 2006, two of the petitioners filed suit in the Supreme Court of the State of New York seeking to vacate the Deputy Commissioner’s decision and the revised Danskammer SPDES Permit. On March 26, 2007, the Court transferred the lawsuit to the Third Department Appellate Division. The case will now proceed as a normal appeal from a final agency decision and the decision will be based on whether there is substantial evidence in the record to support the agency decision. We believe that the decision of the Deputy Commissioner is well reasoned and will be affirmed. However, in the event the decision is not affirmed and we ultimately are required to install a closed cycle cooling system, this could have a material adverse effect on our financial condition, results of operations and cash flows.

Roseton State Pollutant Discharge Elimination System Permit. In April 2005, the NYSDEC issued to DNE a draft SPDES Permit renewal for the Roseton plant. The Draft Roseton SPDES Permit requires the facility to actively manage its water intake to substantially reduce mortality of aquatic organisms.

In July 2005, a public hearing was held to receive comments on the Draft Roseton SPDES Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking 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 aquatic organism mortality. The petitioners claim that only a closed cycle cooling system meets the Clean Water Act’s requirement that the cooling water intake structures reflect the BTA for minimizing adverse environmental impacts. In September 2006, the administrative law judge issued a ruling admitting the petitioners to full party status and setting forth the issues to be adjudicated in the permit renewal hearing. Various holdings in the ruling have been appealed to the Commissioner

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

of NYSDEC by DNE, NYSDEC staff, and the petitioners. We expect that the adjudicatory hearing on the Draft Roseton SPDES Permit will occur in 2007 or 2008. We believe that the petitioners’ claims are without merit, and we plan to oppose those claims vigorously. Given the high cost of installing a closed-cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operations and cash flows.

Moss Landing National Pollutant Discharge Elimination System Permit. The California Regional Water Quality Control Board (“Water Board”) issued a NPDES permit for the Moss Landing Power Plant in October 2000 in connection with modernization of the plant and the California Energy Commission’s licensing of that project. A local environmental group, Voices of the Wetlands (“Petitioner”), sought review of the permit in Superior Court in Monterey County in July 2001 claiming that the permit was not supported by sufficient analysis of the BTA for cooling water intake structures as required under the Clean Water Act. Petitioner contends that the once-through, seawater-cooling system at Moss Landing should be replaced with a closed-cycle cooling system.

The Superior Court concluded that the Water Board’s BTA analysis was insufficient and remanded the permit to the Water Board directing a comprehensive analysis and reconsideration of the NPDES permit. Following the hearing on remand, the Water Board affirmed its BTA finding. In July 2004, the Superior Court held that the Water Board had conducted a thorough and comprehensive BTA analysis on remand. This decision was appealed by Petitioner to California’s Sixth Appellate District. Briefing for the appeal was completed in November 2005, and oral argument was held on September 18, 2007. A ruling from the appellate court is expected by the end of the fourth quarter 2007.

We believe that Petitioner’s claims lack merit and we plan to oppose those claims vigorously. Given the high cost of installing a closed-cycle cooling system, an adverse result in this proceeding could have a material adverse effect on our financial condition, results of operation and cash flow.

Guarantees and Indemnifications

In the ordinary course of business, 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 remote.

WCP Indemnities. In connection with the sale of our 50% interest in West Coast Power to NRG on March 31, 2006, an agreement was executed to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. The agreement states that we will manage the Gas Index Pricing Litigation described above for which NRG could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses resulting from such litigation, as well as from other proceedings based on similar acts or omissions which formed the basis of such litigation. The agreement further states that we will manage the California Market Litigation described above for which NRG could suffer a loss subsequent to the closing, and that we and NRG would each be responsible for 50% of any costs or losses resulting from that power litigation, as well as from

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

other proceedings based on similar acts or omissions which formed the basis of such litigation. The agreement provides that NRG will manage other active litigation and indemnify us for any resulting losses, subject to certain conditions. Maximum recourse under these matters is not limited by the agreement or by the passage of time with the exception of the California Department of Water Resources matter in which NRG has a specified indemnity obligation. The damages claimed by the various plaintiffs in these matters are unspecified as of September 30, 2007.

Targa Indemnities. 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 certain 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. We have recorded an accrual in association with the cleanup of groundwater contamination at the Breckenridge Gas Processing Plant. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million. We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. We have recorded a reserve associated with this indemnification.

Illinois Power Indemnities. As a condition of Dynegy’s 2004 sale of Illinois Power and its interest in Electric Energy Inc.’s plant in Joppa, Illinois, Dynegy provided indemnifications to third parties regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, Dynegy has 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 natural gas and investments in specified items. Although there is no limitation on Dynegy’s liability under this indemnity, the amount of the indemnity is limited to 50% of any such losses. On July 27, 2005, Dynegy made a payment of $8 million to Ameren in settlement of Ameren’s indemnification claims with respect to an ICC Order disallowing items relating to one of Illinois Power’s natural gas storage fields resulting in a negative revenue requirement impact to Ameren. In anticipation of similar cases, Dynegy recognized a pre-tax charge of $12 million in 2005. As anticipated, Dynegy paid Ameren for an additional amount disallowed in a similar ICC Order in the third quarter 2006. Furthermore, in August 2007, the ICC issued its final Order in another of the related cases, which has been appealed. Dynegy has adjusted the amount reserved for the various ongoing cases in light of these and other developments in the cases. Further disallowances and other events which fall within the scope of the indemnity may still occur; however, Dynegy is not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. Dynegy intends to contest any proposed disallowances.

Northern Natural and Other Indemnities. During 2003, as part of our sales of Northern Natural, the Rough and Hornsea natural 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, 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, CoGen Lyondell, Rockingham Hackberry LNG Project, SouthStar Energy Services, various Canadian assets, Michigan Power, Oyster Creek, Hartwell, Commonwealth, Sherman, and Indian Basin. We have recorded reserves for existing environmental, tax and employee liabilities and have incurred no other expense relating to these indemnities.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Note 12—Regulatory Issues

We are subject to regulation by various federal, state and local 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. The matters discussed below are material developments since the filing of our Forms 10-K. Please see Note 18—Regulatory Issues beginning on pages F-53 and F-40, respectively, of Dynegy’s and DHI’s Forms 10-K for further discussion.

Illinois Resource Procurement Auction. In January 2006, the ICC approved a reverse power procurement auction as the process by which utilities would procure power beginning in 2007. The initial auction occurred in September 2006, and we subsequently entered into two supplier forward contracts with subsidiaries of Ameren Corporation to provide capacity, energy and related services. The Illinois legislature passed legislation in 2007 as part of the Illinois rate relief package that significantly altered the power procurement process in Illinois but the contracts with the Ameren subsidiaries remain in effect. Please see Note 11—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

California Greenhouse Gas Regulation. The California Global Warming Solutions Act (“AB 32”), enacted in September 2006, became effective on January 1, 2007. This Act directs CARB to develop a greenhouse gas control program that will reduce the state’s greenhouse gas emissions to their 1990 levels by 2020. CARB must establish the statewide greenhouse gas emissions cap by January 2008, finalize regulations to achieve required emission reductions by January 2011, and begin implementation and enforcement of the regulatory program by January 2012.

Senate Bill No. 1368 directs the CEC and CPUC, in consultation with other state agencies, to establish greenhouse gas emission performance standards for publicly owned utilities and municipalities. These agencies have instituted proceedings to establish such performance standards restricting the rate of greenhouse gas emissions to that of combined-cycle natural gas baseload generation.

Although California’s comprehensive greenhouse gas control program will likely influence the development of federal and state programs, the structure and requirements have yet to be fully developed. While we cannot reliably predict the potential impact of the California greenhouse gas program on our future financial condition, results of operations or cash flows, the program could have far-reaching and significant impacts on the energy industry and on us.

Regional Greenhouse Gas Initiative. Our Northeast assets in New York, Connecticut and Maine may become subject to a state-driven greenhouse gas program known as RGGI. RGGI is a program under development by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants. The participating RGGI states developed a model rule for regulating greenhouse gas using a cap-and-trade program to reduce carbon emissions by at least 10 % of current emission levels by the year 2018.

The State of Maine enacted climate change legislation in June 2007 approving the state’s participation in RGGI and proposed a CO₂ Budget Trading rule based on the RGGI model rule in July 2007. The proposed rule would implement a CO₂ cap-and-trade program that would cap total authorized CO₂ emissions from affected Maine power generators at 5,948,902 tons per year beginning in 2009 through 2014. Beginning in 2015, the CO₂ emission cap would be reduced each year until 2018 when emissions would be capped at 5,354,014 tons per year. The proposed rule would require that each power generator hold CO₂ allowances equal to its annual CO₂ emissions. Compliance with the allowance requirement could be achieved by reducing emissions, purchasing allowances or securing offset allowances from an approved offset project. Allowances would be distributed to power generators through a state auction with the proceeds placed in an Energy and Carbon Savings Trust fund to be used for energy efficiency and other greenhouse gas reduction projects and for ratepayer relief. The rules governing the auction have not yet been proposed.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

The State of New York issued proposed regulations on October 24, 2007 setting forth its planned CO₂ Budget Trading Program. The proposed rule would implement a cap-and-trade program that would cap total authorized CO₂ emissions from New York electric generators with capacity greater than 25MW of electrical output. The initial CO₂ emissions cap for affected New York generators would be 64,310,805 tons per year beginning in 2009 through 2014. Beginning in 2015, the cap would be reduced each year until 2018, when emissions would be capped at 57,879,725 tons per year. The program would require that each affected CO₂ budget source hold CO₂ allowances equal to the total CO₂ emissions from all of its CO₂ budget units for the control period. Compliance with the allowance requirement could be achieved by reducing emissions, purchasing allowances and/or securing offset allowances from an approved offset project. All allowances would be distributed through an auction or auctions open to participation by any individual or entity that meets prescribed minimum financial requirements. The auctions would be administered by the New York State Energy Research and Development Authority with proceeds being used to promote energy efficiency and clean energy technologies and to cover the administrative costs of the CO₂ Budget Trading Program. Rules governing the auction have not yet been proposed.

The State of Connecticut also enacted legislation in June 2007 that mandates a cap and trade program for CO₂ including a requirement that affected generators purchase 100% of the carbon credits needed to operate their facilities through an auction process. No rules governing the Connecticut auction process have yet been proposed.

The potential impact of the final RGGI program on our future financial condition, results of operations and cash flows will depend on a number of variable factors. While these impacts cannot be reliably predicted at this time, the RGGI program, including the Maine, New York and Connecticut CO₂ control programs, could have far-reaching and significant impacts on the energy industry.

Officials in other states where we have generation assets have expressed intentions to regulate greenhouse gasses and we are paying close attention to legislative and regulatory developments in those jurisdictions. However, at this time we cannot predict the potential impact of greenhouse gas regulation in these jurisdictions on our future financial condition, results of operations or cash flows.

Federal Greenhouse Gas Regulation. Despite a great deal of support in the energy industry for a comprehensive federal program, and numerous proposals in Congress, no proposal for the regulation of greenhouse gas emissions which addresses the issue of global warming has been enacted. On April 2, 2007, the U. S. Supreme Court issued its decision in Massachusetts v. Environmental Protection Agency, a case involving regulation of CO₂ emissions of motor vehicles. The Court ruled that CO₂ is a pollutant subject to regulation under the Clean Air Act and that the EPA has a duty to determine whether CO₂ emissions contribute to climate change. This decision, together with increasing state and federal legislative and regulatory initiatives and other related activities, may lead to federal regulation of greenhouse gas emissions. The timing of any such regulation and its impact on us and the rest of the power generation industry cannot yet be determined.

Note 13—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully described in Note 20—Employee Compensation, Savings and Pension Plans beginning on page F-61 of Dynegy’s Form 10-K, and Note 18—Employee Compensation, Savings and Pension Plans beginning on page F-45 of DHI’s Form 10-K.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

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


	Pension Benefits						Other Benefits
	Three Months Ended September 30,
	2007			2006			2007		2006
	(in millions)
Service cost benefits earned during period	$	2		$	2		$	1	$	—
Interest cost on projected benefit obligation		3			2			1		—
Expected return on plan assets		(3	)		(2	)		—		—
Recognized net actuarial loss		1			1			—		1

Net periodic benefit cost	$	3		$	3		$	2	$	1
Additional cost due to curtailment		—			1			—		—

Total net periodic benefit cost	$	3		$	4		$	2	$	1


	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2007			2006			2007		2006
	(in millions)
Service cost benefits earned during period	$	7		$	7		$	2	$	2
Interest cost on projected benefit obligation		8			7			3		2
Expected return on plan assets		(9	)		(7	)		—		—
Recognized net actuarial loss		2			2			1		1

Net periodic benefit cost	$	8		$	9		$	6	$	5
Additional cost due to curtailment		—			3			—		—

Total net periodic benefit cost	$	8		$	12		$	6	$	5

Exchange Transaction with Chairman and CEO. On March 17, 2006, Dynegy entered into an exchange transaction with Dynegy’s Chairman and CEO. Under the terms of the transaction, the purpose of which was to address uncertainties created by proposed regulations issued in late 2005 pursuant to Section 409A of the Internal Revenue Code (the “Code”), Dynegy cancelled all of the 2,378,605 stock options then held by Dynegy’s Chairman and CEO. As consideration for canceling these stock options, Dynegy granted its Chairman and CEO 967,707 stock options at an exercise price of $4.88, which equaled the closing price of Dynegy’s Class A common stock on the date of grant, and DHI made a cash payment to him of approximately $6 million on January 15, 2007 based on the in-the-money value of the vested stock options that were cancelled.

Contributions. During the nine months ended September 30, 2007, we made approximately $14 million in contributions to our pension plans. We expect to make contributions of approximately $1 million to other benefit plans in the fourth quarter 2007.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Note 14—Income Taxes

Effective Tax Rate. 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. Dynegy’s income taxes included in continuing operations were as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(in millions, except rates)
Income tax (expense) benefit	$	(59	)	$	41		$	(95	)	$	150
Effective tax rate		38	%		37	%		35	%		36	%

For the three months ended September 30, 2007, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. As a result of the Merger Agreement, our effective state tax rate increased primarily as a result of the higher state tax rates in the states in which the LS Contributed Entities’ assets are located. This increase was more than offset by the impact of decreases in the New York state income tax rate, the Texas margin tax credit rate and adjustments to Dynegy’s reserve for uncertain tax positions during the nine months ended September 30, 2007.

DHI’s income taxes included in continuing operations were as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(in millions, except rates)
Income tax (expense) benefit	$	(62	)	$	43		$	(94	)	$	132
Effective tax rate		39	%		38	%		32	%		36	%

For the three months ended September 30, 2007, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35% due primarily to state income taxes. As a result of the Merger Agreement, our effective state tax rate increased primarily as a result of the higher state tax rates in the states in which the LS Contributed Entities’ assets are located. This increase was more than offset by the impact of decreases in the New York state income tax rate, the Texas margin tax credit rate and adjustments to DHI’s reserve for uncertain tax positions during the nine months ended September 30, 2007.

Dynegy and DHI recorded a $7 million and $13 million decrease, respectively, to their accumulated deficits as of January 1, 2007 to reflect the cumulative effect of adopting FIN No. 48. Please see Note 1—Accounting Policies—Accounting Principles Adopted—FIN No. 48 for further discussion.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Note 15—Segment Information

We report results of our power generation business in the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Following the completion of the Merger Agreement in April 2007, our previously named South segment (“GEN-SO”) has been renamed the GEN-WE segment and the power generation facilities located in California and Arizona acquired through the Merger Agreement are included in this segment. The Kendall, Ontelaunee and Plum Point power generation facilities acquired through the Merger Agreement are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger Agreement are included in GEN-NE. We continue to separately report the results of our CRM business. Results associated with our former NGL segment are included in discontinued operations in Other and Eliminations due to the sale of this business. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our unaudited condensed consolidated financial statements.

Pursuant to EITF Issue 02-03, all gains and losses on third party energy trading contracts in the CRM segment, whether realized or unrealized, are presented net in the 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, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). In the second quarter 2007, we discontinued the use of hedge accounting for certain derivative transactions affecting the GEN-MW, GEN-NE and GEN-WE segments. The operating results presented herein reflect the changes in market values of derivative instruments entered into by each of these segments. Please see Note 5-Risk Management Activities for further discussion.

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Dynegy’s Segment Data for the Three Months Ended September 30, 2007
(in millions)

Reportable segment information for Dynegy, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2007 and 2006 is presented below:


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	392		$	354		$	264		$	4		$	—		$	1,014
Other		—			—			32			—			—			32

Total revenues	$	392		$	354		$	296		$	4		$	—		$	1,046

Depreciation and amortization	$	(51	)	$	(25	)	$	(12	)	$	—		$	(4	)	$	(92	)

Operating income (loss)	$	139		$	119		$	52		$	(12	)	$	(51	)	$	247

Earnings (losses) from unconsolidated investments		—			12			—			—			(4	)		8
Other items, net		1			—			—			(2	)		18			17
Interest expense																	(117	)

Income from continuing operations before income taxes																	155
Income tax expense																	(59	)

Income from continuing operations																	96
Income from discontinued operations, net of taxes																	124

Net income																$	220

Identifiable assets:
Domestic	$	6,564		$	3,411		$	2,032		$	294		$	1,045		$	13,346
Other		—			7			14			37			—			58


Total	$	6,564		$	3,418		$	2,046		$	331		$	1,045		$	13,404

Unconsolidated investments	$	—		$	35		$	—		$	—		$	61		$	96

Capital expenditures and investments in unconsolidated affiliates	$	(72	)	$	(5	)	$	(5	)	$	—		$	(3	)	$	(85	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Dynegy’s Segment Data for the Three Months Ended September 30, 2006
(in millions)


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	260		$	24		$	182		$	20		$	—		$	486
Other		—			—			18			4			—			22

		260			24			200			24			—			508
Intersegment revenues		—			—			(1	)		1			—			—

Total revenues	$	260		$	24		$	199		$	25		$	—		$	508

Depreciation and amortization	$	(43	)	$	(2	)	$	(6	)	$	—		$	(3	)	$	(54	)
Impairment and other charges		(96	)		—			—			—			—			(96	)

Operating income (loss)	$	(10	)	$	6		$	33		$	(9	)	$	(40	)	$	(20	)
Earnings from unconsolidated investments		—			4			—			—			—			4
Other items, net		1			—			2			2			6			11
Interest expense																	(107	)

Loss from continuing operations before income taxes																	(112	)
Income tax benefit																	41

Loss from continuing operations																	(71	)
Income from discontinued operations, net of taxes																	2

Net loss																$	(69	)

Identifiable assets:
Domestic	$	4,719		$	747		$	1,371		$	364		$	199		$	7,400
Other		—			2			10			95			—			107

Total	$	4,719		$	749		$	1,381		$	459		$	199		$	7,507

Unconsolidated investments	$	—		$	7		$	—		$	—		$	—		$	7
Capital expenditures	$	(22	)	$	(4	)	$	(5	)	$	—		$	(2	)	$	(33	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Dynegy’s Segment Data for the Nine Months Ended September 30, 2007
(in millions)


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	1,070		$	499		$	690		$	10		$	—		$	2,269
Other		—			—			109			1			—			110

Total revenues	$	1,070		$	499		$	799		$	11		$	—		$	2,379

Depreciation and amortization	$	(143	)	$	(49	)	$	(30	)	$	—		$	(10	)	$	(232	)

Operating income (loss)	$	399		$	105		$	148		$	17		$	(159	)	$	510

Earnings (losses) from unconsolidated investments		—			12			—			—			(6	)		6
Other items, net		(8	)		—			—			(5	)		39			26
Interest expense																	(268	)

Income from continuing operations before income taxes																	274
Income tax expense																	(95	)

Income from continuing operations																	179
Income from discontinued operations, net of taxes																	131

Net income																$	310

Identifiable assets:
Domestic	$	6,564		$	3,411		$	2,032		$	294		$	1,045		$	13,346
Other		—			7			14			37			—			58

Total	$	6,564		$	3,418		$	2,046		$	331		$	1,045		$	13,404

Unconsolidated investments	$	—		$	35		$	—		$	—		$	61		$	96
Capital expenditures and investments in unconsolidated affiliates	$	(187	)	$	(16	)	$	(24	)	$	—		$	(16	)	$	(243	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Dynegy’s Segment Data for the Nine Months Ended September 30, 2006
(in millions)


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	744		$	83		$	410		$	69		$	—		$	1,306
Other		—			—			109			12			—			121

		744			83			519			81			—			1,427
Intersegment revenues		—			—			(3	)		3			—			—

Total revenues	$	744		$	83		$	516		$	84		$	—		$	1,427

Depreciation and amortization	$	(126	)	$	(6	)	$	(18	)	$	—		$	(14	)	$	(164	)
Impairment and other charges		(96	)		(9	)		—			—			(2	)		(107	)

Operating income (loss)	$	159		$	(2	)	$	59		$	(3	)	$	(121	)	$	92
Earnings from unconsolidated investments		—			6			—			—			—			6
Other items, net		1			1			6			1			32			41
Interest expense																	(559	)

Loss from continuing operations before income taxes																	(420	)
Income tax benefit																	150

Loss from continuing operations																	(270	)
Loss from discontinued operations, net of taxes																	(6	)
Cumulative effect of change in accounting principle, net of taxes																	1

Net loss																$	(275	)

Identifiable assets:
Domestic	$	4,719		$	747		$	1,371		$	364		$	199		$	7,400
Other		—			2			10			95			—			107

Total	$	4,719		$	749		$	1,381		$	459		$	199		$	7,507

Unconsolidated investments	$	—		$	7		$	—		$	—		$	—		$	7
Capital expenditures	$	(58	)	$	(16	)	$	(12	)	$	—		$	(6	)	$	(92	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2007 and 2006 is presented below:

DHI’s Segment Data for the Three Months Ended September 30, 2007
(in millions)


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	392		$	354		$	264		$	4		$	—		$	1,014
Other		—			—			32			—			—			32

Total revenues	$	392		$	354		$	296		$	4		$	—		$	1,046

Depreciation and amortization	$	(51	)	$	(25	)	$	(12	)	$	—		$	(4	)	$	(92	)

Operating income (loss)	$	139		$	119		$	52		$	(12	)	$	(51	)	$	247

Earnings from unconsolidated investments		—			12			—			—			—			12
Other items, net		1			—			—			(2	)		19			18
Interest expense																	(117	)

Income from continuing operations before income taxes																	160
Income tax expense																	(62	)

Income from continuing operations																	98
Income from discontinued operations, net of taxes																	124

Net income																$	222

Identifiable assets:
Domestic	$	6,564		$	3,358		$	2,032		$	317		$	1,756		$	14,027
Other		—			—			14			14			—			28

Total	$	6,564		$	3,358		$	2,046		$	331		$	1,756		$	14,055

Unconsolidated investments	$	—		$	35		$	—		$	—		$	—		$	35
Capital expenditures	$	(72	)	$	(3	)	$	(5	)	$	—		$	(3	)	$	(83	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

DHI’s Segment Data for the Three Months Ended September 30, 2006
(in millions)


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	260		$	24		$	182		$	20		$	—		$	486
Other		—			—			18			4			—			22

		260			24			200			24			—			508
Intersegment revenues		—			—			(1	)		1			—			—

Total revenues	$	260		$	24		$	199		$	25		$	—		$	508

Depreciation and amortization	$	(43	)	$	(2	)	$	(6	)	$	—		$	(3	)	$	(54	)
Impairment and other charges		(96	)		—			—			—			—			(96	)

Operating income (loss)	$	(10	)	$	6		$	33		$	(9	)	$	(39	)	$	(19	)
Earnings from unconsolidated investments		—			4			—			—			—			4
Other items, net		1			—			2			2			4			9
Interest expense and debt conversion costs																	(107	)

Loss from continuing operations before income taxes																	(113	)
Income tax benefit																	43

Loss from continuing operations																	(70	)
Income from discontinued operations, net of taxes																	3

Net loss																$	(67	)

Identifiable assets:
Domestic	$	4,719		$	748		$	1,387		$	387		$	744		$	7,985
Other		—			—			10			71			—			81

Total	$	4,719		$	748		$	1,397		$	458		$	744		$	8,066

Unconsolidated investments	$	—		$	7		$	—		$	—		$	—		$	7
Capital expenditures	$	(22	)	$	(4	)	$	(5	)	$	—		$	(2	)	$	(33	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

DHI’s Segment Data for the Nine Months Ended September 30, 2007
(in millions)


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	1,070		$	499		$	690		$	10		$	—		$	2,269
Other		—			—			109			1			—			110

Total revenues	$	1,070		$	499		$	799		$	11		$	—		$	2,379

Depreciation and amortization	$	(143	)	$	(49	)	$	(30	)	$	—		$	(10	)	$	(232	)

Operating income (loss)	$	399		$	105		$	148		$	17		$	(140	)	$	529

Earnings from unconsolidated investments		—			12			—			—			—			12
Other items, net		(8	)		—			—			(5	)		38			25
Interest expense																	(268	)

Income from continuing operations before income taxes																	298
Income tax expense																	(94	)

Income from continuing operations																	204
Income from discontinued operations, net of taxes																	130

Net income loss																$	334

Identifiable assets:
Domestic	$	6,564		$	3,358		$	2,032		$	317		$	1,756		$	14,027
Other		—			—			14			14			—			28

Total	$	6,564		$	3,358		$	2,046		$	331		$	1,756		$	14,055

Unconsolidated investments	$	—		$	35		$	—		$	—		$	—		$	35
Capital expenditures	$	(187	)	$	(14	)	$	(24	)	$	—		$	(11	)	$	(236	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

DHI’s Segment Data for the Nine Months Ended September 30, 2006
(in millions)


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
Unaffiliated revenues:
Domestic	$	744		$	83		$	410		$	69		$	—		$	1,306
Other		—			—			109			12			—			121

		744			83			519			81			—			1,427
Intersegment revenues		—			—			(3	)		3			—			—

Total revenues	$	744		$	83		$	516		$	84		$	—		$	1,427

Depreciation and amortization	$	(126	)	$	(6	)	$	(18	)	$	—		$	(14	)	$	(164	)
Impairment and other charges		(96	)		(9	)		—			—			(2	)		(107	)

Operating income (loss)	$	159		$	(2	)	$	59		$	(3	)	$	(119	)	$	94
Earnings from unconsolidated investments		—			6			—			—			—			6
Other items, net		1			1			6			1			27			36
Interest expense and debt conversion costs																	(507	)

Loss from continuing operations before income taxes																	(371	)
Income tax benefit																	132

Loss from continuing operations																	(239	)
Loss from discontinued operations, net of taxes																	(6	)

Net loss																$	(245	)

Identifiable assets:
Domestic	$	4,719		$	748		$	1,387		$	387		$	744		$	7,985
Other		—			—			10			71			—			81

Total	$	4,719		$	748		$	1,397		$	458		$	744		$	8,066

Unconsolidated investments	$	—		$	7		$	—		$	—		$	—		$	7
Capital expenditures	$	(58	)	$	(16	)	$	(12	)	$	—		$	(6	)	$	(92	)

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2007 and 2006

Note 16—Subsequent Events

On October 15, 2007, pursuant to a registration rights agreement pertaining to the Notes, DHI initiated an exchange offer of $1.1 billion aggregate principal amount of DHI’s 7.75% Senior Unsecured Notes due 2019 and $550 million aggregate principal amount of its 7.50% Senior Unsecured Notes due 2015 which is expected to be completed in the fourth quarter 2007. Please see Note 8—Debt—Senior Unsecured Notes Offering for further discussion.

On October 25, 2007, we entered into an agreement to sell a non-controlling ownership interest in PPEA for approximately $82 million. Please see Note 7—Variable Interest Entities—PPEA Holding Company LLC for further discussion.

DYNEGY INC. and DYNEGY HOLDINGS INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

For the Interim Periods Ended September 30, 2007 and 2006

Item 2—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

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 Forms 10-K.

In April 2007, Dynegy contributed to DHI its interest in New York Holdings. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities of New York Holdings were recorded by DHI at Dynegy’s historical cost on the acquisition date. This management’s discussion and analysis of financial condition and results of operations included herein with respect to DHI reflects the contribution as though DHI had owned New York Holdings in all periods presented.

General

We are holding companies and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three separate segments in our consolidated financial statements: (1) the Midwest segment (“GEN-MW”); (2) the West segment (“GEN-WE”); and (3) the Northeast segment (“GEN-NE”). We also separately report results of our CRM business, which primarily consists of our legacy physical gas supply contracts and gas transportation contracts and remaining legacy power and emission trading positions that remain from the third-party trading business that was substantially exited in 2002. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our consolidated financial statements. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. In connection with the Merger Agreement discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, our previously named South segment (“GEN-SO”) has been renamed GEN-WE and the power generation facilities located in California and Arizona acquired through the Merger Agreement are included in this segment. The Kendall and Ontelaunee power generation facilities acquired through the Merger Agreement are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger Agreement are included in GEN-NE.

In addition to our operating generation facilities, we own an approximate 70% interest in PPEA which in turn owns a 57% undivided interest in Plum Point, a new 665 MW coal-fired power generation facility under construction in Arkansas, which is included in GEN-MW. On October 25, 2007, we entered into an agreement to sell a non-controlling ownership interest in PPEA for approximately $82 million. We also own a 50% interest in SCEA, which owns a 75% undivided interest in Sandy Creek, an 898 MW power generation facility under construction in McLennan County, Texas, which is included in GEN-WE. Finally, through its interest in DLS Power Holdings, Dynegy owns a 50% interest in a portfolio of greenfield development projects totaling more than 6,700 MW of generating capacity and repowering and/or expansion opportunities representing approximately 2,500 MW of generating capacity, which is included in Other.

Recent Developments

CoGen Lyondell Sale. On August 1, 2007, we completed our sale of our CoGen Lyondell power generation facility for approximately $470 million to EnergyCo., LLC (“EnergyCo.”), a joint venture between PNM Resources and a subsidiary of Cascade Investment, LLC. We recorded a $210 million gain related to the sale of the asset in the third quarter 2007.

Illinois Rate Relief. Legislative leaders from the State of Illinois, including the Speaker of the House and the Senate President, announced a comprehensive transitional rate relief package for electric consumers on July 23, 2007. The program, which became law in August 2007, will provide approximately $1 billion to help fund a new power procurement agency and provide assistance to utility customers in Illinois.

As a part of this rate relief package, we will make payments of up to $25 million over a 29-month period. These payments will be contingent on certain conditions related to the absence of future electric rate and tax legislation in Illinois. We made a payment of $7.5 million in the third quarter 2007 and anticipate making payments of $9.0 million in 2008 and $8.5 million in 2009. Our payment of $7.5 million in 2007 was used as funding for the Illinois Power Agency, which was created as part of Illinois’ comprehensive rate relief package. Our expected payments for 2008 and 2009 will be made in monthly installments, provided that if at any time prior to December 2009, as further described in the rate relief package and related agreements, Illinois imposes an electric rate freeze or imposes an additional tax on generators, our obligations to make the monthly payments will cease. The monthly payments will be paid into an escrow account established to support rate relief activities for Ameren Illinois Utilities’ customers. The rate relief package and related agreements have resulted in motions to dismiss several ongoing court and regulatory cases surrounding the 2006 Illinois reverse power procurement auction. We recorded a second quarter 2007 pre-tax charge of $25 million, included as a cost of sales on our unaudited condensed consolidated statements of operations. Please read Note 11—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

The contracts originally entered into by DPM and the Ameren Illinois Utilities as a result of the auction remain in place following the effectiveness of the rate relief package and related agreements.

Sandy Creek. In connection with its acquisition of a 50% interest in DLS Power Holdings, as further discussed above, Dynegy acquired a 50% interest in Sandy Creek Energy Associates, LP (“SCEA”). SCEA owns the Sandy Creek Energy Station (the “Project”), which is a proposed 898 MW facility to be located in McLennan County, Texas. In August 2007, Sandy Creek Holdings, LLC (“SCH”) became a stand-alone entity separate from DLS Power Holdings and SCH and its wholly owned subsidiaries, including SCEA, entered into various financing agreements to construct the Project and sold a 25% undivided interest in the Project to an unrelated third party.

The financing agreements consist of a $200 million term loan and $800 million in construction loans with SCEA as borrower. The SCEA debt is secured by a pledge of SCEA’s assets, contract rights and SCEA’s undivided tenancy in common interest in the Project.

In addition, SCH entered into a $200 million credit agreement with the Dynegy Member and the LSP Member, as defined below. The SCH debt is secured by a pledge of SCH’s indirect ownership interests in SCEA. To fund its obligation under the SCH Equity Agreement, SCH entered into a credit agreement with the Dynegy Member and the LSP Member. The Dynegy Member’s 50% share of the credit agreement is supported by a letter of credit issued under DHI’s primary credit facility in the amount of $100 million. Such letter of credit may be drawn upon by the lenders if certain conditions are met. The Dynegy Member and the LS Member each agreed to make capital contributions of $223 million to fund project costs after the SCEA and SCH loans have been utilized and otherwise upon the occurrence of certain events and milestone dates. The Dynegy Member’s obligation to make such contributions is supported by a letter of credit in the amount of $223 million issued under the Fifth Amended and Restated Credit Facility. Such letter of credit may be drawn upon by the SCEA lenders if certain conditions are met.

Upon the close of the financing agreements discussed above, SCEA sold a 25% undivided interest in the Project to an unaffiliated third party for approximately $30 million plus a portion of the accumulated construction costs. During the third quarter 2007, we recognized our share of the gain on the sale, which approximated $12 million, in Earnings from unconsolidated investments on the unaudited condensed consolidated statements of operations. During the third quarter 2007, SCEA received $24 million in cash proceeds, consisting of approximately $15 million of the purchase price and $9 million for its share of accumulated costs. The remainder of the purchase price, plus accrued interest, is expected to be collected in 2010. SCEA will distribute the proceeds from the sale to the Dynegy Member and the LSP Member during the fourth quarter 2007. Please read Note 7—Variable Interest Entities—Sandy Creek for further information.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe 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, legal settlements and working capital needs. Examples of working capital needs include prepayments or cash collateral associated with purchases of commodities, particularly natural gas and coal, facility maintenance costs (including required environmental expenditures) and other costs such as payroll. Our liquidity and capital resources are primarily derived from cash flows from operations, cash on hand, borrowings under our financing agreements, asset sale proceeds and proceeds from capital market transactions to the extent we engage in these activities. Additionally, DHI may borrow money from time to time from Dynegy.

Debt Obligations

On April 2, 2007, we assumed approximately $1.9 billion of debt upon completion of the Merger Agreement. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

Also on April 2, 2007, in connection with the completion of the transactions contemplated by the Merger Agreement, an aggregate $275 million under the Revolving Facility, an aggregate $400 million under the Term L/C Facility (with the proceeds placed in a collateral account to support the issuance of letters of credit) and an aggregate $70 million under Term Loan B (representing all available borrowings under Term Loan B) were drawn under the Fifth Amended and Restated Credit Agreement.

On May 24, 2007, we entered into the Credit Agreement Amendment. The Credit Agreement Amendment amended the Fifth Amended and Restated Credit Facility by increasing the amount of the existing $850 million Revolving Facility to $1.15 billion and increasing the amount of the existing $400 million term letter of the Term L/C Facility to $850 million; the Credit Agreement Amendment did not affect the Term Loan B. The Credit Agreement Amendment also amended a pro forma leverage ratio requirement in the Fifth Amended and Restated Credit Facility to allow DHI to issue the Notes.

On May 24, 2007, DHI issued $1.1 billion aggregate principal amount of its 2019 Notes and $550 million aggregate principal amount of its 2015 Notes. DHI used the net proceeds from the sale of the Notes to repay a portion of the debt assumed in the Merger Agreement with LS Power.

On August 6, 2007, we subsequently repaid the $275 million borrowed under the Revolving Facility. On September 7, 2007, we completed the redemption of $11 million of DHI’s remaining outstanding 9.875% Second Priority Secured Notes due 2010 at a redemption price of 104.938% of the principal amount plus accrued and unpaid interest to the redemption date. Please read Note 8—Debt for further discussion of these items.

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 business at November 1, 2007, September 30, 2007 and December 31, 2006:


	November 1,		September 30,		December 31,
	2007		2007		2006
	(in millions)
By Business:
Generation	$	1,148	$	1,169	$	134
Customer Risk Management		33		38		54
Other		191		191		7

Total	$	1,372	$	1,398	$	195

By Type:
Cash (1)	$	76	$	62	$	38
Letters of Credit		1,296		1,336		157

Total	$	1,372	$	1,398	$	195


(1)		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.

The majority of the increase in collateral postings from December 31, 2006 to September 30, 2007 relates to an increase of approximately $700 million due to the completion of the Merger Agreement and incorporation of the letters of credit postings required by the LS Contributing Entities. The $700 million is comprised of the following: approximately $325 million relating to hedging activities; approximately $130 million of development requirements; approximately $100 million as required under LTSAs and EMAs; approximately $90 million for environmental related requirements; and approximately $50 million of collateral requirements under transport and transmission agreements. During 2007, we also issued two letters of credit totaling $323 million in conjunction with the Sandy Creek power generation facility development and an $83 million letter of credit to satisfy the Sithe debt service reserve fund requirements that was previously funded with restricted cash. The balance of the increase relates to price and volume changes associated with collateral postings supporting our normal power and fuel purchases and sales.

Going forward, we expect counterparties’ collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness. We believe that we have sufficient capital resources to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted, for the foreseeable future.

Tax Attributes

For accounting purposes, at January 1, 2007, Dynegy’s NOL deferred tax asset attributable to our previously incurred federal NOL carry-forwards was valued at approximately $695 million. These NOL carry-forwards will begin to expire in the year 2022. As a result of the application of the provisions of Section 382 of the Internal Revenue Code, when CUSA sold its shares of Dynegy’s class A common stock in the second quarter 2007, Dynegy incurred an ownership change that established an annual limitation on the usage of our NOL carry-forwards. The limitation is based in part on the market value of Dynegy’s stock at the time of the ownership change and the then-prevailing interest rate and in part on certain built-in gains recognized in a particular taxable year.

The magnitude of the limitation and its effect on us is difficult to assess and may fluctuate depending on the amount of recognized built-in gains in a particular taxable year. However, we do not expect that the ownership change that occurred will have a material impact on Dynegy’s tax liability, because of the application of the built-in gain provisions of Section 382. The ultimate realization of Dynegy’s NOL carry-forwards will be affected, in part, by the tax law in effect at the time of realization.

Disclosure of Contractual Obligations and Contingent Financial Commitments

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

Our contractual obligations and contingent financial commitments have changed since December 31, 2006. On April 2, 2007, in conjunction with the completion of the Merger Agreement, we assumed approximately $1 billion of contractual obligations in addition to the long-term debt assumed. These obligations primarily related to interconnection, operations and maintenance, long term service, and gas transportation agreements. Further, upon completion of the Merger Agreement, our obligations under our power tolling arrangement related to the Kendall facility became an intercompany obligation. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion. On May 24, 2007, we completed a $1.65 billion offering of senior unsecured notes. Please also read Note 8—Debt for a discussion of these and other changes in our debt obligations.

As of September 30, 2007, there were no other material changes to our contractual obligations and contingent financial commitments since December 31, 2006.

Dividends on Common Stock

Dividend payments on Dynegy’s common stock are at the discretion of Dynegy’s Board of Directors. Dynegy did not declare or pay a dividend on its common stock during the third quarter 2007, and does not foresee a declaration of dividends in the near term.

Internal Liquidity Sources

Our primary internal liquidity sources are cash flows from operations, cash on hand and available capacity under our Fifth Amended and Restated Credit Facility, as amended, which is scheduled to mature in April 2012.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at November 1, 2007, September 30, 2007 and December 31, 2006:


	November 1,			September 30,			December 31,
	2007			2007 (1)			2006
	(in millions)
Revolver capacity	$	1,150		$	1,150		$	470
Borrowings against revolver capacity		—			—			—
Term letter of credit capacity, net of required reserves		825			825			194
Plum Point letter of credit capacity		101			101			—
Outstanding letters of credit		(1,296	)		(1,336	)		(157	)

Unused capacity		780			740			507
Cash—DHI		503	(2)		594	(2)		243	(2)

Total available liquidity—DHI		1,283			1,334			750
Cash—Dynegy		37			44			128

Total available liquidity—Dynegy	$	1,320		$	1,378		$	878


(1)		In April 2007, we amended and restated the credit facility, and in May 2007, we further amended it. Please see Note 8—Debt—Fifth Amended and Restated Credit Facility for further discussion.

(2)		The November 1, 2007, September 30, 2007 and December 31, 2006 amounts include approximately zero, $2 million and $46 million, respectively, of cash that remains in Europe and $4 million, $12 million and $10 million, respectively, of cash that remains in Canada.

Cash Flows from Operations. Dynegy had operating cash inflows of $366 million for the nine months ended September 30, 2007. This consisted of $736 million in operating cash flows from our power generation business, offset by $24 million of cash outflows relating to our customer risk management business and $346 million of cash outflows relating to corporate-level expenses.

DHI had operating cash inflows of $375 million for the nine months ended September 30, 2007. This consisted of $736 million in operating cash flows from our power generation business, offset by $24 million of cash outflows relating to our customer risk management business and $337 million of cash outflows relating to corporate-level expenses.

Please read “—Results of Operations—Operating Income (Loss)” and “—Cash Flow Disclosures” for further discussion of factors impacting our operating cash flows for the periods presented.

Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of natural gas and its correlation to power prices, the cost of coal and fuel oil, and the value of ancillary services and capacity. Additionally, availability of our plants during peak demand periods will be required to allow us to capture attractive market prices when available. Over the longer term, our operating cash flows also will be impacted by, among other things, our ability to tightly manage our operating costs, including maintenance costs in balance with ensuring that our plants are available to operate when markets offer attractive returns.

Cash on Hand. At November 1, 2007 and September 30, 2007, Dynegy had cash on hand of $540 million and $638 million, respectively, as compared to $371 million at the end of 2006. The increase in cash on hand at September 30, 2007 as compared to the end of 2006 is primarily attributable to cash provided by the operating activities of our generating business and proceeds received from the sale of our CoGen Lyondell facility offset by cash paid in connection with the Merger Agreement.

At November 1, 2007 and September 30, 2007, DHI had cash on hand of $503 million and $594 million, respectively, as compared to $243 million at the end of 2006. The increase in cash on hand at September 30, 2007 as compared to the end of 2006 is primarily attributable to cash provided by the operating activities of our generation business and proceeds received from the sale of our CoGen Lyondell facility offset by dividend payments made to Dynegy.

Revolver Capacity. On April 2, 2007, DHI entered into the Fifth Amended and Restated Credit Facility, which is our primary credit facility. On May 24, 2007, DHI entered into an amendment to the Fifth Amended and Restated Credit Facility. Please read Note 8—Debt—Fifth Amended and Restated Credit Facility for further discussion.

External Liquidity Sources

Our primary external liquidity sources are proceeds from asset sales and other types of capital-raising transactions, including potential debt and equity issuances.

Asset Sale Proceeds. On October 25, 2007, we entered into an agreement to sell a non-controlling ownership interest in PPEA for approximately $82 million. Please see Note 7—Variable Interest Entities—PPEA Holding Company LLC for further discussion.

On August 1, 2007, we completed our sale of our CoGen Lyondell power generation facility for approximately $470 million. Please read Note 3—Discontinued Operations—GEN-WE Discontinued Operations—Cogen Lyondell for further discussion.

On January 31, 2007, we entered into an agreement to sell our interest in the Calcasieu power generation facility for approximately $57 million, subject to regulatory approval. The transaction is expected to close in early 2008. Please read
Note 3—Discontinued Operations—GEN-WE Discontinued Operations—Calcasieu for further discussion.

Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. We consider divestitures of non-core generation assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the value that can be captured through a divestiture outweighs the benefits of continuing to own and operate such assets. In connection with this review, we are considering options to potentially sell our 576 MW Bluegrass generation facility and our 539 MW Heard County generation facility. Moreover, dispositions of one or more generation facilities could occur in 2008 or beyond. Were any such sale or disposition to be consummated, the disposition could result in accounting charges related to the affected asset(s), and our future earnings and cash flows could be affected.

Capital-Raising Transactions. As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we may explore additional sources of external liquidity. The timing of any transaction may be impacted by events, such as strategic growth opportunities, development activities, legal judgments or regulatory requirements, which could require us to pursue additional capital in the near-term. The receptiveness of the capital markets to an offering of debt or equity securities 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 by Dynegy likely would have other effects as well, including stockholder dilution. Our ability to issue debt securities is limited by our financing agreements, including our Fifth Amended and Restated Credit Facility, as amended. Please read Note 8—Debt for further discussion.

In addition, we continually review and discuss opportunities to grow our company and to participate in what we believe will be continuing consolidation of the power generation industry. No such definitive transaction has been agreed to and none can be guaranteed to occur; however, we have successfully executed on similar opportunities in the past and could do so again in the future. Depending on the terms and structure of any such transaction, we could issue significant debt and/or equity securities for capital-raising purposes. We also could be required to assume substantial debt obligations and the underlying payment obligations.

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

RESULTS OF OPERATIONS—DYNEGY INC. and DYNEGY HOLDINGS INC.

Overview. 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, 2007 and 2006. At the end of this section, we have included our outlook for each segment.

We report results of our power generation business in the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Following the completion of the Merger Agreement in April 2007, our previously named South segment has been renamed the GEN-WE segment and the power generation facilities located in California and Arizona acquired through the Merger Agreement are included in this segment. The Kendall, Ontelaunee and Plum Point power generation facilities acquired through the Merger Agreement are included in GEN-MW, and the Casco Bay and Bridgeport power generation facilities acquired through the Merger Agreement are included in GEN-NE. We also separately report results of our CRM business, which primarily consists of legacy physical gas supply contracts and gas transportation contracts and remaining legacy power and emission trading positions that remain from the third-party trading business that was substantially exited in 2002. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization. Because of the diversity among their respective operations, we report the results of each business as a separate segment in our unaudited condensed consolidated financial statements.

Three Months Ended September 30, 2007 and 2006

Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the three-month periods ended September 30, 2007 and 2006, respectively:

Dynegy’s Results of Operations for the Three Months Ended September 30, 2007


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	392		$	354		$	296		$	4		$	—		$	1,046
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(202	)		(210	)		(232	)		(4	)		(1	)		(649	)
Depreciation and amortization expense		(51	)		(25	)		(12	)		—			(4	)		(92	)
Gain on sale of assets, net		—			—			—			4			—			4
General and administrative expense		—			—			—			(16	)		(46	)		(62	)

Operating income (loss)	$	139		$	119		$	52		$	(12	)	$	(51	)	$	247
Earnings (losses) from unconsolidated investments		—			12			—			—			(4	)		8
Other items, net		1			—			—			(2	)		18			17
Interest expense																	(117	)

Income from continuing operations before income taxes																	155
Income tax expense																	(59	)

Income from continuing operations																	96
Income from discontinued operations, net of taxes																	124

Net income																$	220

Dynegy’s Results of Operations for the Three Months Ended September 30, 2006


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	260		$	24		$	199		$	25		$	—		$	508
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(131	)		(16	)		(160	)		(12	)		—			(319	)
Depreciation and amortization expense		(43	)		(2	)		(6	)		—			(3	)		(54	)
Impairment and other charges		(96	)		—			—			—			—			(96	)
General and administrative expense		—			—			—			(22	)		(37	)		(59	)

Operating income (loss)	$	(10	)	$	6		$	33		$	(9	)	$	(40	)	$	(20	)
Earnings from unconsolidated investments		—			4			—			—			—			4
Other items, net		1			—			2			2			6			11
Interest expense and debt conversion costs																	(107	)

Loss from continuing operations before income taxes																	(112	)
Income tax benefit																	41

Loss from continuing operations																	(71	)
Income from discontinued operations, net of taxes																	2

Net loss																$	(69	)

The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the three-month periods ended September 30, 2007 and 2006, respectively:

DHI’s Results of Operations for the Three Months Ended September 30, 2007


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	392		$	354		$	296		$	4		$	—		$	1,046
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(202	)		(210	)		(232	)		(4	)		(1	)		(649	)
Depreciation and amortization expense		(51	)		(25	)		(12	)		—			(4	)		(92	)
Gain on sale of assets, net		—			—			—			4			—			4
General and administrative expense		—			—			—			(16	)		(46	)		(62	)

Operating income (loss)	$	139		$	119		$	52		$	(12	)	$	(51	)	$	247
Earnings from unconsolidated investments		—			12			—			—			—			12
Other items, net		1			—			—			(2	)		19			18
Interest expense																	(117	)

Income from continuing operations before income taxes																	160
Income tax expense																	(62	)

Income from continuing operations																	98
Income from discontinued operations, net of taxes																	124

Net income																$	222

DHI’s Results of Operations for the Three Months Ended September 30, 2006


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	260		$	24		$	199		$	25		$	—		$	508
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(131	)		(16	)		(160	)		(12	)		—			(319	)
Depreciation and amortization expense		(43	)		(2	)		(6	)		—			(3	)		(54	)
Impairment and other charges		(96	)		—			—			—			—			(96	)
General and administrative expense		—			—			—			(22	)		(36	)		(58	)

Operating income (loss)	$	(10	)	$	6		$	33		$	(9	)	$	(39	)	$	(19	)
Earnings from unconsolidated investments		—			4			—			—			—			4
Other items, net		1			—			2			2			4			9
Interest expense and debt conversion costs																	(107	)

Loss from continuing operations before income taxes																	(113	)
Income tax benefit																	43

Loss from continuing operations																	(70	)
Income from discontinued operations, net of taxes																	3

Net loss																$	(67	)

The following table provides summary segmented operating statistics for the three months ended September 30, 2007 and 2006, respectively:


	Three Months Ended
	September 30,
	2007		2006
GEN-MW
Million Megawatt Hours Generated		7.5		5.7
Average Actual On-Peak Market Power Prices ($/MWh) (1):
Cinergy (Cin Hub)	$	64	$	58
Commonwealth Edison (NI Hub)	$	61	$	58
PJM West	$	75	$	74

GEN-WE
Million Megawatt Hours Generated (2) (3)		5.2		0.3
Average Actual On-Peak Market Power Prices ($/MWh) (1):
North Path 15 (NP 15)	$	69	$	72
Palo Verde	$	69	$	67
Average Market Spark Spreads ($/MWh):
North Path 15 (NP15)	$	24	$	27
Palo Verde	$	26	$	24

GEN-NE
Million Megawatt Hours Generated		3.2		1.7
Average Actual On-Peak Market Power Prices ($/MWh) (1):
New York—Zone G	$	78	$	84
New York—Zone A	$	64	$	62
Mass Hub	$	71	$	71
Average Market Spark Spreads ($/MWh):
New York—Zone A	$	19	$	18
Mass Hub	$	24	$	24

Average natural gas price—Henry Hub ($/MMBtu) (4)	$	6.15	$	6.08


(1)		Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the Company.

(2)		Includes our ownership percentage in the MWh generated by our GEN-WE investment in NCA#2 for the three months ended September 30, 2007 and September 30, 2006.

(3)		Excludes approximately 0.3 MWh and 0.8 MWh generated by our CoGen Lyondell facility, which we sold in August 2007, and less than 0.1 MWh and less than 0.1 MWh generated by our Calcasieu facility, which is classified as held for sale, for the three months ended September 30, 2007 and 2006, respectively.

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

The following tables summarize significant items on a pre-tax basis affecting net income (loss) for the periods presented:


	Three Months Ended September 30, 2007
	Power Generation
										Other &
	GEN-MW		GEN-WE		GEN-NE		CRM			Eliminations		Total
	(in millions)
Discontinued operations (1)	$	—	$	213	$	—	$	4		$	—	$	217
Legal and settlement charge		—		—		—		(16	)		—		(16	)
Gain on sale of Sandy Creek ownership interest		—		12		—		—			—		12

Total	$	—	$	225	$	—	$	(12	)	$	—	$	213


(1)		Discontinued operations for GEN-WE includes a $210 million pre-tax gain on the sale of the CoGen Lyondell power generation facility.


	Three Months Ended September 30, 2006
	Power Generation
												Other &
	GEN-MW			GEN-WE		GEN-NE			CRM			Eliminations		Total
	(in millions)
Asset impairment	$	(96	)	$	—	$	—		$	—		$	—	$	(96	)
Legal and settlement charges		—			—		—			(22	)		—		(22	)
Sithe subordinated debt exchange charge		—			—		(36	)		—			—		(36	)
Discontinued operations (1)		—			2		—			6			2		10

Total	$	(96	)	$	2	$	(36	)	$	(16	)	$	2	$	(144	)

Operating Income (Loss)

Operating income for Dynegy was $247 million for the three months ended September 30, 2007, compared to an operating loss of $20 million for the three months ended September 30, 2006. Operating income for DHI was $247 million for the three months ended September 30, 2007, compared to an operating loss of $19 million for the three months ended September 30, 2006.

Power Generation—Midwest Segment. Operating income for GEN-MW was $139 million for the three months ended September 30, 2007, compared to an operating loss of $10 million for the three months ended September 30, 2006. Operating income for 2006 included a $96 million pre-tax impairment charge related to the Bluegrass generation facility, due to changes in the market that resulted in economic constraints on the facility.

Results for the three months ended September 30, 2007 improved by $61 million from the three months ended September 30, 2006 as a result of higher volumes, increased market prices, improved pricing as a result of the Illinois reverse power procurement auction and the addition of the new Midwest plants acquired through the Merger, offset by mark-to market losses.

Generated volumes increased by 32%, up from 5.7 million MWh for the third quarter 2006 to 7.5 million MWh for the same period in 2007. Average actual on-peak prices in the Cin Hub pricing region increased from $58 per MWh in the third quarter 2006 to $64 per MWh for the third quarter 2007.

Beginning January 1, 2007, we began operating under two new energy product supply agreements with subsidiaries of Ameren Corporation through our participation in the Illinois reverse power procurement auction in 2006. Under these new agreements, we provide up to 1,400 MWh around the clock for prices of approximately $65 per megawatt-hour.

The Kendall and Ontelaunee plants acquired on April 2, 2007 provided results of $25 million for the three months ended September 30, 2007, exclusive of mark-to-market results discussed below.

GEN-MW’s results for the three months ended September 30, 2007 included unrealized mark-to-market losses of $29 million related to forward sales, compared to unrealized $11 million of mark-to-market gains for the three months ended September 30, 2006. Of the $29 million in 2007 mark-to-market losses, $12 million related to positions that will settle in 2007, and the remaining $17 million related to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $43 million for the third quarter 2006 to $51 million for the third quarter 2007 primarily as a result of the new Midwest plants.

Power Generation—West Segment. Operating income for GEN-WE was $119 million for three months ended September 30, 2007, compared to income of $6 million for the three months ended September 30, 2006. The 2006 results relate to our Heard County and Rockingham generation facilities. Results from our CoGen Lyondell and Calcasieu power generation facilities have been classified as discontinued operations for all periods presented.

Results for the three months ended September 30, 2007 improved by $136 million from the three months ended September 30, 2006 as a result of the addition of the new West plants acquired through the Merger and higher mark-to-market gains.

Generated volumes were 5.2 MWh for the third quarter 2007, up from 0.3 million MWh for the third quarter 2006. The volume increase was primarily driven by the new West plants. The plants provided total results of $74 million for the three months ended September 30, 2007, exclusive of mark-to-market results discussed below.

GEN-WE’s results for the three months ended September 30, 2007 included unrealized mark-to-market gains of $68 million related to heat rate call-options and forward sales agreements, compared to zero for the three months ended September 30, 2006. Of the $68 million in 2007 mark-to-market gains, $34 million related to positions that will settle in 2007, and the remaining $34 million related to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $2 million for the third quarter 2006 to $25 million for the third quarter 2007 primarily as a result of the new West plants.

Power Generation—Northeast Segment. Operating income for GEN-NE was $52 million for the three months ended September 30, 2007, compared to $33 million for the three months ended September 30, 2006.

Results for the three months ended September 30, 2007 improved by $25 million from the three months ended September 30, 2006 as a result of the addition of the new Northeast plants acquired through the Merger offset by mark-to-market losses. Additionally, a fuel oil inventory write-down of approximately $6 million was recorded in the three months ended September 30, 2006.

On peak market prices in New York Zone G decreased by 7% and Zone A increased by 3%. Average market spark spreads increased by 6% and zero for New York Zone A and Mass Hub, respectively.

Generated volumes increased by 88%, up from 1.7 million MWh for the third quarter 2006 to 3.2 million MWh for the same period in 2007. The volume increase was primarily driven by the new Northeast plants. The Bridgeport and Casco Bay plants provided total results of $30 million for the three months ended September 30, 2007, exclusive of mark-to-market results discussed below.

GEN-NE’s results for the three months ended September 30, 2007 included unrealized mark-to-market losses of $19 million related to forward sales, compared to unrealized mark-to-market losses of $7 million for the three months ended September 30, 2006. Of the $19 million in 2007 mark-to-market losses, $18 million related to positions that will settle in 2007, and the remaining $1 million loss related to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $6 million for the third quarter 2006 to $12 million for the third quarter 2007 as a result of the new Northeast plants.

CRM. Operating loss for the CRM segment was $12 million for the three months ended September 30, 2007, compared to an operating loss of $9 million for the three months ended September 30, 2006.

Results for 2007 and 2006 reflected legal charges of approximately $16 million and $22 million, respectively, resulting from additional activities during the period that negatively affected management’s assessment of the probable and estimable losses associated with the applicable proceedings. The 2007 legal charges were partially offset by a $4 million gain on the sale of NYMEX securities. The 2006 legal charges were largely offset by mark-to-market income on our legacy coal, natural gas, emissions, and power positions.

Other. Dynegy’s other operating loss for the three months ended September 30, 2007 was $51 million, compared to an operating loss of $40 million for the three months ended September 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses were $62 million and $59 million for the three months ended September 30, 2007 and 2006, respectively. General and administrative expenses for the three months ended September 30, 2007 included legal and settlement charges of $17 million, $16 million of which was reflected in our CRM segment. This compared with legal and settlement charges of $22 million in the same period of 2006, all of which were reflected in our CRM segment. The remaining increase from 2006 to 2007 was primarily a result of higher salary and employee benefit costs due to the Merger.

DHI’s other operating loss for the three months ended September 30, 2007 was $51 million, compared to an operating loss of $39 million for the three months ended September 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expenses.

DHI’s consolidated general and administrative expenses were $62 million and $58 million for the three months ended September 30, 2007 and 2006, respectively. General and administrative expenses for the three months ended September 30, 2007 included legal and settlement charges of $17 million, $16 million of which is reflected in our CRM segment. This compared with legal and settlement charges of $22 million in the same period of 2006, all of which were reflected in our CRM segment. The remaining increase from 2006 to 2007 was primarily a result of higher salary and employee benefit costs due to the Merger.

Earnings from Unconsolidated Investments

Dynegy’s earnings from unconsolidated investments were $8 million for the three months ended September 30, 2007. GEN-WE recognized $12 million of earnings related to its investment in Sandy Creek largely due to its share of the gain on SCEA’s sale of a 25% undivided interest in the Project. Please see Note 7 — Variable Interest Entities — Sandy Creek for further information. This income was partly offset by a $4 million loss related to Dynegy’s interest in DLS Power Holdings. Earnings from unconsolidated investments for the three months ended September 30, 2006 were $4 million, related to the GEN-WE investment in NCA#2.

DHI’s earnings from unconsolidated investments of $12 million for the three months ended September 30, 2007 related to its investment in Sandy Creek largely due to its share of the gain on SCEA’s sale of a 25% undivided interest in the Project. Please see Note 7 — Variable Interest Entities — Sandy Creek for further information.

Earnings from unconsolidated investments for the three months ended September 30, 2006 were $4 million, related to the GEN-WE investment in NCA#2.

Other Items, Net

Dynegy’s other items, net, totaled $17 million of net income for the three months ended September 30, 2007, compared to $11 million of income for the three months ended September 30, 2006. The increase was primarily associated with higher interest income due to larger restricted cash balances in 2007.

DHI’s other items, net, totaled $18 million of net income for the three months ended September 30, 2007, compared to $9 million of income for the three months ended September 30, 2006. The increase was primarily associated with higher interest income due to larger restricted cash balances in 2007.

Interest Expense

Dynegy’s and DHI’s interest expense and debt conversion costs totaled $117 million for the three months ended September 30, 2007, compared to $107 million for the three months ended September 30, 2006. The increase was primarily attributable to additional borrowings in connection with our Fifth Amended and Restated Credit Facility and the issuance of the $1.65 billion of Senior Unsecured Notes on May 24, 2007. This increase is partly offset by a $36 million charge was recorded in the third quarter 2006 associated with the Sithe subordinated debt exchange.

Income Tax (Expense) Benefit

Dynegy reported an income tax expense from continuing operations of $59 million for the three months ended September 30, 2007, compared to an income tax benefit from continuing operations of $41 million for the three months ended September 30, 2006. The 2007 effective tax rate was 38%, compared to 37% in 2006.

DHI reported an income tax expense from continuing operations of $62 million for the three months ended September 30, 2007, compared to an income tax benefit from continuing operations of $43 million for the three months ended September 30, 2006. The 2007 effective tax rate was 39%, compared to 38% in 2006.

In general, differences between these effective rates and the statutory rate of 35% resulted primarily from the effect of state income taxes. As a result of the Merger Agreement, our effective state tax rate increased primarily as a result of the higher state tax rates in the states in which the LS Contributed Entities assets are located.

Discontinued Operations

Income From Discontinued Operations Before Taxes. Discontinued operations include the Calcasieu and CoGen Lyondell power generation facilities in our GEN-WE segment, DMSLP in our former NGL segment and our U.K. CRM business in our CRM segment.

During the three months ended September 30, 2007, Dynegy’s pre-tax income from discontinued operations was $217 million ($124 million after-tax). Dynegy’s GEN-WE segment included earnings of $3 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities in addition to a pre-tax gain of $210 million associated with the completion of our sale of the CoGen Lyondell power generation facility.

During the three months ended September 30, 2006, Dynegy’s pre-tax income from discontinued operations was $10 million ($2 million after-tax). Dynegy’s GEN-WE segment included earnings of $2 million from the operation of the CoGen Lyondell and Calcasieu generation facilities. Dynegy’s U.K. CRM business included earnings of $6 million for the three months ended September 30, 2006, associated with the settlement of an outstanding contract. Dynegy also recorded pre-tax income of $2 million attributable to NGL.

During the three months ended September 30, 2007, DHI’s pre-tax income from discontinued operations was $217 million ($124 million after-tax). DHI’s GEN-WE segment included earnings of $3 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities in addition to a pre-tax gain of $210 million associated with the completion of our sale of the CoGen Lyondell power generation facility.

During the three months ended September 30, 2006, DHI’s pre-tax income from discontinued operations was $10 million ($3 million after-tax). DHI’s GEN-WE segment included earnings of $2 million from the operation of the CoGen Lyondell and Calcasieu generation facilities. DHI’s U.K. CRM business included earnings of $6 million for the three months ended September 30, 2006, associated with the settlement of an outstanding contract. DHI also recorded pre-tax income of $2 million attributable to NGL.

Income Tax (Expense) Benefit From Discontinued Operations.

Dynegy recorded an income tax expense from discontinued operations of $93 million during the three months ended September 30, 2007, compared to an income tax benefit from discontinued operations of $8 million during the three months ended September 30, 2006. The effective rates for the three months ended September 30, 2007 and 2006 were 43% and 80%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” requires a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%. The effective tax rate was also impacted by the $62 million of goodwill allocated to the CoGen Lyondell power generation facility upon its sale. As there was no tax basis in the goodwill, there were no tax benefits associated with the allocated goodwill.

DHI recorded an income tax expense from discontinued operations of $93 million during the three months ended September 30, 2007, compared to an income tax benefit from discontinued operations of $7 million during the three months ended September 30, 2006. The effective rates for the three months ended September 30, 2007 and 2006 were 43% and 70%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” requires a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%. The effective tax rate was also impacted by the $62 million of goodwill allocated to the CoGen Lyondell power generation facility upon its sale. As there was no tax basis in the goodwill, there were no tax benefits associated with the allocated goodwill.

Nine Months Ended September 30, 2007 and 2006

Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the nine-month periods ended September 30, 2007 and 2006, respectively:

Dynegy’s Results of Operations for the Nine Months Ended September 30, 2007


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	1,070		$	499		$	799		$	11		$	—		$	2,379
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(528	)		(345	)		(621	)		18			(2	)		(1,478	)
Depreciation and amortization expense		(143	)		(49	)		(30	)		—			(10	)		(232	)
Gain on sale of assets, net		—			—			—			4			—			4
General and administrative expense		—			—			—			(16	)		(147	)		(163	)

Operating income (loss)	$	399		$	105		$	148		$	17		$	(159	)	$	510
Earnings (losses) from unconsolidated investments		—			12			—			—			(6	)		6
Other items, net		(8	)		—			—			(5	)		39			26
Interest expense																	(268	)

Income from continuing operations before income taxes																	274
Income tax expense																	(95	)

Income from continuing operations																	179
Income from discontinued operations, net of taxes																	131


Net income																$	310

Dynegy’s Results of Operations for the Nine Months Ended September 30, 2006


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	744		$	83		$	516		$	84		$	—		$	1,427
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(363	)		(70	)		(439	)		(34	)		(1	)		(907	)
Depreciation and amortization expense		(126	)		(6	)		(18	)		—			(14	)		(164	)
Impairment and other charges		(96	)		(9	)		—			—			(2	)		(107	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(53	)		(107	)		(160	)

Operating income (loss)	$	159		$	(2	)	$	59		$	(3	)	$	(121	)	$	92
Earnings from unconsolidated investments		—			6			—			—			—			6
Other items, net		1			1			6			1			32			41
Interest expense and debt conversion costs																	(559	)

Loss from continuing operations before income taxes																	(420	)
Income tax benefit																	150

Loss from continuing operations																	(270	)
Loss from discontinued operations, net of taxes																	(6	)
Cumulative effect of change in accounting principle, net of taxes																	1

Net loss																$	(275	)

The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the nine-month periods ended September 30, 2007 and 2006, respectively:

DHI’s Results of Operations for the Nine Months Ended September 30, 2007


	Power Generation												Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	1,070		$	499		$	799		$	11		$	—		$	2,379
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(528	)		(345	)		(621	)		18			(2	)		(1,478	)
Depreciation and amortization expense		(143	)		(49	)		(30	)		—			(10	)		(232	)
Gain on sale of assets, net		—			—			—			4			—			4
General and administrative expense		—			—			—			(16	)		(128	)		(144	)

Operating income (loss)	$	399		$	105		$	148		$	17		$	(140	)	$	529
Earnings from unconsolidated investments		—			12			—			—			—			12
Other items, net		(8	)		—			—			(5	)		38			25
Interest expense																	(268	)

Income from continuing operations before income taxes																	298
Income tax expense																	(94	)

Income from continuing operations																	204
Income from discontinued operations, net of taxes																	130

Net income																$	334

DHI’s Results of Operations for the Nine Months Ended September 30, 2006


	Power Generation
													Other and
	GEN-MW			GEN-WE			GEN-NE			CRM			Eliminations			Total
	(in millions)
Revenues	$	744		$	83		$	516		$	84		$	—		$	1,427
Cost of sales, exclusive of depreciation and amortization expense shown separately below		(363	)		(70	)		(439	)		(34	)		(1	)		(907	)
Depreciation and amortization expense		(126	)		(6	)		(18	)		—			(14	)		(164	)
Impairment and other charges		(96	)		(9	)		—			—			(2	)		(107	)
Gain on sale of assets, net		—			—			—			—			3			3
General and administrative expense		—			—			—			(53	)		(105	)		(158	)

Operating income (loss)	$	159		$	(2	)	$	59		$	(3	)	$	(119	)	$	94
Earnings from unconsolidated investments		—			6			—			—			—			6
Other items, net		1			1			6			1			27			36
Interest expense and debt conversion costs																	(507	)

Loss from continuing operations before income taxes																	(371	)
Income tax benefit																	132

Loss from continuing operations																	(239	)
Loss from discontinued operations, net of taxes																	(6	)

Net loss																$	(245	)

The following table provides summary segmented operating statistics for the nine months ended September 30, 2007 and 2006, respectively:


	Nine Months Ended
	September 30,
	2007		2006
GEN-MW
Million Megawatt Hours Generated (1)		19.1		16.1
Average Actual On-Peak Market Power Prices ($/MWh) (2):
Cinergy (Cin Hub)	$	62	$	53
Commonwealth Edison (NI Hub)	$	59	$	54
PJM West	$	72	$	65

GEN-WE
Million Megawatt Hours Generated (1) (3)		8.0		0.9
Average Actual On-Peak Market Power Prices ($/MWh) (2):
North Path 15 (NP 15)	$	66	$	61
Palo Verde	$	63	$	59
Average Market Spark Spreads ($/MWh):
North Path 15 (NP15)	$	16	$	14
Palo Verde	$	15	$	13

GEN-NE
Million Megawatt Hours Generated		7.0		3.5
Average Actual On-Peak Market Power Prices ($/MWh) (2):
New York—Zone G	$	83	$	78
New York—Zone A	$	62	$	60
Mass Hub	$	76	$	71
Average Actual On-Peak Market Spark Spread ($/MWh):
New York—Zone A	$	11	$	11
Mass Hub	$	20	$	19

Average natural gas price—Henry Hub ($/MMBtu) (4)	$	6.95	$	6.79


(1)		Includes our ownership percentage in the MWh generated by our GEN-WE investment in NCA#2 for the nine months ended September 30, 2007 and includes the MWh generated by our GEN-WE investments in West Coast Power and NCA#2 and our GEN-MW investment in Rocky Road for the nine months ended September 30, 2006.

(2)		Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the Company.

(3)		Excludes approximately 1.8 MWh and 2.2 MWh generated by our CoGen Lyondell facility, which we sold in August 2007, and less than 0.1 MWh and less than 0.1 MWh generated by our Calcasieu facility, which is classified as held for sale, for the nine months ended September 30, 2007 and 2006, respectively.

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

The following tables summarize significant items on a pre-tax basis affecting net income (loss) for the periods presented:


	Nine Months Ended September 30, 2007
	Power Generation
	GEN-MW			GEN-WE		GEN-NE		CRM			Other			Total
	(in millions)
Discontinued operations (1)	$	—		$	213	$	—	$	15		$	—		$	228
Legal and settlement charges		—			—		—		(16	)		(2	)		(18	)
Illinois rate relief charge		(25	)		—		—		—			—			(25	)
Change in fair value of interest rate swaps, net of minority interest		(9	)		—		—		—			39			30
Gain on sale of Sandy Creek ownership interest		—			12		—		—			—			12
Settlement of Kendall toll		—			—		—		31			—			31

Total DHI		(34	)		225		—		30			37			258
Legal and settlement charges		—			—		—		—			(19	)		(19	)

Total Dynegy	$	(34	)	$	225	$	—	$	30		$	18		$	239


(1)		Discontinued operations for GEN-WE includes a $210 million pre-tax gain on the sale of the CoGen Lyondell power generation facility.


	Nine Months Ended September 30, 2006
	Power Generation
	GEN-MW			GEN-WE			GEN-NE			CRM			Other			Total
	(in millions)
Debt conversion costs	$	—		$	—		$	—		$	—		$	(204	)	$	(204	)
Asset impairments		(96	)		(9	)		—			—			—			(105	)
Legal and settlement charges		—			—			—			(53	)		—			(53	)
Sithe subordinated debt exchange charge		—			—			(36	)		—			—			(36	)
Acceleration of financing costs		—			—			—			—			(34	)		(34	)

Total DHI		(96	)		(9	)		(36	)		(53	)		(238	)		(432	)
Debt conversion costs		—			—			—			—			(45	)		(45	)
Legal and settlement charges		—			—			—			—			(2	)		(2	)

Total Dynegy	$	(96	)	$	(9	)	$	(36	)	$	(53	)	$	(285	)	$	(479	)

Operating Income

Operating income for Dynegy was $510 million for the nine months ended September 30, 2007, compared to $92 million for the nine months ended September 30, 2006. Operating income for DHI was $529 million for the nine months ended September 30, 2007, compared to $94 million for the nine months ended September 30, 2006.

Power Generation—Midwest Segment. Operating income for GEN-MW was $399 million for the nine months ended September 30, 2007, compared to $159 million for the nine months ended September 30, 2006. Operating income for 2006 included a $96 million pre-tax impairment charge related to the Bluegrass generation facility, due to changes in the market that resulted in economic constraints on the facility.

Results for the nine months ended September 30, 2007 improved by $161 million from the nine months ended September 30, 2006 as a result of higher volumes, increased market prices, improved pricing as a result of the Illinois reverse power procurement auction, the addition of the new Midwest plants acquired through the Merger and higher mark-to-market gains. These items were partially offset by a $25 million charge related to the Illinois rate relief package.

Generated volumes increased by 19%, up from 16.1 million MWh for the nine months ended September 30, 2006 to 19.1 million MWh for the same period in 2007. Average actual on-peak prices in Cin Hub pricing region increased from $53 per MWh for the nine months ended September 30, 2006 to $62 per MWh for the nine months ended September 30, 2007.

The Kendall and Ontelaunee plants acquired on April 2, 2007 provided results of $44 million for the nine months ended September 30, 2007, exclusive of mark-to-market results discussed below.

GEN-MW’s results for the nine months ended September 30, 2007 included unrealized mark-to-market gains of $6 million related to forward sales, compared to $10 million of unrealized mark-to-market gains for the nine months ended September 30, 2006. Of the $6 million in 2007 mark-to-market gains, no losses related to positions which will settle in 2007, and the remaining $6 million of gains related to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

In July 2007, we entered into agreements with various parties to make payments of up to $25 million to support a comprehensive rate relief package for Illinois for electric consumers. During September 2007, the governor of Illinois approved the legislation and we made an initial payment of $7.5 million. We recorded a second quarter 2007 pre-tax charge of $25 million, included as a cost of sales on our unaudited condensed consolidated statements of operations. Please see Note 11—Commitments and Contingencies—Illinois Auction Complaints for further discussion.

Depreciation expense increased from $126 million for the nine months ended September 30, 2006 to $143 million for the nine months ended September 30, 2007 primarily as a result of the new Midwest plants and capital projects placed into service in 2006.

Power Generation—West Segment. Operating income for GEN-WE was $105 million for the nine months ended September 30, 2007, compared to a loss of $2 million for the nine months ended September 30, 2006. The 2006 results relate to our Heard County and Rockingham generation facilities. Results from our CoGen Lyondell and Calcasieu power generation facilities have been classified as discontinued operations for all periods presented.

Results for the nine months ended September 30, 2007 improved by $141 million from the nine months ended September 30, 2006 as a result of the addition of the new West plants acquired through the Merger offset by mark-to-market losses described below.

Generated volumes were 8.0 million MWh for the nine months ended September 30, 2007, up from 0.9 million MWh for the nine months ended September 30, 2006. The volume increase was primarily driven by the new West plants, which provided total results of $115 million for the nine months ended September 30, 2007, exclusive of mark-to-market results discussed below. The volume increase from the new West plants was partially offset by a reduction due to the sale of the Rockingham generation facility in late 2006.

GEN-WE’s results for the nine months ended September 30, 2007 included unrealized mark-to-market gains of $35 million related to heat rate call-options and forward sales agreements, compared to zero for the nine months ended September 30, 2006. Of the $35 million in 2007 mark-to-market gains, $25 million related to positions which will settle in 2007, and the remaining $10 million related to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $6 million for the nine months ended September 30, 2006 to $49 million for the nine months ended September 30, 2007 primarily as a result of the new West plants. In addition, during the second quarter 2006, we recorded a $9 million impairment of our Rockingham facility, resulting from the announcement of our sale of the facility.

Power Generation—Northeast Segment. Operating income for GEN-NE was $148 million for the nine months ended September 30, 2007, compared to $59 million for the nine months ended September 30, 2006.

Results for the nine months ended September 30, 2007 improved by $101 million from the nine months ended September 30, 2006 as a result of increased market prices and spark spreads, the addition of the new Northeast plants acquired through the Merger and higher mark-to-market gains. Additionally, a fuel oil inventory write-down of approximately $6 million was recorded in the nine months ended September 30, 2006.

On peak market prices in New York Zone G and Zone A increased by 7% and 4%, respectively. Spark spreads widened due to higher power prices. Average market spark spreads increased 2% and 10% for New York Zone A and Mass Hub, respectively.

Generated volumes increased by 100%, up from 3.5 million MWh for the nine months ended September 30, 2006 to 7.0 million MWh for the same period in 2007. The volume increase was partially driven by the new Northeast plants. The Bridgeport and Casco Bay plants provided total results of $40 million for the nine months ended September 30, 2007, exclusive of mark-to-market results discussed below. The volume increase was also a result of higher spark spreads and cooler weather in the first quarter 2007, which led to greater run times than in 2006.

Results were favorably impacted by $11 million due to an opportunistic sale of emissions credits that were not required for near-term operations of our facilities in the nine months ended September 30, 2006. Similar sales of $7 million occurred in the nine months ended September 30, 2007.

GEN-NE’s results for the nine months ended September 30, 2007 included unrealized mark-to-market gains of $13 million related to forward sales, compared to unrealized losses of $20 million for the nine months ended September 30, 2006. Of the $13 million in 2007 mark-to-market gains, $10 million related to positions which will settle in 2007, and the remaining $3 million related to positions that will settle in 2008 and beyond. See Note 5—Risk Management Activities—Cash Flow Hedges for a discussion of our decision to no longer designate derivative transactions as cash flow hedges beginning with the second quarter 2007.

Depreciation expense increased from $18 million for the nine months ended September 30, 2006 to $30 million for the nine months ended September 30, 2007. This was primarily due to the new Northeast plants.

CRM. Operating income for the CRM segment was $17 million for the nine months ended September 30, 2007, compared to an operating loss of $3 million for the nine months ended September 30, 2006. Results for 2007 include a $31 million gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the Merger, Kendall held a power tolling contract with our CRM segment. Upon completion of the Merger, this contract became an intercompany agreement, and was effectively eliminated on a consolidated basis, resulting in the $31 million gain. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

Results for 2007 and 2006 reflect legal charges of approximately $16 million and $53 million, respectively, resulting from additional activities during the period that negatively affected management’s assessment of probable and estimable losses associated with the applicable proceedings. The 2007 legal charges were partially offset by a $4 million gain on the sale of NYMEX securities. The 2006 legal charges were partially offset by mark-to-market income on our legacy coal, natural gas, emissions, and power positions.

Other. Dynegy’s other operating loss for the nine months ended September 30, 2007 was $159 million, compared to an operating loss of $121 million for the three months ended September 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses increased to $163 for the nine months ended September 30, 2007 from $160 million for the nine months ended September 30, 2006. General and administrative expenses for the nine months ended September 30, 2007 included legal and settlement charges of $37 million, compared with legal and settlement charges of $55 million in the same period of 2006. Additionally, general and administrative expenses for 2007 included a charge of approximately $6 million in connection with the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger Agreement. The remaining increase from 2006 to 2007 was primarily a result of higher salary and employee benefit costs due to the Merger.

DHI’s other operating loss for the nine months ended September 30, 2007 was $140 million, compared to an operating loss of $119 million for the nine months ended September 30, 2006. Operating losses in both periods were comprised primarily of general and administrative expense.

DHI’s consolidated general and administrative expenses decreased to $144 for the nine months ended September 30, 2007 from $158 million for the nine months ended September 30, 2006. General and administrative expenses for the nine months ended September 30, 2007 included legal and settlement charges of $18 million, compared with legal and settlement charges of $53 million in the same period of 2006. The decrease in legal and settlement charges from 2006 to 2007 was partially offset by a charge of approximately $6 million in 2007 related to the accelerated vesting of restricted stock and stock option awards previously granted to employees, which vested in full upon closing of the Merger Agreement. Additionally, salary and employee benefit costs were higher in 2007 as a result of the Merger.

Earnings from Unconsolidated Investments

Dynegy’s earnings from unconsolidated investments were $6 million for both the nine months ended September 30, 2007 and the nine months ended September 30, 2006. Earnings in 2007 included $12 million from the GEN-WE investment in Sandy Creek largely due to its share of the gain on SECA’s sale of a 25% undivided interest in the Project. Please see Note 7—Variable Interest Entities—Sandy Creek for further information. This income was partially offset by losses related to Dynegy’s interest in DLS Power Holdings. Earnings in 2006 related to the GEN-WE investment in NCA#2.

DHI’s earnings from unconsolidated investments were $12 million for the nine months ended September 30, 2007, compared with earnings of $6 million the nine months ended September 30, 2006. Earnings in 2007 included $12 million from the GEN-WE investment in Sandy Creek largely due to its share of the gain on SCEA’s sale of a 25% undivided interest in the Project. Please see Note 7—Variable Interest Entities—Sandy Creek for further information. Earnings in 2006 related to the GEN-WE investment in NCA#2.

Other Items, Net

Dynegy’s other items, net totaled $26 million of income for the nine months ended September 30, 2007, compared to $41 million of income for the nine months ended September 30, 2006. The decrease was primarily associated with $8 million of minority interest expense recorded related to the Plum Point development project as well as foreign currency losses in the nine months ended September 30, 2007. The minority interest expense was primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion.

DHI’s other items, net totaled $25 million of income for the nine months ended September 30, 2007, compared to $36 million of income for the nine months ended September 30, 2006. The decrease was primarily associated with $8 million of minority interest expense recorded in 2007 related to the Plum Point development project. The minority interest expense was primarily due to the mark-to-market interest income recorded during the three months ended June 30, 2007 related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion.

Interest Expense

Dynegy’s interest expense and debt conversion costs totaled $268 million for the nine months ended September 30, 2007, compared to $559 million for the nine months ended September 30, 2006. The decrease was primarily attributable to debt conversion costs and acceleration of financing costs resulting from our liability management program executed in the second quarter of 2006 as well as a $36 million charge associated with the Sithe subordinated debt exchange. Included in interest expense for the nine months ended September 30, 2007 was approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Credit Agreement Facility. Effective July 1, 2007, these agreements were designated as cash flow hedges.

Also included in interest expense for the nine months ended September 30, 2007 was approximately $12 million of income from interest rate swap agreements that, prior to being terminated, were associated with the portion of the debt repaid in late May 2007. The mark-to-market income included in interest expense for 2007 was offset by net losses of approximately $7 million in connection with the repayment of a portion of the project indebtedness assumed in connection with the Merger. These items were offset by higher interest expense incurred in 2007 due to higher 2007 debt balances resulting from the Merger Agreement.

DHI’s interest expense and debt conversion costs totaled $268 million for the nine months ended September 30, 2007, compared to $507 million for the nine months ended September 30, 2006. The decrease was primarily attributable to debt conversion costs and acceleration of financing costs resulting from our liability management program executed in the second quarter of 2006 as well as a $36 million charge associated with the Sithe subordinated debt exchange. Included in interest expense for the nine months ended September 30, 2007 was approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Credit Agreement Facility. Effective July 1, 2007, these agreements were designated as cash flow hedges. Also included in interest expense for the nine months ended September 30, 2007 was approximately $12 million of income from interest rate swap agreements, prior to being terminated, that were associated with the portion of the debt repaid in late May 2007. The mark-to-market income included in interest expense for 2007 was offset by net losses of approximately $7 million in connection with the repayment of a portion of the project indebtedness assumed in connection with the Merger. These items were offset by higher interest expense incurred in 2007 due to higher 2007 debt balances resulting from the Merger Agreement.

Income Tax (Expense) Benefit

Dynegy reported an income tax expense from continuing operations of $95 million for the nine months ended September 30, 2007, compared to an income tax benefit from continuing operations of $150 million for the nine months ended September 30, 2006. The 2007 effective tax rate was 35%, compared to 36% in 2006.

DHI reported an income tax expense from continuing operations of $94 million for the nine months ended September 30, 2007, compared to an income tax benefit from continuing operations of $132 million for the nine months ended September 30, 2006. The 2007 effective tax rate was 32%, compared to 36% in 2006.

In general, differences between these effective rates and the statutory rate of 35% resulted primarily from the effect of state income taxes and adjustments to our reserve for uncertain tax positions. As a result of the Merger Agreement, our effective state tax rate increased primarily as a result of the higher state tax rates in the states in which the LS assets are located. This increase was more than offset by the impact of decreases in the New York state income tax rate and the Texas margin tax credit rate during the nine months ended September 30, 2007.

Discontinued Operations

During the nine months ended September 30, 2007, Dynegy’s pre-tax income from discontinued operations was $228 million ($131 million after-tax). Dynegy’s GEN-WE segment included $3 from the operation of the CoGen Lyondell and Calcasieu power generation facilities in addition to a pre-tax gain of $210 million associated with the completion of our sale of the CoGen Lyondell power generation facility. Dynegy’s U.K. CRM business included income of $15 million, primarily related to a favorable settlement of a legacy receivable.

During the nine months ended September 30, 2006, Dynegy’s pre-tax loss from discontinued operations was $5 million ($6 million after-tax). Dynegy’s GEN-WE segment included losses of $13 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. Dynegy’s U.K. CRM segment included earnings of $5 million for the nine months ended September 30, 2006, associated with the settlement of an outstanding contract. Dynegy also recorded pre-tax income of $3 million attributable to NGL.

During the nine months ended September 30, 2007, DHI’s pre-tax income from discontinued operations was $228 million ($130 million after-tax). DHI’s GEN-WE segment included $3 from the operation of the CoGen Lyondell and Calcasieu power generation facilities in addition to a pre-tax gain of $210 million associated with the completion of our sale of the CoGen Lyondell power generation facility. DHI’s U.K. CRM business included income of $15 million, primarily related to a favorable settlement of a legacy receivable.

During the nine months ended September 30, 2006, DHI’s pre-tax loss from discontinued operations was $5 million ($6 million after-tax). DHI’s GEN-WE segment included losses of $13 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities. DHI’s U.K. CRM segment included earnings of $5 million for the nine months ended September 30, 2006, associated with the settlement of an outstanding contract. DHI also recorded pre-tax income of $3 million attributable to NGL.

Income Tax (Expense) Benefit From Discontinued Operations.

Dynegy recorded an income tax expense from discontinued operations of $97 million during the nine months ended September 30, 2007, compared to an income tax expense from discontinued operations of $1 million during the nine months ended September 30, 2006. The effective rates for the nine months ended September 30, 2007 and 2006 are 43% and 20%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” proscribes a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%. The effective tax rate was also impacted by the $62 million of goodwill allocated to the CoGen Lyondell power generation facility upon its sale. As there was no tax basis in the goodwill, there were no tax benefits associated with the allocated goodwill.

DHI recorded an income tax expense from discontinued operations of $98 million during the nine months ended September 30, 2007, compared to an income tax expense from discontinued operations of $1 million during the nine months ended September 30, 2006. The effective rates for the nine months ended September 30, 2007 and 2006 are 43% and 20%, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” proscribes a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35%. The effective tax rate was also impacted by the $62 million of goodwill allocated to the CoGen Lyondell power generation facility upon its sale. As there was no tax basis in the goodwill, there were no tax benefits associated with the release allocated goodwill.

Outlook

Our recently completed Merger Agreement with the LS Contributing Entities represents the transition from our previous era of self-restructuring and operations of our legacy fleet to a period of expanded, more diverse operations that provides greater scale and scope in our key markets and stronger positioning for future growth opportunities.

Generally, we expect that our future financial results will continue to reflect sensitivity to fuel and emissions commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and IMA. Our commercial team actively manages commodity price risk associated with our unsold power production by trading in the forward markets at physical hubs that are correlated with our assets. We also participate in various regional auctions and bilateral opportunities.

Compared to the legacy Dynegy assets, a higher percentage of our forecasted generation output from the assets acquired through the Merger Agreement is contracted through physical and financial agreements extending beyond the prompt year. Including volumes committed under contracts acquired with these assets, contracts resulting from the Illinois resource procurement auction and power and steam delivery commitments from our Independence facility, a substantial portion of the output from our fleet of power generation facilities is contracted for the next twelve months. This includes RMR arrangements at our South Bay and Oakland facilities. The remaining output from our facilities is available for other forward sales opportunities to capture attractive market prices when they are available. To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil and power commodity markets.

Our results will also continue to be impacted, perhaps materially, by environmental regulations and their impact on our financial condition and results of operations. In addition to the CARB, various state and federal programs on the subject of climate change have been initiated or are being discussed. It is difficult to predict with certainty the precise outcome of these various initiatives and discussions or the resulting impact on our results of operations and financial condition. If some or all of the initiatives are adopted and implemented, we and similarly situated power generators could incur significant additional costs to develop, construct and operate power generation facilities, with the magnitude of any such cost increases to be influenced by, among other things:

	•		the structure and scope of final rules and regulations, including the level of emissions reductions required and the time period for these reductions;

	•		the ability to recover in the marketplace any associated increases in operating and/or capital costs;

	•		the demonstration of new technologies that make further emissions reductions a reality and any associated costs; and

	•		the risk of litigation and related adversary proceedings, particularly with respect to development projects and associated permitting activities.

On August 21, 2007, we entered into amended and restated Contractual Service Agreements (“CSAs”) with General Electric, which became effective October 1, 2007, for the Casco Bay, Arlington Valley, Griffith and Moss Landing facilities. These CSAs replace the LTSA contracts for which we issued termination notices on April 2, 2007 and successfully resolved issues between the parties regarding the LTSAs.

The following summarizes our outlook for our power generation business by reportable segment.

GEN-MW. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and IMA.

For the remainder of 2007, GEN-MW results will continue to be affected by the delivery obligations resulting from our participation in the Illinois resource procurement auction. The power commodity price under the auction-related agreements is higher than existed under our previous contract. The price we will receive under the auction contract in 2007 is approximately $65/MWh. Under the auction contract, we assume increased costs and penalty risks associated with managing delivered power volumes. The price we received under the previous contract averaged approximately $42/MWh in 2006, and was a function of the amount of power called on by IP under the previous contract. We anticipate that the revenues generated by our Midwest facilities will continue to benefit in 2007 from the implementation of contracts resulting from the auction and the sale of additional volumes into the MISO wholesale markets at prevailing market prices.

Another factor impacting our results in the Midwest will be the regulatory environment in Illinois. Recent legislation has provided more certainty with respect to the Illinois regulatory environment, at least for the near term. Please read “Recent Developments” and Note 11—Commitments and Contingencies—Illinois Auction Complaints for further discussion. Furthermore, in October 2007, Commonwealth Edison and the Ameren Illinois Utilities filed their procurement plans for the period from June 2008 to May 2009. We are reviewing those filings and have intervened in the ICC cases. Final decisions are expected by the end of this year. We anticipate the actual procurement events will be held early next year.

In 2005, DMG entered into a comprehensive, Midwest system-wide settlement with the EPA and other parties, resolving the environmental litigation related to our Baldwin Energy Complex in Illinois. The settlement will require substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. Through September 30, 2007, DMG had achieved all emission reductions scheduled to date under the Consent Decree and was developing plans to install additional emission control equipment to meet future Consent Decree emission limits. DMG has constructed a mercury control project at the Vermilion Power Station that began operation in June 2007. Our estimated costs associated with the Consent Decree projects, which we expect to incur through 2012, are approximately $775 million. We expect to have spent $115 million of this amount by December 31, 2007. Expected spending associated with the Consent Decree for the next four years and thereafter are as follows: 2008—$150 million, 2009-$195 million, 2010—$175 million, 2011—$100 million and thereafter—$40 million.

Through 2010, 96% of our Midwest coal requirements are contracted. For 2007 and 2008, the prices associated with these contracts are fixed. Our longer term results are sensitive to changes in coal prices to the extent that our current fixed prices are adjusted through contract re-openers or related provisions. The new prices resulting from the re-openers will become effective January 1, 2009.

Our results will continue to be affected by IMA. We use IMA to monitor fleet performance over time. This measure quantifies the percentage of generation for each of our 14 major steam units that were available when market prices were favorable for participation. Through our focus on safe and efficient operations, we seek to maximize our IMA and, as a result, our revenue generating opportunities. The IMA for our coal-fired fleet for the nine months ended September 30, 2007 was approximately 93%, compared to 89% for the comparable period of 2006. (In 2007, we modified the way we calculate IMA to better reflect the capabilities of the units due to seasonal variations. IMA for 2006 has been recalculated on a basis comparable to 2007.) We attempt to schedule maintenance and repair work to minimize downtime during peak demand periods, to the extent doing so does not compromise a safe working environment for our employees and contractors.

In connection with the Merger discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, we acquired assets in Illinois and Pennsylvania. These assets include the 1,200 MW Kendall natural gas-fired facility in Minooka, IL and the 580 MW Ontelaunee natural gas-fired facility in Ontelaunee Township, PA. With respect to the Kendall facility, 275 MW of the facility’s capacity is committed to a subsidiary of Constellation Energy (“Constellation”) under a power purchase agreement that extends through 2017. An additional 550 MW of capacity is committed under another agreement with Constellation, which extends through November 2008. These power purchase agreements provide us with predictable contracted revenues, and mitigate the effects of fluctuating market prices for electricity.

The Ontelaunee facility sells its energy, capacity and other ancillary services to wholesale electricity customers directly on the spot market. However, exposure to the market prices of energy has been hedged under a financially settled heat rate call-option agreement.

PJM recently implemented a forward capacity auction, the Reliability Pricing Model. The auction has resulted in a dramatic increase in the value of capacity in not only PJM, but in the neighboring MISO as well. The increase in prices indicates a projected tightening of the supply/demand balance in the near future. More immediately, we benefited from selling approximately 1,300 net MWs into the 2008-2009 planning year auction and 2,650 net MWs into the 2009-2010 auction, both of which were held earlier in 2007.

Our 576 MW Bluegrass generation facility is being considered for a potential sale. Please read “Asset Sale Proceeds” for further discussion.

Plum Point is currently in the construction phase, with an expected completion date of August 2010. Upon completion it will be a 665 MW coal-fired power generating facility located in Osceola, Arkansas. The City of Osceola has loaned $100 million in proceeds of a tax exempt bond issuance to Plum Point. We are considering the possibility of refinancing the outstanding Tax Exempt Bonds, however any decision to proceed will be conditioned on seeking necessary public approvals and favorable market conditions. Please read Note 8—Debt—Plum Point Tax Exempt Bonds for further discussion.

GEN-WE. In connection with the Merger discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, we acquired a portfolio of assets in California and Arizona. These assets include six facilities located in California (Moss Landing, Morro Bay, South Bay and Oakland) and Arizona (Arlington Valley and Griffith), with a total capacity of 5,545 MW. Moss Landing, Morro Bay, and Griffith are subject to certain power purchase agreements under which the buyer pays the power generation facility a fixed monthly payment for the right to call energy, capacity and ancillary services from the power generation facility. The South Bay and Oakland facilities operate under RMR agreements with the CAISO.

Moss Landing, Arlington Valley and Griffith sell energy, capacity and/or other ancillary services to wholesale electricity customers directly in the spot market. Several financially-settled heat rate call-options are in effect that mitigate the exposure of these facilities to changes in the market price of energy.

Our GEN-WE segment will no longer benefit from the earnings from the CoGen Lyondell facility due to the completion of the sale of this facility on August 1, 2007. For the nine months ended September 30, 2007, we recorded operating income of $5 million related to the operation of CoGen Lyondell. This amount has been reclassified as income from discontinued operations. Additionally, our 539 MW Heard County generation facility is being considered for a potential sale. Please read “Asset Sale Proceeds” for further discussion.

In August 2007, our GEN-WE segment acquired a 50% interest in SCEA, which owns a 75% undivided interest in the Sandy Creek Energy Station, a proposed 898 MW facility to be located in McLennan County, Texas. Please see Note 7—Variable Interest Entities—Sandy Creek for further discussion. Site work has begun on this project, and we anticipate that construction will begin in the fourth quarter 2007. We intend to pursue opportunities to enter into long-term contacts for the generation from the facility, which we anticipate will begin commercial operations in 2012.

GEN-NE. We expect our results to continue to be impacted by power prices, fuel prices, fuel availability and IMA. Spreads between the price for power and fuel costs are expected to remain volatile as both fuel and power prices change based on demand and weather. This volatility has significant impact on the run-time for the Roseton unit. All of our coal supply requirements for 2007 are contracted at a fixed price. We continue to maintain sufficient coal and oil inventories and contractual commitments intended to provide us with a stable fuel supply.

Additionally, our results could be affected by potential changes in New York, Maine and/or Connecticut state environmental regulations, as well as our ability to obtain permits necessary for the operation of our facilities. Please see Note 11—Commitments and Contingencies—Danskammer State Pollutant Discharge Elimination System Permit and —Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit, respectively, for further discussion.

In connection with the Merger discussed in Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions, we acquired assets in Connecticut and Maine. These assets include the 527 MW Bridgeport natural gas-fired facility in Bridgeport, CT and the 540 MW Casco Bay natural gas-fired facility in Veazie, ME.

The Bridgeport facility had been operating pursuant to the terms of the Bridgeport RMR agreement, subject to the outcome of ongoing proceedings before the FERC to resolve the question of whether Bridgeport is eligible for an RMR agreement. On May 25, 2007, Bridgeport and the intervening parties submitted a Joint Offer of Settlement, which effectively terminated the RMR Agreement as of May 31, 2007. Under the Settlement, Bridgeport will no longer be required to submit stipulated bids as of June 1, 2007 therein allowing Bridgeport to more fully participate as a merchant generator in the ISO-NE market.

In October 2007, we terminated a heat-rate call option related to our Casco Bay facility. This option would have expired on December 31, 2010. As a result of the cancellation, we received a termination payment of $32 million, and a letter of credit for $35 million supporting the transaction was returned to us.

DLS Power Development. Through Dynegy’s interest in DLS Power Development, Dynegy and LS Associates continue to move forward with the Long Leaf Project, which comprises development of a 600 MW scrubbed pulverized coal generating facility located in Georgia. During the second quarter 2007, this project received all necessary permits, although certain challengers are contesting the validity of these permits. Management believes the validity of the permits will be upheld, and could seek construction financing and power purchase agreements for future generation from the facility by first or second quarter of 2008.

The DLS Power Development portfolio is anticipated to be dynamic in nature, with changes in projects and priorities likely to occur based on the joint venture parties views of market prices, supply/demand balances, contract availability and the terms thereof, environmental implications and other factors that they deem relevant. Other projects in active development include renewable energy projects and natural gas-fired projects in the West.

Cash Flow Disclosures

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


	Dynegy Inc.						Dynegy Holdings Inc.
	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(in millions)
Operating cash flows from our generation businesses	$	736		$	503		$	736		$	503
Operating cash flows from our customer risk management business		(24	)		(370	)		(24	)		(370	)
Other operating cash flows		(346	)		(313	)		(337	)		(325	)

Net cash provided by (used) in operating activities	$	366		$	(180	)	$	375		$	(192	)

Operating Cash Flow

Dynegy. Dynegy’s cash flow provided by operations totaled $366 million for the nine months ended September 30, 2007. During the nine months ended September 30, 2007, our power generation business provided positive cash flow from operations of $736 million primarily due to positive earnings for the period. Our customer risk management business used approximately $24 million in cash, largely as a result of cash payments associated with our legacy trading business. These payments were partially offset by the receipt of approximately $32 million from the sale of a legacy receivable. Other and Eliminations includes a use of approximately $346 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income.

Dynegy’s cash flow used in operations totaled $180 million for the nine months ended September 30, 2006. GEN provided cash flow from operations of $503 million, primarily due to positive earnings for the period. Our CRM segment used cash flow of approximately $370 million primarily due to a $370 million termination payment on our Sterlington tolling contract. Other and Eliminations includes a use of approximately $313 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances and the receipt of approximately $20 million associated with the resolution of a legal dispute.

DHI. DHI’s cash flow provided by operations totaled $375 million for the nine months ended September 30, 2007. During the nine months ended September 30, 2007, our power generation business provided positive cash flow from operations of $736 million primarily due to positive earnings for the period. Our customer risk management business used approximately $24 million in cash largely as a result of cash payments associated with our legacy trading business. These payments were partially offset by the receipt of approximately $32 million from the sale of a legacy receivable. Other and Eliminations includes a use of approximately $337 million in cash primarily due to interest payments to service debt and general and administrative expense, partially offset by interest income.

DHI’s cash flow used in operations totaled $192 million for the nine months ended September 30, 2006. GEN provided cash flow from operations of $503 million, primarily due to positive earnings for the period. Our CRM segment used cash flow of approximately $370 million primarily due to a $370 million termination payment on our Sterlington tolling contract. Other and Eliminations includes a use of approximately $325 million in cash primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income on cash balances.

Capital Expenditures and Investing Activities

Dynegy. Dynegy’s cash used in investing activities during the nine months ended September 30, 2007 totaled $503 million. Capital spending of $236 million was primarily comprised of $187 million, $14 million, and $24 million for our GEN-MW, GEN-WE, and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $92 million associated with the construction of the Plum Point facility, which is provided by non-recourse project financing. The remaining capital spending for the GEN-MW and GEN-WE segments primarily related to maintenance and environmental projects, while spending in the GEN-NE segment primarily related to maintenance. In addition, there was approximately $11 million of capital expenditures in Other.

Net proceeds from the sale of assets totaled $466 million, which included $462 million from the sale of the CoGen Lyondell power generation facility.

Cash used in connection with the completion of the Merger Agreement, net of cash acquired, was $128 million. Please see Note 2—LS Power Business Combination and Dynegy Illinois Entity Contributions for further discussion.

The increase in restricted cash of $598 million related primarily to a $650 million deposit associated with our cash collateralized facility, partially offset by the release of Independence restricted cash due to the posting of a letter of credit.

Dynegy’s cash provided by investing activities during the nine months ended September 30, 2006 totaled $213 million. Capital spending of $92 million was primarily comprised of $58 million, $16 million, and $12 million in the GEN-MW, GEN-WE, and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $6 million of capital expenditures in Other.

Proceeds from assets sales, net totaled $18 million and primarily consisted of proceeds from the sale of a gas turbine not in use.

Net proceeds from the sale and acquisition of unconsolidated investments, net of cash acquired totaled $165 million. This included net cash proceeds of $205 million from the sale of our 50% ownership interest in West Coast Power to NRG. This was partially offset by a payment of $45 million for our acquisition of NRG’s 50% ownership interest in Rocky Road, which included $5 million of cash on hand.

The decrease in restricted cash of $125 million related primarily to the return of our $335 million deposit associated with our former cash collateralized facility, offset by a $200 million deposit associated with our cash collateralized facility and a $10 million increase in the Independence restricted cash balance.

DHI. DHI’s cash used in investing activities during the nine months ended September 30, 2007 totaled $363 million. Capital spending of $236 million was primarily comprised of $187 million, $14 million, and $24 million for our GEN-MW, GEN-WE, and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $92 million associated with the construction of the Plum Point facility. The remaining capital spending for the GEN-MW and GEN-WE segments primarily related to maintenance and environmental projects, while spending in the GEN-NE segment primarily related to maintenance. In addition, there was approximately $11 million of capital expenditures in Other.

Net proceeds from the sale of assets totaled $466 million, which included $462 million from the sale of the CoGen Lyondell power generation facility.

DHI’s cash provided by investing activities during the nine months ended September 30, 2006 totaled $212 million. Capital spending of $92 million was primarily comprised of $58 million, $16 million, and $12 million in the GEN-MW, GEN-WE, and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $6 million of capital expenditures in Other.

Proceeds from assets sales, net totaled $15 million and primarily consisted of proceeds from the sale of a gas turbine not in use.

Financing Activities

Dynegy. Dynegy’s cash provided by financing activities during the nine months ended September 30, 2007 totaled $404 million. During the nine months ended September 30, 2007, Dynegy received proceeds from long-term borrowings from the following sources, net of approximately $33 million of debt issuance costs:

	•		$1,650 million in aggregate principal amount from our Senior Unsecured Notes due 2015 and 2019;

	•		$665 million in aggregate principal amount on our letter of credit facilities;

	•		$275 million in aggregate principal amount on our revolver due 2012;

	•		$70 million senior secured term loan facility due 2013; and

	•		$78 million in aggregate principal amount on our Plum Point Credit Agreement Facility.

These borrowings were partially offset by $2,300 million of payments:

	•		$396 million in aggregate principal amount on our Kendall Senior Secured Term Loan Facility;

	•		$150 million in aggregate principal amount on our Ontelaunee term loan due 2009;

	•		$919 million in aggregate principal amount on our Gen Finance First Lien Term Loan;

	•		$150 million in aggregate principal amount on our Gen Finance Second Lien Term Loan;

	•		$275 million promissory note to LS Associates;

	•		$275 million in aggregate principal amount on our Revolving Facility;

	•		$70 million in aggregate principal amount on our Griffith debt;

	•		$39 million in aggregate principal amount on our 8.50% secured bonds due 2007;

	•		$15 million in aggregate principal amount on our letter of credit facilities; and

	•		$11 million in aggregate principal amount on our Second Priority Senior Secured Notes.

Dynegy’s cash used in financing activities during the nine months ended September 30, 2006 totaled $1,194 million. Repayments of long-term debt totaled $1,780 million for the nine months ended September 30, 2006 and consisted of the following payments:

	•		$900 million in aggregate principal amount on our 10.125% Second Priority Senior Secured Notes due 2013;

	•		$614 million in aggregate principal amount on our 9.875% Second Priority Senior Secured Notes due 2010;

	•		$225 million in aggregate principal amount on our Second Priority Senior Secured Floating Rate Notes due 2008;

	•		$23 million in aggregate principal amount on our 7.45% Senior Notes due 2006; and

	•		$18 million in aggregate principal amount on our 8.50% secured bonds due 2007.

In addition to the above repayments during the nine months ended September 30, 2006, we redeemed all of the outstanding shares of our Series C Preferred for $400 million.

Debt conversion costs of $249 million consisted of the following payments:

	•		$204 million to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs;

	•		$44 million aggregate premium to induce conversion of our $225 million 4.75% Convertible Subordinated Debentures due 2023; and

	•		$1 million in transaction costs associated with the redemption of our Series C Preferred.

The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:

	•		$750 million aggregate principal amount from a private offering of our 8.375% Senior Unsecured Notes due 2016;

	•		$200 million, LIBOR + 1.75% letter of credit facility due 2012; and

	•		$150 million, LIBOR + 1.75% term loan due 2012.

Proceeds from the issuance of common stock during the nine months ended September 30, 2006 consisted primarily of approximately $178 million in proceeds from a common stock offering of 40.25 million shares of Dynegy’s Class A common stock at $4.60 per share, net of underwriting fees. Dividend payments totaling $17 million were also made on Dynegy’s Series C Preferred prior to its redemption.

DHI. DHI’s cash provided by financing activities during the nine months ended September 30, 2007 totaled $339 million. During the nine months ended September 30, 2007, DHI received proceeds from long-term borrowings from the following sources, net of approximately $33 million of debt issuance costs:

	•		$1,650 million in aggregate principal amount from our Senior Unsecured Notes due 2015 and 2019;

	•		$665 million in aggregate principal amount on our letter of credit facilities;

	•		$275 million in aggregate principal amount on our revolver due 2012;

	•		$70 million in aggregate principal amount on our senior secured term loan facility due 2013; and

	•		$78 million in aggregate principal amount on our Plum Point Credit Agreement Facility.

These borrowings were partially offset by $2,025 million of payments:

	•		$396 million in aggregate principal amount on our Kendall Senior Secured Term Loan Facility;

	•		$150 million in aggregate principal amount on our Ontelaunee term loan due 2009;

	•		$919 million in aggregate principal amount on our Gen Finance First Lien Term Loan;

	•		$150 million in aggregate principal amount on our Gen Finance Second Lien Term Loan;

	•		$275 million in aggregate principal amount on our Revolving Facility;

	•		$70 million in aggregate principal amount on our Griffith debt;

	•		$39 million in aggregate principal amount on our 8.50% secured bonds due 2007;

	•		$15 million in aggregate principal amount on our letter of credit facilities; and

	•		$11 million in aggregate principal amount on our Second Priority Senior Secured Notes.

Cash used in financing activities for the nine months ended September 30, 2007 also includes dividend payments to Dynegy totaling $342 million.

DHI’s cash used in financing activities during the nine months ended September 30, 2006 totaled $1,083 million. Repayments of long-term debt totaled $1,780 million for the nine months ended September 30, 2006 and consisted of the following payments:

	•		$900 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2013;

	•		$614 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2010;

	•		$225 million in aggregate principal amount on our Second Priority Senior Secured Notes due 2008;

	•		$23 million in aggregate principal amount on our 7.45% Senior Notes due 2006; and

	•		$18 million in aggregate principal amount on our 8.50% secured bonds due 2007.

Debt conversion costs of $203 million consisted of payments to redeem the Second Priority Senior Secured Notes mentioned above, including approximately $3 million of transaction costs.

The repayments were partially offset by $1,071 million of proceeds from the following sources, net of approximately $29 million of debt issuance costs:

	•		$750 million aggregate principal amount from our Senior Unsecured Notes due 2016;

	•		$200 million, LIBOR + 1.75% letter of credit facility due 2012; and

	•		$150 million, LIBOR + 1.75% term loan due 2012.

Cash used in financing activities for the nine months ended September 30, 2006 also includes $170 million in payments to Dynegy, which consists of repayments of borrowings of $120 million and a dividend payment of $50 million.

RISK-MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance sheets:


	As of and for the
	Nine Months
	Ended September
	30, 2007
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2007	$	53
Risk-management gains recognized through the income statement in the period, net		126
Cash received related to risk-management contracts settled in the period, net		(13	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		(149	)

Fair value of portfolio at September 30, 2007	$	17


(1)		Our modeling methodology has been consistently applied.

(2)		This amount consists of $38 million in net risk management liabilities acquired in connection with the Merger Agreement as well as changes in value associated with cash flow hedges on forward power sales and fair value and cash flow hedges on debt.

The net risk management asset of $17 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, 2007 and December 31, 2006. 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			2007 (2)			2008			2009			2010			2011		Thereafter
	(in millions)
September 30, 2007	$	29		$	39		$	(5	)	$	(8	)	$	(2	)	$	1	$	4
December 31, 2006		(44	)		(45	)		(3	)		—			—			1		3

Increase (decrease) (3)	$	73		$	84		$	(2	)	$	(8	)	$	(2	)	$	—	$	1


(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 asset at September 30, 2007 of $17 million on the unaudited condensed consolidated balance sheets include the $29 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2)		Amounts represent October 1 to December 31, 2007 values in the September 30, 2007 row and January 1 to December 31, 2007 values in the December 31, 2006 row.

(3)		Increase since December 31, 2007 primarily due to the settlement of a large portion of risk-management liabilities outstanding at December 31, 2006 during 2007 and mark-to-market gains recognized in 2007, partially offset by $38 million in net risk-management liabilities acquired in connection with the Merger Agreement.

Cash Flow Components of Net Risk-Management Asset


	Nine Months		Three Months
	Ended		Ended
	September 30,		December 31,		Total
	2007		2007		2007			2008			2009			2010			2011		Thereafter
	(in millions)
September 30, 2007 (1)	$	19	$	53	$	72		$	6		$	(14	)	$	(4	)	$	2	$	6
December 31, 2006						(45	)		(4	)		—			—			1		5

Increase (decrease)					$	117		$	10		$	(14	)	$	(4	)	$	1	$	1


(1)		The cash flow values for 2007 reflect realized cash flows for the nine months ended September 30, 2007 and anticipated undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges.

The following table provides an assessment of net contract values by year as of September 30, 2007, based on our valuation methodology:

Net Fair Value of Risk-Management Portfolio


	Total		2007		2008			2009			2010			2011		Thereafter
	(in millions)
Market Quotations (1)	$	25	$	17	$	(1	)	$	3		$	1		$	1	$	4
Prices Based on Models.		4		22		(4	)		(11	)		(3	)		—		—


Total	$	29	$	39	$	(5	)	$	(8	)	$	(2	)	$	1	$	4


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

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements” by both Dynegy and DHI. 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:

	•		anticipated benefits of diversifying our operations, including the merger with the LS Contributing Entities;

	•		beliefs and expectations regarding financing, development and timing of any and all joint venture projects;

	•		projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;

	•		expectations regarding capital expenditures, interest expense and other payments;

	•		beliefs and assumptions about economic conditions and the demand for electricity;

	•		beliefs about commodity pricing and generation volumes;

	•		our focus on safety and our ability to efficiently operate our assets so as to maximize our revenue generating opportunities;

	•		strategies to capture opportunities presented by rising commodity prices and strategies to manage our exposure to energy price volatility;

	•		beliefs and assumptions relating to liquidity;

	•		statements related to the effects of changing to mark-to-market accounting including any related to gains and losses in earnings or value changes related to market price volatility;

	•		strategies to address our substantial leverage, or to access the capital markets;

	•		measures to compete effectively with industry participants;

	•		beliefs and assumptions about market competition, fuel supply, generation capacity and regional supply and demand characteristics of the wholesale power generation market;

	•		sufficiency of coal, fuel oil and natural gas inventories and transportation, including strategies to deploy coal supplies;

	•		beliefs about the outcome of legal, regulatory and administrative matters;

	•		expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations, including those relating to global warming;

	•		the disposition and resolution of settlements, complaints, and suits related to the Illinois Power Auction and impacts that these may have;

	•		expectations and estimates regarding the DMG consent decree and the associated costs; and

	•		efforts to position our power generation business for future growth and pursuing and executing acquisition, disposition or combination opportunities.

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, many of which are beyond our control, including those set forth under Part II-Other Information, Item 1A-Risk Factors.

RECENT ACCOUNTING PRONOUNCEMENTS

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

CRITICAL ACCOUNTING POLICIES

Please read Note 1—Accounting Policies—Goodwill and Other Intangible Assets for further discussion of our policy with respect to goodwill and other intangible assets. Please read “Critical Accounting Policies” beginning on pages 74 and 62, respectively, of Dynegy’s and DHI’s Forms 10-K for a complete description of our critical accounting policies, with respect to which there have been no other material changes since the filing of such Forms 10-K.

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.

Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk beginning on pages 81 and 68, respectively, of Dynegy’s and DHI’s Forms 10-K for a discussion of our exposure to commodity price variability and other market risks related to our net non-trading derivative assets and liabilites, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of September 30, 2007.

Value at Risk (“VaR”). The following table sets forth the aggregate daily VaR of the mark-to-market portion of our risk-management portfolio primarily associated with the GEN segments and the CRM business. The VaR calculation does not include market risks associated with the accrual portion of the risk-management portfolio that is designated as a cash flow hedge or a “normal purchase normal sale”, nor does it include expected future production from our generating assets. Another limitation to our calculation of VaR is our use of the JP Morgan RiskMetrics ^TM approach, which calculates option values using a linear approximation. With the acquisition of several financially-settled heat rate call-option agreements in the LS Power business combination, the actual change in the fair value of these instruments may differ significantly from the calculated VaR.

There is a significant increase in VaR from December 31, 2006 to September 30, 2007 due to the above mentioned financially-settled heat rate call-options and our decision to cease designating certain derivative transactions as cash flow hedges, beginning on April 2, 2007.

Daily and Average VaR for Risk-Management Portfolios


	September 30,		December 31,
	2007		2006
	(in millions)
One Day VaR—95% Confidence Level	$	22	$	1
One Day VaR—99% Confidence Level	$	31	$	1
Average VaR for the Year-to-Date Period—95% Confidence Level	$	17	$	3

Credit Risk. The following table represents our credit exposure at September 30, 2007 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary


	Investment
	Grade Quality
	(in millions)
Type of Business:
Financial Institutions	$	435
Utility and Power Generators		37

Total	$	472

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of September 30, 2007, our fixed rate debt instruments, as a percentage of total debt instruments, were approximately 78%. Adjusted for interest rate swaps, net notional fixed rate debt as a percentage of total debt was approximately 74%. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of September 30, 2007, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended September 30, 2008 would either decrease or increase interest expense by approximately $15 million. Over time, we may seek to reduce or increase the percentage of fixed rate financial obligations in our debt portfolio through the use of swaps or other financial instruments.

Derivative Contracts. The notional financial contract amounts associated with our interest rate contracts were as follows at September 30, 2007 and December 31, 2006, respectively:

Absolute Notional Contract Amounts


	September 30,		December 31,
	2007		2006
Net Cash Flow Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	263	$	—
Fixed Interest Rate Paid (Percent)		5.32		—
Net Fair Value Hedge Interest Rate Swaps (In Millions of U.S. Dollars)	$	525	$	525
Fixed Interest Rate Received on Swaps (Percent)		4.33		4.33
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	231	$	306
Fixed Interest Rate Paid (Percent)		5.35		5.29
Interest Rate Risk-Management Contract (In Millions of U.S. Dollars)	$	206	$	281
Fixed Interest Rate Received (Percent)		5.28		5.23

Item 4—CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.

DHI is not subject to the disclosure requirements promulgated under Section 404 of the Sarbanes-Oxley Act of 2002 with respect to its internal control over financial reporting until DHI files its 2007 Form 10-K. Nevertheless, because DHI comprises a significant part of Dynegy as a consolidated enterprise, DHI’s internal control over financial reporting has been reviewed in connection with Dynegy’s compliance with Section 404 of the Sarbanes-Oxley Act.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of Dynegy’s disclosure committee in an effort to ensure that information required to be disclosed in the consolidated enterprise’s SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the third quarter 2007 relating to Dynegy’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, Dynegy’s and DHI’s CEO and CFO concluded that Dynegy’s and DHI’s disclosure controls and procedures were effective as of September 30, 2007.

Changes in Internal Controls Over Financial Reporting

There were no changes in the consolidated enterprise’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect the consolidated enterprise’s internal control over financial reporting during the third quarter 2007.

DYNEGY INC. and DYNEGY HOLDINGS INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

See Note 11—Commitments and Contingencies to the accompanying unaudited condensed consolidated financial statements for discussion of the legal proceedings that we believe could be material to us.

Item 1A—RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

See Item 1A—Risk Factors on pages F-22 and F-18, respectively, of Dynegy’s and DHI’s Forms 10-K as updated in their respective Forms 10-Q for the quarters ended March 31 and June 30, 2007 for factors, risks and uncertainties that may affect future results.

Item 2—UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS—DYNEGY INC.

Upon vesting of restricted stock awarded by the Company to employees, shares are withheld to cover the employees’ withholding taxes. Information on the Company’s purchases of equity securities during the quarter follows:

(d)

Maximum

(c)

Number of

Total Number of

Shares that

Shares Purchased

May Yet Be

(a)

(b)

as Part of

Purchased

Total Number

Average

Publicly

Under the

of Shares

Price Paid

Announced Plans

Plans or

Period

Purchased

per Share

or Programs

Programs

July

—

N/A

August

2,394

8.91

—

N/A

September

—

N/A

Total

2,394

8.91

—

N/A

These were the only repurchases of equity securities made by us during the three months ended September 30, 2007. Dynegy does not have a stock repurchase program.

Item 4—SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS—DYNEGY INC.

Our 2007 annual meeting of stockholders was held on July 18, 2007. The purpose of the annual meeting was to consider and vote upon the following proposals:

	1.		To elect eight Class A common stock directors and three Class B common stock directors to serve until the 2008 annual meeting of stockholders;

	2.		To act upon a proposal to ratify the appointment of Ernst & Young LLP as our independent auditors commencing with the review of the unaudited financial statements for the second quarter ending June 30, 2007 through the remainder of the fiscal year ending December 31, 2007; and

	3.		To act upon a stockholder proposal regarding pay-for-superior-performance.

Our current Board of Directors is comprised of eleven members. At the annual meeting, each of the following individuals was elected to serve as one of our directors: James T. Bartlett, David W. Biegler, Thomas D. Clark, Jr., Victor J. Grijalva, Patricia A. Hammick, Frank E. Hardenbergh, George L. Mazanec, Robert C. Oelkers, Mikhail Segal, William L. Trubeck and Bruce A. Williamson. The votes cast for each nominee and the votes withheld were as follows:

Class A Directors


		FOR		WITHHELD
1.	David W. Biegler		442,454,325		12,362,799
2.	Thomas D. Clark, Jr.		450,035,665		4,781,459
3.	Victor J. Grijalva		441,378,492		13,438,632
4.	Patricia A. Hammick		450,019,133		4,797,991
5.	George L. Mazanec		433,932,288		20,884,836
6.	Robert C. Oelkers		434,074,048		20,743,076
7.	William L. Trubeck		434,004,791		20,812,333
8.	Bruce A. Williamson		447,354,233		7,462,891

Class B Directors


		FOR		WITHHELD
1.	James T. Bartlett		340,000,000		0
2.	Frank E. Hardenbergh		340,000,000		0
3.	Mikhail Segal		340,000,000		0

The following votes were cast with respect to the proposal to ratify the selection of Ernst & Young LLP as our independent auditors commencing with the review of the unaudited financial statements for the second quarter ending June 30, 2007 through the remainder of the fiscal year ending December 31, 2007, which passed. There were no broker non-votes.


FOR	AGAINST	ABSTAIN
791,900,986	1,801,951	1,114,185

The following votes were cast with respect to the stockholder proposal regarding pay-for-superior-performance, which failed to pass. There were 91,719,360 broker non-votes.


FOR	AGAINST	ABSTAIN
121,029,989	613,373,998	4,692,277

Item 6—EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.

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


Exhibit
Number		Description
10.1		Fourth Amendment to October 18, 2002 Employment Agreement between Bruce A. Williamson and Dynegy Inc. dated August 23, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 24, 2007, File No. 001-33443).

10.2		Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Dynegy Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 5, 2007, File No. 001-33443).

10.3		Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 5, 2007, File No. 001-33443).

**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.

**31.1(a)		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.

**31.2(a)		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.

†32.1(a)		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.

†32.2(a)		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


**		Filed herewith.

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

DYNEGY INC. and DYNEGY HOLDINGS INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: November 8, 2007	By:	/s/ Holli C. Nichols
		Holli C. Nichols
		Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

	DYNEGY HOLDINGS INC.
Date: November 8, 2007	By:	/s/ Holli C. Nichols
		Holli C. Nichols
		Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)

EXHIBIT INDEX


Exhibit
Number		Description
10.1		Fourth Amendment to October 18, 2002 Employment Agreement between Bruce A. Williamson and Dynegy Inc. dated August 23, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 24, 2007, File No. 001-33443).

10.2		Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Dynegy Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 5, 2007, File No. 001-33443).

10.3		Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 5, 2007, File No. 001-33443).

**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.

**31.1(a)		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.

**31.2(a)		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.

†32.1(a)		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.

†32.2(a)		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


**		Filed herewith.

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