Dyne Therapeutics 10-Q 2008 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2008
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)

Entity	Commission File Number	State of Incorporation	I.R.S. Employer 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 x No o
Dynegy Holdings Inc.	Yes x No o

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

	Large accelerated filer	Accelerated filer	Non-accelerated filer (Do not check if a smaller reporting company)	Smaller reporting company
Dynegy Inc.	x	o	o	o
Dynegy Holdings Inc.	o	o	x	o

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 x
Dynegy Holdings Inc.	Yes o No x

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, 502,580,360 shares outstanding as of August 1, 2008; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of August 1, 2008. 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.: June 30, 2008 and December 31, 2007		4
	Condensed Consolidated Statements of Operations—Dynegy Inc.: For the three and six months ended June 30, 2008 and 2007		5
	Condensed Consolidated Statements of Cash Flows—Dynegy Inc.: For the six months ended June 30, 2008 and 2007		6
	Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Inc.: For the three and six months ended June 30, 2008 and 2007		7
	Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.: June 30, 2008 and December 31, 2007		8
	Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.: For the three and six months ended June 30, 2008 and 2007		9
	Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.: For the six months ended June 30, 2008 and 2007		10
	Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Holdings Inc.: For the three and six months ended June 30, 2008 and 2007		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.	41
	Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.	70
	Item 4.	CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.	71
PART II. OTHER INFORMATION
	Item 1.	LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	73
	Item 1A.	RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	73
	Item 2.	UNREGISTERED SALES OF SECURITIES AND USE OF PROCEEDS—DYNEGY INC.	75
	Item 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS—DYNEGY INC.	75
	Item 6.	EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	76

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 percent of Dynegy’s total consolidated revenue for the six month period ended June 30, 2008 and constituting approximately 100 percent of Dynegy’s total consolidated asset base as of June 30, 2008 except for Dynegy’s 50 percent 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.

2

DEFINITIONS

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

APB	Accounting Principles Board
ASM	Ancillary Services Market
BTA	Best technology available
CAIR	Clean Air Interstate Rule
CFTC	Commodity Futures Trading Commission
CO2	Carbon Dioxide
CRM	Our former customer risk management business segment
CUSA	Chevron U.S.A. Inc., a wholly owned subsidiary of Chevron Corporation
DHI	Dynegy Holdings Inc., Dynegy’s primary financing subsidiary
DMG	Dynegy Midwest Generation, Inc.
DMSLP	Dynegy Midstream Services L.P.
EITF	Emerging Issues Task Force
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
GAAP	Generally Accepted Accounting Principles of the United States of America
GEN	Our power generation business
GEN-MW	Our power generation business - Midwest segment
GEN-NE	Our power generation business - Northeast segment
GEN-WE	Our power generation business - West segment
ICC	Illinois Commerce Commission
IMA	In-market asset availability
ISO	Independent System Operator
ISO-NE	Independent System Operator – New England
MISO	Midwest Independent Transmission Operator, Inc.
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt hour
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRG	NRG Energy, Inc.
NYSDEC	New York State Department of Environmental Conservation
OTC	Over the Counter
PJM	PJM Interconnection, LLC
PPEA	PPEA Holding Company LLC
RGGI	Regional Greenhouse Gas Initiative
SCEA	Sandy Creek Energy Associates, LP
SCH	Sandy Creek Holdings LLC
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SO2	Sulfur Dioxide
SPDES	State Pollutant Discharge Elimination System
VaR	Value at Risk
VIE	Variable Interest Entity

3

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)

	June 30, 2008				December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents		$	271			$	328
Restricted cash			123				104
Accounts receivable, net of allowance for doubtful accounts of $18 and $20, respectively			478				426
Accounts receivable, affiliates			1				1
Inventory			172				199
Assets from risk-management activities			3,363				358
Deferred income taxes			1				45
Prepayments and other current assets			342				145
Assets held for sale (Note 3)			304				57
Total Current Assets			5,055				1,663
Property, Plant and Equipment			10,560				10,689
Accumulated depreciation			(1,707	)			(1,672	)
Property, Plant and Equipment, Net			8,853				9,017
Other Assets
Unconsolidated investments			62				79
Restricted cash and investments			1,173				1,221
Assets from risk-management activities			220				55
Goodwill			438				438
Intangible assets			465				497
Deferred income taxes			5				6
Accounts receivable, affiliates			2				—
Other long-term assets			255				245
Total Assets		$	16,528			$	13,221
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable		$	412			$	292
Accrued interest			55				56
Accrued liabilities and other current liabilities			132				201
Liabilities from risk-management activities			3,951				397
Notes payable and current portion of long-term debt			57				51
Liabilities held for sale			—				2
Total Current Liabilities			4,607				999
Long-term debt			5,819				5,739
Long-term debt, affiliates			200				200
Long-Term Debt			6,019				5,939
Other Liabilities
Liabilities from risk-management activities			489				116
Deferred income taxes			919				1,250
Other long-term liabilities			396				388
Total Liabilities			12,430				8,692
Minority Interest			18				23
Commitments and Contingencies (Note 10)
Stockholders’ Equity
Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at June 30, 2008 and December 31, 2007; 505,087,481 and 502,819,794 shares issued and outstanding at June 30, 2008 and December 31, 2007, respectively			5				5
Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at June 30, 2008 and December 31, 2007; 340,000,000 shares issued and outstanding at June 30, 2008 and December 31, 2007			3				3
Additional paid-in capital			6,476				6,463
Subscriptions receivable			(3	)			(5	)
Accumulated other comprehensive loss, net of tax			(42	)			(25	)
Accumulated deficit			(2,288	)			(1,864	)
Treasury stock, at cost, 2,560,727 and 2,449,259 shares at June 30, 2008 and December 31, 2007, respectively			(71	)			(71	)
Total Stockholders’ Equity			4,080				4,506
Total Liabilities and Stockholders’ Equity		$	16,528			$	13,221

See the notes to condensed consolidated financial statements.

4

DYNEGY INC.

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2008				2007				2008				2007
Revenues		$	323			$	828			$	868			$	1,333
Cost of sales			(456	)			(369	)			(907	)			(609	)
Operating and maintenance expense, exclusive of depreciation shown separately below			(125	)			(141	)			(237	)			(220	)
Depreciation and amortization expense			(93	)			(88	)			(186	)			(140	)
Gain on sale of assets			26				—				26				—
General and administrative expenses			(39	)			(48	)			(78	)			(101	)
Operating income (loss)			(364	)			182				(514	)			263
Losses from unconsolidated investments			(3	)			(2	)			(12	)			(2	)
Interest expense			(108	)			(84	)			(217	)			(151	)
Minority interest income (expense)			2				(9	)			2				(9	)
Other income and expense, net			15				10				35				18
Income (loss) from continuing operations before income taxes			(458	)			97				(706	)			119
Income tax benefit (expense) (Note 12)			186				(30	)			282				(36	)
Income (loss) from continuing operations			(272	)			67				(424	)			83
Income from discontinued operations, net of tax benefit (expense) of zero, $(5), $1 and $(4), respectively (Notes 3 and 12)			—				9				—				7
Net income (loss)		$	(272	)		$	76			$	(424	)		$	90
Earnings (Loss) Per Share (Note 9):
Basic earnings (loss) per share:
Income (loss) from continuing operations		$	(0.32	)		$	0.08			$	(0.51	)		$	0.13
Income from discontinued operations			—				0.01				—				0.01
Basic earnings (loss) per share		$	(0.32	)		$	0.09			$	(0.51	)		$	0.14
Diluted earnings (loss) per share:
Income (loss) from continuing operations		$	(0.32	)		$	0.08			$	(0.51	)		$	0.12
Income from discontinued operations			—				0.01				—				0.01
Diluted earnings (loss) per share		$	(0.32	)		$	0.09			$	(0.51	)		$	0.13
Basic shares outstanding			837				828				837				663
Diluted shares outstanding			839				830				839				665

See the notes to condensed consolidated financial statements.

5

DYNEGY INC.

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

	Six Months Ended June 30,
	2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(424	)		$	90
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization			188				146
Losses from unconsolidated investments, net of cash distributions			12				2
Risk-management activities			760				(97	)
Gain on sale of assets			(26	)			—
Deferred income taxes			(281	)			41
Legal and settlement charges			—				11
Other			—				10
Changes in working capital:
Accounts receivable			(77	)			(130	)
Inventory			23				(3	)
Prepayments and other assets			(178	)			(18	)
Accounts payable and accrued liabilities			61				119
Changes in non-current assets			(35	)			(17	)
Changes in non-current liabilities			9				3
Net cash provided by operating activities			32				157
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(299	)			(153	)
Unconsolidated investments			(1	)			(5	)
Proceeds from asset sales, net			84				—
Business acquisitions, net of cash acquired			—				(126	)
Decrease (increase) in restricted cash and restricted investments			28				(589	)
Other investing			11				—
Net cash used in investing activities			(177	)			(873	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net			111				2,663
Repayments of long-term borrowings			(21	)			(1,994	)
Proceeds from issuance of capital stock			2				1
Other financing, net			(4	)			(2	)
Net cash provided by financing activities			88				668
Net decrease in cash and cash equivalents			(57	)			(48	)
Cash and cash equivalents, beginning of period			328				371
Cash and cash equivalents, end of period		$	271			$	323
Other non-cash investing activity:
Noncash construction expenditures		$	34			$	—

See the notes to condensed consolidated financial statements.

6

DYNEGY INC.

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

	Three Months Ended June 30,
	2008				2007
Net income (loss)		$	(272	)		$	76
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net			20				—
Reclassification of mark-to-market losses to earnings, net			(1	)			(13	)
Deferred losses on cash flow hedges, net			(2	)			—
Changes in cash flow hedging activities, net (net of tax benefit (expense) of ($5) and $8, respectively)			17				(13	)
Allocation to minority interest			(9	)			—
Total cash flow hedging activities			8				(13	)
Recognized prior service cost and actuarial loss			1				1
Foreign currency translation adjustment			—				2
Unrealized gain (loss) on securities, net:
Unrealized gain (loss) on securities			1				(2	)
Less: Reclassification adjustments for gain realized in net loss			(9	)			—
Net unrealized losses (net of tax benefit of $5 and $1, respectively)			(8	)			(2	)
Unconsolidated investment other comprehensive loss, net (net of tax benefit of $4)			(7	)			—
Other comprehensive loss, net of tax			(6	)			(12	)
Comprehensive income (loss)		$	(278	)		$	64

	Six Months Ended June 30,
	2008				2007
Net income (loss)		$	(424	)		$	90
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net			(6	)			(59	)
Reclassification of mark-to-market gains (losses) to earnings, net			7				(28	)
Deferred losses on cash flow hedges, net			(2	)			—
Changes in cash flow hedging activities, net (net of tax benefit (expense) of zero and $51, respectively)			(1	)			(87	)
Allocation to minority interest			2				—
Total cash flow hedging activities			1				(87	)
Recognized prior service cost and actuarial loss			1				2
Foreign currency translation adjustment			—				2
Unrealized loss on securities, net:
Unrealized loss on securities			(3	)			(2	)
Less: Reclassification adjustments for gain realized in net loss			(9	)			—
Net unrealized losses (net of tax benefit of $8 and $1, respectively)			(12	)			(2	)
Unconsolidated investment other comprehensive loss, net (net of tax benefit of $4)			(7	)			—
Other comprehensive loss, net of tax			(17	)			(85	)
Comprehensive income (loss)		$	(441	)		$	5

See the notes to condensed consolidated financial statements.

7

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited) (in millions)

	June 30, 2008				December 31, 2007
ASSETS
Current Assets
Cash and cash equivalents		$	238			$	292
Restricted cash			123				104
Accounts receivable, net of allowance for doubtful accounts of $15 and $15 respectively			481				428
Accounts receivable, affiliates			1				1
Inventory			172				199
Assets from risk-management activities			3,363				358
Deferred income taxes			—				30
Prepayments and other current assets			342				145
Assets held for sale (Note 3)			304				57
Total Current Assets			5,024				1,614
Property, Plant and Equipment			10,560				10,689
Accumulated depreciation			(1,707	)			(1,672	)
Property, Plant and Equipment, Net			8,853				9,017
Other Assets
Unconsolidated investments			—				18
Restricted cash and investments			1,173				1,221
Assets from risk-management activities			220				55
Goodwill			438				438
Intangible assets			465				497
Deferred income taxes			5				6
Accounts receivable, affiliates			2				—
Other long-term assets			256				241
Total Assets		$	16,436			$	13,107
LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities
Accounts payable		$	412			$	291
Accrued interest			55				56
Accrued liabilities and other current liabilities			133				202
Deferred income taxes			7				—
Liabilities from risk-management activities			3,951				397
Notes payable and current portion of long-term debt			57				51
Liabilities held for sale			—				2
Total Current Liabilities			4,615				999
Long-term debt			5,819				5,739
Long-term debt to affiliates			200				200
Long-Term Debt			6,019				5,939
Other Liabilities
Liabilities from risk-management activities			489				116
Deferred income taxes			733				1,052
Other long-term liabilities			394				381
Total Liabilities			12,250				8,487
Minority Interest			18				23
Commitments and Contingencies (Note 10)
Stockholder’s Equity
Capital Stock, $1 par value, 1,000 shares authorized at June 30, 2008 and December 31, 2007, respectively			—				—
Additional paid-in capital			5,684				5,684
Affiliate receivable			(815	)			(825	)
Accumulated other comprehensive loss, net of tax			(42	)			(25	)
Accumulated deficit			(659	)			(237	)
Total Stockholder’s Equity			4,168				4,597
Total Liabilities and Stockholder’s Equity		$	16,436			$	13,107

See the notes to condensed consolidated financial statements.

8

DYNEGY HOLDINGS INC.

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

	Three Months Ended June 30,								Six Months Ended June 30,
	2008				2007				2008				2007
Revenues		$	323			$	828			$	868			$	1,333
Cost of sales			(456	)			(369	)			(907	)			(609	)
Operating and maintenance expense, exclusive of depreciation shown separately below			(125	)			(141	)			(237	)			(220	)
Depreciation and amortization expense			(93	)			(88	)			(186	)			(140	)
Gain on sale of assets			26				—				26				—
General and administrative expenses			(39	)			(46	)			(78	)			(82	)
Operating income (loss)			(364	)			184				(514	)			282
Earnings (losses) from unconsolidated investments			3				—				(2	)			—
Interest expense			(108	)			(84	)			(217	)			(151	)
Minority interest income (expense)			2				(9	)			2				(9	)
Other income and expense, net			14				12				34				16
Income (loss) from continuing operations before income taxes			(453	)			103				(697	)			138
Income tax benefit (expense) (Note 12)			184				(21	)			275				(32	)
Income (loss) from continuing operations			(269	)			82				(422	)			106
Income from discontinued operations, net of tax benefit (expense) of zero, $(6), $1 and $(5), respectively (Notes 3 and 12)			—				8				—				6
Net income (loss)		$	(269	)		$	90			$	(422	)		$	112

See the notes to condensed consolidated financial statements.

9

DYNEGY HOLDINGS INC.

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

	Six Months Ended June 30,
	2008				2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	(422	)		$	112
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization			188				146
Losses from unconsolidated investments, net of cash distributions			2				—
Risk-management activities			760				(97	)
Gain on sale of assets, net			(26	)			—
Deferred income taxes			(273	)			32
Legal and settlement charges			—				11
Other			(2	)			10
Changes in working capital:
Accounts receivable			(78	)			(130	)
Inventory			23				(3	)
Prepayments and other assets			(178	)			(18	)
Accounts payable and accrued liabilities			61				122
Changes in non-current assets			(35	)			(17	)
Changes in non-current liabilities			9				3
Net cash provided by operating activities			29				171
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(299	)			(153	)
Unconsolidated investments			10				—
Proceeds from asset sales, net			84				—
Business acquisitions, net of cash acquired			—				17
Decrease (increase) in restricted cash and restricted investments			28				(589	)
Affiliate transactions			1				(12	)
Other investing			7				—
Net cash used in investing activities			(169	)			(737	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net			111				2,663
Repayments of long-term borrowings			(21	)			(1,719	)
Dividend to affiliate			—				(342	)
Other financing, net			(4	)			1
Net cash provided by financing activities			86				603
Net increase (decrease) in cash and cash equivalents			(54	)			37
Cash and cash equivalents, beginning of period			292				243
Cash and cash equivalents, end of period		$	238			$	280
Other non-cash investing activity:
Noncash construction expenditures		$	34			$	—

See the notes to condensed consolidated financial statements.

10

DYNEGY HOLDINGS INC.

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

	Three Months Ended June 30,
	2008				2007
Net income (loss)		$	(269	)		$	90
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net			20				—
Reclassification of mark-to-market gains to earnings, net			(1	)			(13	)
Deferred losses on cash flow hedges, net			(2	)			—
Changes in cash flow hedging activities, net (net of tax benefit (expense) of ($5) and $8, respectively)			17				(13	)
Allocation to minority interest			(9	)			—
Total cash flow hedging activities			8				(13	)
Recognized prior service cost and actuarial loss			1				1
Foreign currency translation adjustment			—				2
Unrealized gain (loss) on securities, net:
Unrealized gain (loss) on securities			1				(2	)
Less: Reclassification adjustments for gain realized in net loss			(9	)			—
Net unrealized losses (net of tax benefit of $5 and $1, respectively)			(8	)			(2	)
Unconsolidated investment other comprehensive loss, net (net of tax benefit of $4)			(7	)			—
Other comprehensive loss, net of tax			(6	)			(12	)
Comprehensive income (loss)		$	(275	)		$	78

	Six Months Ended June 30,
	2008				2007
Net income (loss)		$	(422	)		$	112
Cash flow hedging activities, net:
Unrealized mark-to-market losses arising during period, net			(6	)			(59	)
Reclassification of mark-to-market gains (losses) to earnings, net			7				(28	)
Deferred losses on cash flow hedges, net			(2	)			—
Changes in cash flow hedging activities, net (net of tax benefit (expense) of zero and $51, respectively)			(1	)			(87	)
Allocation to minority interest			2				—
Total cash flow hedging activities			1				(87	)
Recognized prior service cost and actuarial loss			1				2
Foreign currency translation adjustment			—				2
Unrealized loss on securities, net:
Unrealized loss on securities			(3	)			(2	)
Less: Reclassification adjustments for gain realized in net income (loss)			(9	)			—
Net unrealized losses (net of tax benefit of $8 and $1, respectively)			(12	)			(2	)
Unconsolidated investment other comprehensive loss, net (net of tax benefit of $4)			(7	)			—
Other comprehensive loss, net of tax			(17	)			(85	)
Comprehensive income (loss)		$	(439	)		$	27

See the notes to condensed consolidated financial statements.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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 and DHI’s Form 10-K for the year ended December 31, 2007 filed on February 28, 2008, which we refer to as each registrant’s “Form 10-K”.

          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 informed 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 based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing 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, (vi) estimating various factors used to value our pension assets and liabilities and (vii) determining the primary beneficiary of certain VIEs from a set of related parties. 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.

     Accounting Principles Adopted

          SFAS No. 157. On January 1, 2008, we adopted portions of SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

          SFAS No. 159. On January 1, 2008, we adopted 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. We have not elected the fair value option to measure eligible items. Accordingly, this statement had no impact on our financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

     Accounting Principles Not Yet Adopted

          SFAS No. 141(R). On December 4, 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. SFAS No. 141(R) is effective for fiscal years beginning on or after December 15, 2008. We are currently evaluating the impact of this statement on our financial statements.

          SFAS No. 160. On December 4, 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”). SFAS No. 160 requires ownership interests in subsidiaries held by parties other than the parent be clearly identified, labeled, and presented in the consolidated statement of financial position within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and to the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of income; changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently; and any retained noncontrolling equity investment in the former subsidiary be initially measured at fair value. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We are currently evaluating the impact of this statement on our financial statements.

          SFAS No. 161. On March 19, 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). SFAS No. 161 is meant to improve transparency about the location and amounts of derivative instruments in an entity’s financial statements; how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended; and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 requires disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk–related and it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments. SFAS No. 161 is effective for fiscal years beginning on or after November 15, 2008. We are currently evaluating the impact of this statement on our financial statements.

          SFAS No. 162. On May 9, 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). SFAS No. 162 is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with GAAP for nongovernmental entities. Prior to the issuance of SFAS No. 162, GAAP hierarchy was defined in the American Institute of Certified Public Accountants (AICPA) Statement on Auditing Standards No. 69, “The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles” (“SAS No. 69”). SAS No. 69 has been criticized because it is directed to external auditors rather than the entity. SFAS No. 162 addresses these issues by establishing that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP. SFAS No. 162 is effective 60 days following the SEC’s approval. This statement will have no impact on our financial statements.

Note 2—Acquisitions and Contributions

          LS Power Business Combination. On April 2, 2007, Dynegy acquired through merger (the “Merger”) entities that owned ten power plants and a power plant under construction (collectively, the “Contributed Entities”) and 50 percent interests

13

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

in DLS Power Holdings, LLC (“DLS Power Holdings”), a development joint venture, and DLS Power Development Company, LLC (“DLS Power Development”) from 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. (the “LS Contributing Entities”). The aggregate purchase price 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 $44 million of which were paid in 2007. 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 portion of our Fifth Amended and Restated Credit Facility and (ii) an aggregate $70 million under a senior secured term loan facility. Please see Note 15—Debt—Fifth Amended and Restated Credit Facility in Dynegy’s and DHI’s Form 10-K for discussion of DHI’s borrowings. 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 benefits of such assets; and (iii) proven nature of the asset development platform that was subsequently contributed to DLS Power Holdings and DLS Power Development.

          In connection with the completion of the Merger, 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 percent interests in DLS Power Holdings and DLS Power Development, which are directly owned by Dynegy.

          The application of purchase accounting under SFAS No. 141, “Business Combinations” (“SFAS No. 141”), required 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, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The allocation process included 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 was based upon customary valuation procedures and techniques.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          The following table summarizes the 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		12
Property, plant and equipment		4,223
Intangible assets (including $9 million current)		224
Goodwill		486
Unconsolidated investments		83
Other		35
Total assets acquired	$	5,296
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		(627	)
Other		(96	)
Minority interest		22
Total liabilities and minority interest assumed	$	(2,766	)
Net assets acquired	$	2,530

          Included in Other liabilities was an intangible liability of $35 million in GEN-MW primarily related to a contract held by LSP Kendall Holding LLC, one of the entities acquired by Dynegy. LSP Kendall Holding LLC 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 an intangible liability from the perspective of LSP Kendall Holding LLC. Upon completion of the Merger, this power tolling agreement was effectively settled, which resulted in a $31 million second quarter 2007 gain equal to the fair value of this contract, in accordance with EITF Issue 04-1, “Accounting for Pre-existing Contractual Relationships Between the Parties to a Purchase Business Combination”. The gain is included in Cost of sales in our unaudited condensed consolidated statements of operations.

          Sithe Assets Contribution. On January 31, 2005, Dynegy acquired, and subsequently contributed to DHI in April 2007, 100 percent of the outstanding common shares of ExRes SHC, Inc. (“ExRes”), the parent company of Sithe Energies, Inc. (“Sithe Energies”) and Sithe/Independence Power Partners, L.P. (“Independence”). The results of the operations of ExRes have been included in Dynegy’s consolidated financial statements since January 31, 2005. Through this acquisition, Dynegy acquired the 1,064 MW Independence power generation facility located near Scriba, New York, as well as natural gas-fired merchant facilities in New York and hydroelectric generation facilities in Pennsylvania (the “Sithe Assets”).

          In April 2007, Dynegy Illinois contributed to DHI all of its interest in New York Holdings Inc. (“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 the Sithe Assets. The Sithe Assets primarily consist of the

15

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

Independence power generation facility. 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 Dynegy’s date of acquisition, January 31, 2005. 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 beginning January 31, 2005.

Note 3—Dispositions and Discontinued Operations

     Dispositions

          Rolling Hills. On July 31, 2008, we completed the sale of the Rolling Hills power generation facility to an affiliate of Tenaska Capital Management, LLC (“Tenaska”) for approximately $368 million, net of transaction costs. We expect to record a gain of approximately $50 million, subject to adjustments for working capital and other items, related to the sale of the facility in the third quarter 2008.

          Beginning in the second quarter 2008, Rolling Hills met the held for sale classification requirements of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“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 June 30, 2008 are $303 million of Property, Plant and Equipment, Net and $1 million of Inventory.

          In accordance with SFAS No. 144, we discontinued depreciation and amortization of Rolling Hills’ property, plant and equipment during the second quarter 2008. Depreciation and amortization expense related to Rolling Hills totaled approximately $1 million and approximately $3 million in the three and six month periods ended June 30, 2008, respectively, compared to approximately $2 million and approximately $4 million in the three and six month periods ended June 30, 2007, respectively.

          NYMEX Securities. In November 2006, the New York Mercantile Exchange (“NYMEX”) completed its initial public offering. At the time, we had two membership seats on the NYMEX, and therefore, we received 90,000 NYMEX shares for each membership seat. During August 2007, we sold 30,000 shares for approximately $4 million, and we recognized a gain of $4 million. During the second quarter 2008, we sold our remaining 150,000 shares and both of our membership seats for approximately $16 million, and we recognized a gain of $15 million, which is included in Gain on sale of assets in our unaudited condensed consolidated statements of operations largely offset by a reduction of $8 million, net of tax of $5 million, in our unaudited condensed consolidated statements of other comprehensive income (loss).

          Oyster Creek. In May 2008, we sold the beneficial interest in Oyster Creek Limited to General Electric for approximately $11 million, which is included in Gain on sale of assets in our unaudited condensed consolidated statements of operations.

     Discontinued Operations

          CoGen Lyondell. On August 1, 2007, we completed the sale of the 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.

          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 $1 million and $5 million in the three and six month periods ended June 30,

16

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

2007, respectively. Also pursuant to SFAS No. 144, we are reporting the results of CoGen Lyondell’s operations in discontinued operations for all periods presented.

          Calcasieu. On March 31, 2008, we completed the sale of the Calcasieu power generation facility to Entergy Gulf States, Inc. (“Entergy”) for approximately $56 million, net of transaction costs.

          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 less than $1 million and $1 million in the three and six month periods ended June 30, 2007, respectively. Also pursuant to SFAS No. 144, we are reporting the results of Calcasieu’s operations in discontinued operations for all periods presented.

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

	GEN-WE			CRM		NGL		Total
	(in millions)
Three Months Ended June 30, 2007
Revenues	$	87		$	—	$	—	$	87
Income from operations before taxes		3			11		—		14
Income (loss) from operations after taxes		(3	)		8		4		9
Six Months Ended June 30, 2008
Loss on sale before taxes	$	(1	)	$	—	$	—	$	(1	)
Loss on sale after taxes		—			—		—		—
Six Months Ended June 30, 2007
Revenues	$	155		$	—	$	—	$	155
Income from operations before taxes		—			11		—		11
Income (loss) from operations after taxes		(5	)		8		4		7

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

	GEN-WE			CRM		NGL		Total
	(in millions)
Three Months Ended June 30, 2007
Revenues	$	87		$	—	$	—	$	87
Income from operations before taxes		3			11		—		14
Income (loss) from operations after taxes		(3	)		7		4		8
Six Months Ended June 30, 2008
Loss on sale before taxes	$	(1	)	$	—	$	—	$	(1	)
Loss on sale after taxes		—			—		—		—
Six Months Ended June 30, 2007
Revenues	$	155		$	—	$	—	$	155
Income from operations before taxes		—			11		—		11
Income (loss) from operations after taxes		(5	)		7		4		6

Note 4—Risk Management Activities, Derivatives and Financial Instruments

          The nature of our business necessarily involves market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

commodity price risks with financially settled and other types of contracts. Our treasury team also manages our financial risks and exposures associated with interest expense variability. These risks and our strategy for mitigating them are more fully described in Note 6—Risk Management Activities and Financial Instruments of Dynegy’s and DHI’s Form 10-K. Consistent with our commodity risk management policy, our commercial team also uses financial instruments in an attempt to capture the benefit of fluctuations in market prices in the geographic regions where our assets operate.

          The following table summarizes the carrying value of the derivatives used in our risk management activities. In the table below, commodity-based derivative contracts primarily represent derivative contracts such as options, swaps and other derivative contracts, related to our generation business that we have not designated as accounting hedges,  that are entered into for purposes of hedging future fuel requirements and sales commitments and securing commodity prices we consider favorable under the circumstances.

	June 30, 2008			December 31, 2007
	(in millions)
Net liabilities:
Interest rate derivatives designated as cash flow and fair value accounting hedges	$	(41	)	$	(32	)
Interest rate derivatives not designated as accounting hedges		—			(2	)
Commodity-based derivative contracts not designated as accounting hedges		(816	)		(66	)
Net liabilities from risk management activities (1)	$	(857	)	$	(100	)

(1) Included in both current and non-current assets and liabilities on the unaudited condensed consolidated balance sheets.

          We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we did not elect to adopt the netting provisions allowed under FSP FIN 39-1, “Amendment of FASB Interpretation No. 39”, which allows an entity to offset the fair value amonts recognized for cash collateral paid or cash collateral received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. As a result, our consolidated balance sheets present derivative assets and liabilities, as well as cash collateral paid or received, on a gross basis. As of June 30, 2008, included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets, we had approximately $210 million of cash collateral postings, which represent the effect of net cash outflows arising from the daily settlements of our
exchange-traded or brokered commodity futures positions held with our futures clearing manager.

          Derivatives related to our generation business were designated as cash flow hedges in the past. However, beginning on April 2, 2007, we chose to cease designating such instruments related to our power generation business as cash flow hedges, and thus apply mark-to-market accounting treatment prospectively. Accordingly, as fair values fluctuate from period to period due to market price volatility, fair value changes and unrealized and realized gains and losses are reflected in the unaudited condensed consolidated statements of operations within Revenues 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”). As such, these mark-to-market gains and losses are not reflected in the unaudited condensed consolidated statements of operations in the same period as the underlying power sales from generation activity for which the derivative instruments serve as economic hedges.

          For the three and six months ended June 30, 2008, our revenues included approximately $481 million and $765 million, respectively, of mark-to-market losses related to this activity compared to $57 million and $34 million, respectively, of mark-to-market gains in the same periods in the prior year.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          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. Prior to April 2, 2007, we applied the cash flow hedge accounting model to certain GEN derivatives as discussed above. The balance in Other comprehensive 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 June 30, 2008, the remaining balance was a $7 million pre-tax loss.

          During the three and six month periods ended June 30, 2008, we recorded zero and $2 million, respectively, of income 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 six month periods ended June 30, 2007, we recorded zero and $5 million, respectively, of income related to ineffectiveness from changes in 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 six month periods ended June 30, 2008 and 2007, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

          The balance in cash flow hedging activities, net at June 30, 2008, is expected to be reclassified to future earnings when the hedged transaction impacts earnings. Of this amount, after-tax losses of approximately $4 million are currently estimated to be reclassified into earnings over the 12 month period ending June 30, 2009. 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 six month periods ended June 30, 2008 and 2007, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and six month periods ended June 30, 2008 and 2007, no amounts were recognized in relation to firm commitments that no longer qualified as fair value hedges.

          Fair Value Measurements. On January 1, 2007, we adopted SFAS No. 157. We did not record a cumulative effect upon the adoption. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure requirements for fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements. Accordingly, SFAS No. 157 does not require any new fair value measurements; however, for some entities the application of SFAS No. 157 will change current practice. The provisions of SFAS No. 157 are to be applied prospectively, except for the initial impact on three specific items: (i) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price under EITF No. 02-3, (ii) existing hybrid financial instruments measured initially at fair value using the transaction price and (iii) blockage factor discounts.

          FASB Staff Position No. FAS 157-2 defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008, with respect to non-financial assets and non-financial liabilities which are not recognized or disclosed at fair value in the financial statements on a recurring basis. Therefore, we have deferred application of SFAS No. 157 to such non-financial assets and non-financial liabilities until January 1, 2009.

          Fair value, as defined in SFAS No. 157, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). However, as permitted under SFAS No. 157, we utilize a mid-market pricing convention (the mid-point price between bid and

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

ask prices) as a practical expedient for valuing the majority of our assets and liabilities measured and reported at fair value. Where appropriate, valuation adjustments are made to account for various factors, including the impact of our credit risk, our counterparties’ credit risk and bid-ask spreads. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We are able to classify fair value balances based on the observability of those inputs. SFAS No. 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy defined by SFAS No. 157 are as follows:

• Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

• Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options and repurchase agreements.

• Level 3 – Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs as well as financial transmission rights. At each balance sheet date, we perform an analysis of all instruments subject to SFAS No. 157 and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2008. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value as of June 30, 2008
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Assets from risk management activities	$	—	$	3,566	$	17	$	3,583
Other		8		—		—		8
Total	$	8	$	3,566	$	17	$	3,591
Liabilities:
Liabilities from risk management activities	$	—	$	4,304	$	136	$	4,440
Total	$	—	$	4,304	$	136	$	4,440

          The determination of the fair values above incorporates various factors required under SFAS No. 157. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.

          Assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts. Some exchange-traded derivatives are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets. In such cases, these exchange-traded derivatives are classified within Level 2. OTC derivative trading instruments include swaps, forwards, options and complex structures that are valued at fair value. In certain instances, these instruments may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives trade in less active markets with a lower availability of pricing information. In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3. Other assets primarily represent available-for-sale securities.

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(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          The following table sets forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:

	Three Months Ended June 30, 2008
	(in millions)
Balance at March 31, 2008	$	(58	)
Unrealized losses		(40	)
Purchases, issuances and settlements		(20	)
Transfers out of Level 3		(1	)
Balance at June 30, 2008	$	(119	)
Change in unrealized losses relating to instruments still held as of June 30, 2008	$	(45	)
	Six Months Ended June 30, 2008
	(in millions)
Balance at December 31, 2007	$	(16	)
Unrealized losses		(66	)
Purchases, issuances and settlements		(36	)
Transfers out of Level 3		(1	)
Balance at June 30, 2008	$	(119	)
Change in unrealized losses relating to instruments still held as of June 30, 2008	$	(55	)

          Gains and losses (realized and unrealized) for Level 3 recurring items are included in revenues on the unaudited condensed consolidated statements of operations. We believe an analysis of instruments classified as Level 3 should be undertaken with the understanding that these items are generally hedging our generation portfolio.

          Transfers in and/or out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period.

Note 5—Accumulated Other Comprehensive Loss

          Accumulated other comprehensive 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:

	June 30, 2008			December 31, 2007
	(in millions)
Cash flow hedging activities, net	$	(38	)	$	(39	)
Foreign currency translation adjustment		27			27
Unrecognized prior service cost and actuarial loss		(24	)		(25	)
Available for sale securities		—			12
Accumulated other comprehensive loss — unconsolidated investments		(7	)		—
Accumulated other comprehensive loss, net of tax	$	(42	)	$	(25	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

Note 6—Variable Interest Entities

          Hydroelectric Generation Facilities. On January 31, 2005, Dynegy completed the acquisition of ExRes, the parent company of Sithe Energies, Inc. and Independence. 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)”). There was no material change during the three or six month periods ended June 30, 2008. Please see Note 12—Variable Interest Entities— Hydroelectric Generation Facilities in Dynegy’s and DHI’s Form 10-K for discussion of these entities.

          PPEA Holding Company LLC. On April 2, 2007, in connection with the completion of the Merger, we acquired a 70 percent interest in PPEA Holding Company LLC (“PPEA”). On December 13, 2007, we sold a portion of our interest in PPEA, reducing our ownership interest in PPEA to 37 percent. PPEA owns and operates Plum Point Energy Associates, LLC (“Plum Point”). Plum Point is constructing a 665 MW coal fired power generation facility (the “Plum Point Project”), located in Mississippi County, Arkansas, in which it owns an approximate 57 percent undivided interest. These assets consist primarily of $458 million of plant construction in progress at June 30, 2008. As of June 30, 2008, we have posted a $15 million letter of credit to support our equity contribution to the Plum Point Project. See Note 15—Debt—Plum Point Credit Agreement Facility for discussion of Plum Point’s borrowings in Dynegy’s and DHI’s Form 10-K. 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).

          DLS Power Holdings and DLS Power Development. On April 2, 2007, in connection with the transactions consummated by the Merger, Dynegy acquired a 50 percent 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 No. 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 $62 million, which represents its equity investment in these entities at June 30, 2008.

          Sandy Creek. Dynegy Sandy Creek Holdings, LLC (the “Dynegy Member”), an indirectly wholly owned subsidiary of Dynegy and DHI, and LSP Sandy Creek Member, LLC (the “LSP Member”) each own a 50 percent interest in Sandy Creek Holdings LLC (“SCH”), which owns all of SCEA. SCEA owns an undivided interest in the Sandy Creek Energy Station (the “Sandy Creek Project”), which is an 898 MW facility under construction in McLennan County, Texas. 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 percent interest in SC Services.

          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

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(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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 $273 million, which represents our $4 million of accumulated losses of unconsolidated companies in excess of investment at June 30, 2008, a note receivable of approximately $2 million and letters of credit totaling $275 million supporting our funding commitment.

          During the second quarter 2008, SCEA sold an 11 percent undivided interest in the Sandy Creek Project, reducing its undivided interest in the Sandy Creek Project from approximately 75 percent to approximately 64 percent. Earnings (losses) from unconsolidated investments includes income of approximately $13 million related to the sale. Using cash on hand and the proceeds of the sale, SCEA repaid approximately $45 million in project-related debt and approximately $7 million in affiliate debt. In addition, both the Dynegy Member and the LSP Member received a distribution of approximately $7 million during the second quarter 2008.

          In connection with the sale, SCH’s $200 million credit agreement commitment was reduced by approximately $30 million to $170 million. The Dynegy Member’s 50 percent share of SCH’s credit agreement funding obligation is supported by a letter of credit in the amount of $85 million issued under a stand-alone letter of credit facility between the Dynegy Member and ABN Amro Bank, N.V. The Dynegy Member’s and the LSP Member’s equity funding commitment also decreased from $223 million each to $190 million each. The Dynegy Member’s equity funding commitment is supported by a letter of credit in the amount of $190 million issued under a stand-alone letter of credit facility between the Dynegy Member and ABN Amro Bank, N.V.

Note 7—Debt

          Contingent LC Facility. On June 17, 2008, DHI entered into a Facility and Security Agreement (the “Contingent LC Facility”) with Morgan Stanley Capital Group Inc. (“Morgan Stanley”), as lender, issuing bank, collateral agent and paying agent.

          Availability under the Contingent LC Facility is contingent on natural gas prices rising above $13/MMBtu during 2009. For every dollar increase above $13/MMBtu in 2009 forward natural gas prices, $40 million in capacity will initially be available, up to a total of $300 million. In the event that the Contingent LC Facility is utilized, it will complement existing liquidity instruments as a source of additional letters of credit to meet our collateral requirements. Letter of credit availability will accrue ongoing fees at an annual rate of 3.2 percent. Over the course of 2009, the ratio of availability per dollar increase in natural gas prices will be reduced, on a pro rata monthly basis, to zero by year end.

          Such letters of credit will be available for the purpose of supporting certain commercial and trading contracts and related netting agreements described in DHI’s Fifth Amended and Restated Credit Agreement dated as of April 2, 2007, as amended (the “Credit Agreement “). As of June 30, 2008, no amounts were available under the Contingent LC Facility.

          Repayments. On June 30, 2008, we made a $21 million principal payment on the Sithe Energies 9.0 percent senior notes due 2013.

Note 8—Related Party Transactions

          Equity Investments. We hold four investments in joint ventures in which LS Power or its affiliates are also investors. Dynegy has a 50 percent ownership interest in DLS Power Holdings and DLS Power Development. DHI has 50 percent ownership interests in SCH and SC Services, which were contributed by Dynegy to DHI in August 2007. Please see Note 6—Variable Interest Entities for further discussion.

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(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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

Note 9—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.

          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 June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
	(in millions, except per share amounts)
Income (loss) from continuing operations for basic and diluted earnings (loss) per share	$	(272	)	$	67	$	(424	)	$	83
Basic weighted-average shares		837			828		837			663
Effect of dilutive securities:
Stock options and restricted stock		2			2		2			2
Diluted weighted-average shares		839			830		839			665
Income (loss) per share from continuing operations:
Basic	$	(0.32	)	$	0.08	$	(0.51	)	$	0.13
Diluted (1)	$	(0.32	)	$	0.08	$	(0.51	)	$	0.12

(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 six months ended June 30, 2008.

Note 10—Commitments and Contingencies

     Legal Proceedings

          Set forth below is a summary of our material ongoing legal proceedings. In accordance with SFAS No. 5 “Accounting for Contingencies”, 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.

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(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          Gas Index Pricing Litigation. We, several of our affiliates, our former joint venture affiliate WCP (Generation) Holdings LLC (“West Coast Power”) and other energy companies were named as defendants in twenty-two 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. Many of the cases have been resolved and those which remain are pending in Nevada district court and the Tennessee appellate court. Recent developments include:

• In October 2007, we, on behalf of ourselves and our former joint venture affiliate West Coast Power, entered into a confidential memorandum of understanding to settle the fourteen cases comprising the California-based gas index litigation. In February 2008, a formal settlement agreement was executed and funding occurred shortly thereafter. Dismissals with prejudice were entered by the court in March 2008. The settlement is without admission of wrongdoing, and we continue to deny plaintiffs’ allegations.

• In February 2007, the Tennessee state court dismissed a class action on defendants’ motion. Plaintiffs appealed and in November 2007, the case was argued to the appellate court. A ruling is expected in the third quarter 2008.

• In February 2008, the United States District Court in Las Vegas, Nevada granted defendants’ motion for summary judgment in a Colorado class action, which had been transferred to Nevada through the multi-district litigation process, thereby dismissing the case and all of plaintiffs’ claims. Plaintiffs moved for reconsideration and the court ordered additional briefing on plaintiffs’ declaratory judgment claims. Those issues are fully briefed and a decision is expected in the third quarter 2008.

• The remaining six cases, three of which seek class certification, are also pending in Nevada federal court. Five of the cases were transferred through multi-district litigation from other states, including Kansas, Wisconsin, Missouri and Illinois. All of the cases contain similar claims -- that individually and in conjunction with other energy companies, we engaged in an illegal scheme to inflate natural gas prices by providing false information to natural gas index publications. The complaints rely heavily on prior FERC and CFTC investigations into and reports concerning index manipulation in the energy industry. The lawsuits seek actual and punitive damages, restitution and/or expenses, and are currently in the discovery phase.

          We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining individual matters. 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.

          Nevada Power Arbitration. Through one of our indirect subsidiaries, we hold an ownership interest in Black Mountain, in which our equal partner is a CUSA subsidiary. Black Mountain 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 Black Mountain 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 Black Mountain is correct and (ii) Black Mountain 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, 2007, if an event of default occurred, Black Mountain would be required to pay approximately $136 million in cumulative excess payments, 50 percent of which would be our proportionate share. We previously disclosed that we agreed to guarantee 50 percent of any Black Mountain obligation to pay cumulative excess payments. Nevada Power further alleges that the cumulative excess payments calculation could equal approximately $365 million in 2023 and would be payable upon the scheduled termination of the power sale agreement, 50 percent of which would be our proportionate share. Management does not believe that Black Mountain has an obligation to pay any amount to Nevada Power upon the scheduled termination of the

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

agreement. In July 2008, the parties presented evidence and arguments in a week-long arbitration proceeding with post-hearing briefing and closing arguments scheduled in the third quarter. A ruling is expected in the fourth quarter 2008. We believe Nevada Power’s claims are without merit and we continue 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.

          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 Dynegy’s joint venture with LS Power; and alleged deficiencies in Dynegy’s SEC disclosures related to the foregoing. Since receiving the subpoena, Dynegy has worked with the New York Attorney General’s office to respond as appropriate.

          Illinova Arbitration. In June 2000, Dynegy’s subsidiary, 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 moved to enforce the arbitration award in state district court and the defendants have filed a motion to vacate the arbitration award. A hearing on these motions was held in December 2007, with a ruling expected in the third quarter 2008.

          Danskammer State Pollutant Discharge Elimination System Permit. In January 2005, the NYSDEC issued a Draft 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 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. The petitioners appealed and briefing was completed before the Third Department Appellate Division in April 2008. On June 19, 2008 the Appellate Division issued its Memorandum and Judgment confirming the determination of NYSDEC in issuing the revised Danskammer SPDES Permit and dismissed the appeal. Petitioners have filed notice of their intent to seek review of the decision before the New York Court of Appeals. We believe that the decisions of the Deputy Commissioner and the Appellate Division are well reasoned and will be affirmed if further review is granted. However, in the event the decisions are 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 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.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          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 of NYSDEC by us, NYSDEC staff, and the petitioners. We expect that the adjudicatory hearing on the Draft Roseton SPDES Permit will begin in 2009. 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 2000 in connection with modernization of the plant and the California Energy Commission’s licensing of that project. A local environmental group 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. On December 14, 2007, the Court of Appeals issued its opinion affirming the trial court’s judgment upholding the permit. The petitioners filed a Petition for Review by the Supreme Court of California, which was granted on March 19, 2008 with further action deferred pending disposition of several petitions for certiorari in the U. S. Supreme Court related to the EPA rule governing existing water intakes. On April 14, 2008, the U.S. Supreme Court granted petitions for certiorari to consider whether cost–benefit comparisons are authorized in determining BTA for cooling water intake structures.

          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 operations and cash flows.

          Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska initiated an action in federal court in the Northern District of California against DHI and 23 other companies in the energy industry. Plaintiffs claim that defendants’ emissions of greenhouse gases including CO2 contribute to climate change and have caused significant damage to a native Alaskan Eskimo village through increased vulnerability to waves, storm surges and erosion. In June 2008, defendants filed multiple motions to dismiss. Plaintiffs’ responses are due in September 2008. We believe the plaintiffs’ suit lacks merit and we intend to oppose their claims vigorously.

          Ordinary Course Litigation. In addition to the matters discussed above, 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.

28

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

     Regulatory Matters

          FERC Market-Based Rate Authority. FERC’s market-based rate authority allows the sale of power at negotiated rates through the bilateral market or within an organized energy market, conditioned on periodic review. In June 2007, FERC finalized a series of fundamental reforms to its market-based rate program intended to strengthen competitive markets and protect consumers from an electric power seller’s exercise of market power by reinforcing regulations for just and reasonable wholesale electric power sales. In order to maintain market-based rate authorization, sellers are required to submit periodic market power analyses. The triennial market power update analysis of the Dynegy Northeast assets must be filed with FERC by September 1, 2008.

     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, asset sales 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.

          West Coast Power Indemnities. In connection with the sale of our 50 percent 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. Upon execution of the California-based Gas Index Pricing Litigation settlement discussed above, West Coast Power is no longer a party to any active Gas Index Pricing Litigation matters subject to this indemnity. The indemnification agreement further provides that NRG assumes responsibility for all defense costs and any risk of loss, subject to certain conditions and limitations, arising from a February 2002 complaint filed at FERC by the California Public Utilities Commission alleging that several parties, including West Cost Power subsidiaries, overcharged the State of California for wholesale power. FERC found the rates charged by wholesale suppliers to be just and reasonable, however, this matter was appealed to the United States Supreme Court, which recently remanded the case to FERC for further review.

          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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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 percent of any such losses. In August 2007, the ICC issued its final Order in a case, which has been affirmed on appeal. Dynegy has adjusted the amount reserved for the various ongoing cases in light of this and other developments in other 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.

          Other Indemnities. During 2003, as part of our sales of the Rough and Hornsea natural gas storage facilities and certain natural gas liquids assets, we provided indemnities to third parties regarding tax representations. Maximum recourse under these indemnities is limited to $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 the Calcasieu, CoGen Lyondell and Rockingham power generating facilities as well as the Hartwell assets.

Note 11—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 21—Employee Compensation, Savings and Pension Plans in Dynegy’s and DHI’s Form 10-K.

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

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
	2008			2007			2008		2007
	(in millions)
Service cost benefits earned during period	$	2		$	3		$	—	$	—
Interest cost on projected benefit obligation		3			2			1		1
Expected return on plan assets		(4	)		(3	)		—		—
Recognized net actuarial loss		1			—			—		1
Total net periodic benefit cost	$	2		$	2		$	1	$	2
	Pension Benefits						Other Benefits
	Six Months Ended June 30,
	2008			2007			2008		2007
	(in millions)
Service cost benefits earned during period	$	5		$	5		$	1	$	1
Interest cost on projected benefit obligation		6			5			2		2
Expected return on plan assets		(7	)		(6	)		—		—
Recognized net actuarial loss		1			1			—		1
Total net periodic benefit cost	$	5		$	5		$	3	$	4

          Contributions. We made no contributions to our pension plans or other postretirement benefit plans during the six months ended June 30, 2008. We made approximately $1 million in contributions to our pension plans during the six months ended June 30, 2007.

30

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

Note 12—Income Taxes

          Effective Tax Rate. We generally 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. However, as of June 30, 2008, our year-to-date loss exceeds our anticipated loss for the year. Therefore, in accordance with FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28”, we have computed our quarterly taxes for the period ended June 30, 2008 by applying a year-to-date effective rate. 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 June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in millions, except rates)
Income tax benefit (expense)	$	186		$	(30	)	$	282		$	(36	)
Effective tax rate		41	%		31	%		40	%		30	%

          For the three and six months ended June 30, 2008, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes. For the three and six months ended June 30, 2007, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes and adjustments to our reserve for uncertain tax positions. During 2007, decreases in the New York state income tax rate and the Texas margin tax credit rate impacted the difference between the effective rate and the statutory rate.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in millions, except rates)
Income tax benefit (expense)	$	184		$	(21	)	$	275		$	(32	)
Effective tax rate		41	%		20	%		39	%		23	%

          For the three and six months ended June 30, 2008, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes. For the three and six months ended June 30, 2007, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes and adjustments to our reserve for uncertain tax positions. During 2007, decreases in the New York state income tax rate and the Texas margin tax credit rate impacted the difference between the effective rate and the statutory rate.

Note 13—Segment Information

          We report results of our power generation business in the following segments: (i) GEN-MW, (ii) GEN-WE, and (iii) GEN-NE. Beginning in the first quarter 2008, the results of our former CRM segment are included in Other as it does not meet the criteria required to be an operating segment as of January 1, 2008. Accordingly, we have restated the corresponding items of segment information for prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

31

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          Reportable segment information for Dynegy, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2008 and 2007 is presented below:

Dynegy’s Segment Data for the Three Months Ended June 30, 2008
(in millions)

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other				Total
Unaffiliated revenues:
Domestic		$	66			$	178			$	56			$	1			$	301
Other			—				—				22				—				22
Total revenues		$	66			$	178			$	78			$	1			$	323
Depreciation and amortization		$	(52	)		$	(25	)		$	(14	)		$	(2	)		$	(93	)
Operating loss		$	(170	)		$	(32	)		$	(142	)		$	(20	)		$	(364	)
Earnings (losses) from unconsolidated investments			—				3				—				(6	)			(3	)
Other items, net			2				4				—				11				17
Interest expense																			(108	)
Loss from continuing operations before income taxes																			(458	)
Income tax benefit																			186
Net loss																		$	(272	)
Identifiable assets:
Domestic		$	9,235			$	3,664			$	2,494			$	1,106			$	16,499
Other			—				—				17				12				29
Total		$	9,235			$	3,664			$	2,511			$	1,118			$	16,528
Unconsolidated investments		$	—			$	—			$	—			$	62			$	62
Capital expenditures and investments in unconsolidated affiliates		$	(134	)		$	(18	)		$	(12	)		$	(9	)		$	(173	)

32

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
Unaffiliated revenues:
Domestic		$	406			$	145			$	226		$	(3	)	$	774
Other			—				—				53			1			54
Total revenues		$	406			$	145			$	279		$	(2	)	$	828
Depreciation and amortization		$	(50	)		$	(23	)		$	(12	)	$	(3	)	$	(88	)
Operating income (loss)		$	160			$	(12	)		$	54		$	(20	)	$	182
Losses from unconsolidated investments			—				—				—			(2	)		(2	)
Other items, net			(9	)			—				—			10			1
Interest expense																	(84	)
Income from continuing operations before income taxes																	97
Income tax expense																	(30	)
Income from continuing operations																	67
Income from discontinued operations, net of taxes																	9
Net income																$	76
Identifiable assets:
Domestic		$	6,280			$	2,916			$	2,172		$	1,820		$	13,188
Other			—				7				21			108			136
Total		$	6,280			$	2,923			$	2,193		$	1,928		$	13,324
Unconsolidated investments		$	—			$	—			$	—		$	86		$	86
Capital expenditures and investments in unconsolidated affiliates		$	(92	)		$	(6	)		$	(16	)	$	(10	)	$	(124	)

33

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

Dynegy’s Segment Data for the Six Months Ended June 30, 2008
(in millions)

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
Unaffiliated revenues:
Domestic		$	230			$	309			$	235		$	—		$	774
Other			—				—				94			—			94
Total revenues		$	230			$	309			$	329		$	—		$	868
Depreciation and amortization		$	(105	)		$	(49	)		$	(27	)	$	(5	)	$	(186	)
Operating loss		$	(229	)		$	(78	)		$	(163	)	$	(44	)	$	(514	)
Losses from unconsolidated investments			—				(2	)			—			(10	)		(12	)
Other items, net			2				4				6			25			37
Interest expense																	(217	)
Loss from continuing operations before income taxes																	(706	)
Income tax benefit																	282
Net loss																$	(424	)
Identifiable assets:
Domestic		$	9,235			$	3,664			$	2,494		$	1,106		$	16,499
Other			—				—				17			12			29
Total		$	9,235			$	3,664			$	2,511		$	1,118		$	16,528
Unconsolidated investments		$	—			$	—			$	—		$	62		$	62
Capital expenditures and investments in unconsolidated affiliates		$	(249	)		$	(21	)		$	(22	)	$	(18	)	$	(310	)

34

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
Unaffiliated revenues:
Domestic		$	678			$	145			$	426		$	6		$	1,255
Other			—				—				77			1			78
Total revenues		$	678			$	145			$	503		$	7		$	1,333
Depreciation and amortization		$	(92	)		$	(24	)		$	(18	)	$	(6	)	$	(140	)
Operating income (loss)		$	260			$	(14	)		$	96		$	(79	)	$	263
Losses from unconsolidated investments			—				—				—			(2	)		(2	)
Other items, net			(9	)			—				—			18			9
Interest expense																	(151	)
Income from continuing operations before income taxes																	119
Income tax expense																	(36	)
Income from continuing operations																	83
Income from discontinued operations, net of taxes																	7
Net income																$	90
Identifiable assets:
Domestic		$	6,280			$	2,916			$	2,172		$	1,820		$	13,188
Other			—				7				21			108			136
Total		$	6,280			$	2,923			$	2,193		$	1,928		$	13,324
Unconsolidated investments		$	—			$	—			$	—		$	86		$	86
Capital expenditures and investments in unconsolidated affiliates		$	(115	)		$	(11	)		$	(19	)	$	(13	)	$	(158	)

35

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

          Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2008 and 2007 is presented below:

DHI’s Segment Data for the Three Months Ended June 30, 2008
(in millions)

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
Unaffiliated revenues:
Domestic		$	66			$	178			$	56		$	1		$	301
Other			—				—				22			—			22
Total revenues		$	66			$	178			$	78		$	1		$	323
Depreciation and amortization		$	(52	)		$	(25	)		$	(14	)	$	(2	)	$	(93	)
Operating loss		$	(170	)		$	(32	)		$	(142	)	$	(20	)	$	(364	)
Earnings from unconsolidated investments			—				3				—			—			3
Other items, net			2				4				—			10			16
Interest expense																	(108	)
Loss from continuing operations before income taxes																	(453	)
Income tax benefit																	184
Net loss																$	(269	)
Identifiable assets:
Domestic		$	9,235			$	3,664			$	2,494		$	1,014		$	16,407
Other			—				—				17			12			29
Total		$	9,235			$	3,664			$	2,511		$	1,026		$	16,436
Capital expenditures		$	(134	)		$	(18	)		$	(12	)	$	(4	)	$	(168	)

36

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
Unaffiliated revenues:
Domestic		$	406			$	145			$	226		$	(3	)	$	774
Other			—				—				53			1			54
Total revenues		$	406			$	145			$	279		$	(2	)	$	828
Depreciation and amortization		$	(50	)		$	(23	)		$	(12	)	$	(3	)	$	(88	)
Operating income (loss)		$	160			$	(12	)		$	54		$	(18	)	$	184
Other items, net			(9	)			—				—			12			3
Interest expense																	(84	)
Income from continuing operations before income taxes																	103
Income tax expense																	(21	)
Income from continuing operations																	82
Income from discontinued operations, net of taxes																	8
Net income																$	90
Identifiable assets:
Domestic		$	6,280			$	2,921			$	2,172		$	2,442		$	13,815
Other			—				—				21			83			104
Total		$	6,280			$	2,921			$	2,193		$	2,525		$	13,919
Capital expenditures		$	(92	)		$	(6	)		$	(16	)	$	(5	)	$	(119	)

37

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

DHI’s Segment Data for the Six Months Ended June 30, 2008
(in millions)

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
Unaffiliated revenues:
Domestic		$	230			$	309			$	235		$	—		$	774
Other			—				—				94			—			94
Total revenues		$	230			$	309			$	329		$	—		$	868
Depreciation and amortization		$	(105	)		$	(49	)		$	(27	)	$	(5	)	$	(186	)
Operating loss		$	(229	)		$	(78	)		$	(163	)	$	(44	)	$	(514	)
Losses from unconsolidated investments			—				(2	)			—			—			(2	)
Other items, net			2				4				6			24			36
Interest expense																	(217	)
Loss from continuing operations before income taxes																	(697	)
Income tax benefit																	275
Net loss																$	(422	)
Identifiable assets:
Domestic		$	9,235			$	3,664			$	2,494		$	1,014		$	16,407
Other			—				—				17			12			29
Total		$	9,235			$	3,664			$	2,511		$	1,026		$	16,436
Capital expenditures		$	(249	)		$	(21	)		$	(22	)	$	(7	)	$	(299	)

38

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

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

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
Unaffiliated revenues:
Domestic		$	678			$	145			$	426		$	6		$	1,255
Other			—				—				77			1			78
Total revenues		$	678			$	145			$	503		$	7		$	1,333
Depreciation and amortization		$	(92	)		$	(24	)		$	(18	)	$	(6	)	$	(140	)
Operating income (loss)		$	260			$	(14	)		$	96		$	(60	)	$	282
Other items, net			(9	)			—				—			16			7
Interest expense																	(151	)
Income from continuing operations before income taxes																	138
Income tax expense																	(32	)
Income from continuing operations																	106
Income from discontinued operations, net of taxes																	6
Net income																$	112
Identifiable assets:
Domestic		$	6,280			$	2,921			$	2,172		$	2,442		$	13,815
Other			—				—				21			83			104
Total		$	6,280			$	2,921			$	2,193		$	2,525		$	13,919
Capital expenditures		$	(115	)		$	(11	)		$	(19	)	$	(8	)	$	(153	)

39

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2008 and 2007

Note 14—Subsequent Event

          On July 31, 2008, we completed the sale of the Rolling Hills power generation facility to an affiliate of Tenaska Capital Management, LLC for approximately $368 million, net of transaction costs. Please see Note 3—Dispositions and Discontinued Operations—Dispositions—Rolling Hills for further discussion.

40

DYNEGY INC. and DYNEGY HOLDINGS INC.

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

For the Interim Periods Ended June 30, 2008 and 2007

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.

          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: (i) the Midwest segment (“GEN-MW”); (ii) the West segment (“GEN-WE”); and (iii) the Northeast segment (“GEN-NE”). Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

          In addition to our operating generation facilities, we own an approximate 37 percent interest in PPEA which in turn owns a 57 percent undivided interest in Plum Point, a 665 MW coal-fired power generation facility under construction in Arkansas, which is included in GEN-MW. We also own a 50 percent interest in SCH, which through a subsidiary owns an approximate 64 percent undivided interest in the Sandy Creek Project, 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 percent interest in a portfolio of greenfield development and brownfield expansion projects and repowering and/or expansion opportunities which is included in Other.

Recent Developments

          Rolling Hills. On July 31, 2008, we completed the sale of the Rolling Hills power generation facility to an affiliate of Tenaska Capital Management, LLC for approximately $368 million, net of transaction costs. We expect to record a gain of approximately $50 million related to the sale of the facility in the third quarter 2008. Please read Note 3—Dispositions and Discontinued Operations—Dispositions—Rolling Hills for further discussion.

          Contingent LC Facility. On June 17, 2008, DHI entered into the Contingent LC Facility with Morgan Stanley. Availability under the Contingent LC Facility is contingent on natural gas prices rising above $13/MMBtu during 2009. In the event that the Contingent LC Facility is utilized, it will complement existing liquidity instruments as a source of additional letters of credit to meet our collateral requirements. Such letters of credit will be available for the purpose of supporting certain commercial and trading contracts and related netting agreements described in the Credit Agreement. Please read Note 7—Debt—Contingent LC Facility for further discussion.

          Sandy Creek. On June 6, 2008, SCEA sold an 11 percent undivided interest in the Sandy Creek Project, to an unaffiliated third party, reducing its undivided interest in the project from approximately 75 percent to approximately 64 percent. Earnings from unconsolidated investments includes income of approximately $13 million related to the sale. Using cash on hand and the proceeds of the sale, SCEA repaid approximately $45 million in project related debt and approximately $7 million in affiliate debt. In addition, both the Dynegy Member and the LSP Member received a distribution of approximately $7 million during the second quarter 2008. Please read Note 6—Variable Interest Entities—Sandy Creek for further discussion.

41

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 (including required environmental expenditures) 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 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.

     Collateral Postings

          We 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 August 1, 2008, June 30, 2008 and December 31, 2007:

	August 1, 2008			June 30, 2008			December 31, 2007
	(in millions)
By Business:
Generation		$	1,371		$	1,572		$	1,130
Other			189			189			202
Total		$	1,560		$	1,761		$	1,332
By Type:
Cash (1)		$	2		$	28		$	53
Letters of Credit			1,558			1,733			1,279
Total		$	1,560		$	1,761		$	1,332

(1) Cash collateral postings exclude the effect of cash inflows and outflows arising from the daily settlements of our exchange-traded or brokered commodity futures positions held with our futures clearing manager.

          The changes in collateral postings from December 31, 2007 to June 30, 2008 and to August 1, 2008 are primarily due to the effect of changing commodity prices on the demand for collateral postings to support our ongoing power sales and fuel purchase programs. We also reduced our letters of credit posting by $48 million on June 6, 2008 as a result of SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project.

          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.

     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

42

activities. Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees.

          As of June 30, 2008, there were no material changes to our contractual obligations and contingent financial commitments since December 31, 2007.

     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 second quarter 2008, 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 Credit Agreement, which is scheduled to mature in April 2012, and under our Contingent LC Facility.

          Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at August 1, 2008, June 30, 2008 and December 31, 2007:

	August 1, 2008				June 30, 2008				December 31, 2007
	(in millions)
Revolver capacity		$	1,150			$	1,150			$	1,150
Borrowings against revolver capacity			—				—				—
Term letter of credit capacity, net of required reserves			825				825				825
Plum Point and Sandy Creek letter of credit capacity			377				377				425
Available contingent letter of credit facility capacity (1)			—				—				—
Outstanding letters of credit			(1,558	)			(1,733	)			(1,279	)
Unused capacity			794				619				1,121
Cash—DHI			880				238				292
Total available liquidity—DHI			1,674				857				1,413
Cash—Dynegy			32				33				36
Total available liquidity—Dynegy		$	1,706			$	890			$	1,449

(1) Under the terms of the Contingent LC Facility, up to $300 million capacity can become available, contingent on forward natural gas prices rising above $13/MMBtu during 2009.

          Cash Flows from Operations. Dynegy had operating cash inflows of $32 million for the six months ended June 30, 2008. This consisted of $324 million in operating cash flows from our power generation business, offset by $292 million of cash outflows relating to corporate-level expenses and our former customer risk management business.

          DHI had operating cash inflows of $29 million for the six months ended June 30, 2008. This consisted of $324 million in operating cash flows from our power generation business, offset by $295 million of cash outflows relating to corporate-level expenses and our former customer risk management business.

          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, the value of ancillary services and capacity and legal and regulatory requirements. Additionally, availability of our plants

43

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 August 1, 2008 and June 30, 2008, Dynegy had cash on hand of $912 million and $271 million, respectively, as compared to $328 million at December 31, 2007. The decrease in cash on hand at June 30, 2008 as compared to the end of 2007 is primarily attributable to an increase in cash margin postings on futures and exchange-cleared derivative positions partially offset by a reduction in cash collateral posting for the Sandy Creek Project, proceeds from the sale of the Calcasieu power generating facility and the sales of other assets, as well as cash provided by the operations of our power generating facilities. The increase in cash on hand from June 30, 2008 to August 1, 2008 was primarily due to proceeds received from the sale of the Rolling Hills power generation facility, as well as cash inflows arising from the daily settlements of our exchange – traded or brokered commodity futures positions held with our futures clearing manager.

          At August 1, 2008 and June 30, 2008, DHI had cash on hand of $880 million and $238 million, respectively, as compared to $292 million at December 31, 2007. The decrease in cash on hand at June 30, 2008 as compared to the end of 2007 is primarily attributable to an increase in cash margin postings on futures and exchange-cleared derivative positions partially offset by a reduction in cash collateral posting for the Sandy Creek Project, proceeds from the sale of the Calcasieu power generating facility and the sales of other assets, as well as cash provided by the operations of our power generating facilities. The increase in cash on hand from June 30, 2008 to August 1, 2008 was primarily due to proceeds received from the sale of the Rolling Hills power generation facility, as well as cash inflows arising from the daily settlements of our exchange – traded or brokered commodity futures positions held with our futures clearing manager.

     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 July 31, 2008, we completed the sale of the Rolling Hills power generation facility to an affiliate of Tenaska Capital Management, LLC for approximately $368 million, net of transaction costs. Please read Note 3—Dispositions and Discontinued Operations—Dispositions—Rolling Hills for further discussion.

          On March 31, 2008, we completed our sale of the Calcasieu power generation facility for approximately $56 million, net of transaction costs. Please read Note 3—Disposition and Discontinued Operations—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. 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.

          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

44

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.

          Capital Allocation. We continually review our investment options with respect to our capital resources. We do not have any material debt maturities until 2011, and between now and then we expect to enhance our current capital resources through the results of our operating business. We will seek to invest these capital resources in various projects and activities based on their return to stockholders. Potential investments could include, among others: add-on or other enhancement projects associated with our current power generation assets; greenfield or brownfield development projects; merger and acquisition activities; and returns of capital to stockholders through, for example, a share buy-back. Capital allocation determinations generally are subject to the discretion of Dynegy’s Board of Directors as well as availability of capital and related investment opportunities, and may be limited by the provisions of our credit agreement. Any particular use of capital in an amount that is not considered material may be made without any prior public disclosure and could occur at any time.

          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 six month periods ended June 30, 2008 and 2007. At the end of this section, we have included our outlook for each segment.

          We report the results of our power generation business as three separate geographical segments in our unaudited condensed consolidated financial statements. Beginning in the first quarter 2008, the results of our former customer risk management business are included in Other as it does not meet the criteria required to be an operating segment as of January 1, 2008. Accordingly, we have restated the corresponding items of segment information for prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

Three Months Ended June 30, 2008 and 2007

          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 June 30, 2008 and 2007, respectively:

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Dynegy’s Results of Operations for the Three Months Ended June 30, 2008

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other				Total
	(in millions)
Revenues		$	66			$	178			$	78			$	1			$	323
Cost of sales			(137	)			(163	)			(155	)			(1	)			(456	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(47	)			(33	)			(51	)			6				(125	)
Depreciation and amortization expense			(52	)			(25	)			(14	)			(2	)			(93	)
Gain on sale of assets, net			—				11				—				15				26
General and administrative expense			—				—				—				(39	)			(39	)
Operating loss		$	(170	)		$	(32	)		$	(142	)		$	(20	)		$	(364	)
Earnings (losses) from unconsolidated investments			—				3				—				(6	)			(3	)
Other items, net			2				4				—				11				17
Interest expense																			(108	)
Loss from continuing operations before income taxes																			(458	)
Income tax benefit																			186
Net loss																		$	(272	)

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

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other				Total
	(in millions)
Revenues		$	406			$	145			$	279			$	(2	)		$	828
Cost of sales			(142	)			(101	)			(159	)			33				(369	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(54	)			(33	)			(54	)			—				(141	)
Depreciation and amortization expense			(50	)			(23	)			(12	)			(3	)			(88	)
General and administrative expense			—				—				—				(48	)			(48	)
Operating income (loss)		$	160			$	(12	)		$	54			$	(20	)		$	182
Losses from unconsolidated investments			—				—				—				(2	)			(2	)
Other items, net			(9	)			—				—				10				1
Interest expense																			(84	)
Income from continuing operations before income taxes																			97
Income tax expense																			(30	)
Income from continuing operations																			67
Income from discontinued operations, net of taxes																			9
Net income																		$	76

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          The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the three month periods ended June 30, 2008 and 2007, respectively:

DHI’s Results of Operations for the Three Months Ended June 30, 2008

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other				Total
	(in millions)
Revenues		$	66			$	178			$	78			$	1			$	323
Cost of sales			(137	)			(163	)			(155	)			(1	)			(456	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(47	)			(33	)			(51	)			6				(125	)
Depreciation and amortization expense			(52	)			(25	)			(14	)			(2	)			(93	)
Gain on sale of assets, net			—				11				—				15				26
General and administrative expense			—				—				—				(39	)			(39	)
Operating loss		$	(170	)		$	(32	)		$	(142	)		$	(20	)		$	(364	)
Earnings from unconsolidated investments			—				3				—				—				3
Other items, net			2				4				—				10				16
Interest expense																			(108	)
Loss from continuing operations before income taxes																			(453	)
Income tax benefit																			184
Net loss																		$	(269	)

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

	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other				Total
	(in millions)
Revenues		$	406			$	145			$	279			$	(2	)		$	828
Cost of sales			(142	)			(101	)			(159	)			33				(369	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(54	)			(33	)			(54	)			—				(141	)
Depreciation and amortization expense			(50	)			(23	)			(12	)			(3	)			(88	)
General and administrative expense			—				—				—				(46	)			(46	)
Operating income (loss)		$	160			$	(12	)		$	54			$	(18	)		$	184
Other items, net			(9	)			—				—				12				3
Interest expense																			(84	)
Income from continuing operations before income taxes																			103
Income tax expense																			(21	)
Income from continuing operations																			82
Income from discontinued operations, net of taxes																			8
Net income																		$	90

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          The following table provides summary segmented operating statistics for the three months ended June 30, 2008 and 2007, respectively:

	Three Months Ended June 30,
	2008				2007
GEN-MW
Million Megawatt Hours Generated			5.5				6.0
In Market Availability for Coal Fired Facilities (1)			91	%			95	%
Average Capacity Factor for Combined Cycle Facilities (2)			11	%			15	%
Average Actual On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)		$	77			$	67
Commonwealth Edison (NI Hub)		$	75			$	62
PJM West		$	99			$	74
Average On-Peak Market Spark Spreads ($/MWh) (4):
PJM West		$	14			$	17
GEN-WE
Million Megawatt Hours Generated (5) (6)			2.3				2.7
Average Capacity Factor for Combined Cycle Facilities (2)			38	%			48	%
Average Actual On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)		$	97			$	69
Palo Verde		$	92			$	65
Average On-Peak Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)		$	18			$	16
Palo Verde		$	15			$	13
GEN-NE
Million Megawatt Hours Generated			1.6				1.8
In Market Availability for Coal Fired Facilities (1)			88	%			90	%
Average Capacity Factor for Combined Cycle Facilities (2)			22	%			19	%
Average Actual On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G		$	123			$	86
New York—Zone A		$	75			$	60
Mass Hub		$	114			$	77
Average On-Peak Market Spark Spreads ($/MWh) (4):
New York—Zone A		$	(9	)		$	3
Mass Hub		$	29			$	20
Fuel Oil		$	(41	)		$	(10	)
Average natural gas price—Henry Hub ($/MMBtu) (7)		$	11.32			$	7.54

(1)	Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.
(2)	Reflects actual production as a percentage of available capacity.
(3)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the Company.
(4)	Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to the Company.
(5)	Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the three months ended June 30, 2008 and 2007, respectively.
(6)	Excludes approximately 0.8 million MWh generated by our CoGen Lyondell power generation facility, which we sold in August 2007, for the three months ended June 30, 2007 and less than 0.1 million MWh generated by our Calcasieu power generation facility, which we sold on March 31, 2008, for the three months ended June 30, 2007.

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(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by the Company.

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

	Three Months Ended June 30, 2008
	Power Generation
	GEN-MW				GEN-WE			GEN-NE			Other			Total
	(in millions)
Gain on sale of NYMEX shares		$	—			$	—		$	—		$	15		$	15
Gain on sale of Oyster Creek ownership interest			—				11			—			—			11
Gain on sale of Sandy Creek ownership interest			—				13			—			—			13
Total		$	—			$	24		$	—		$	15		$	39
	Three Months Ended June 30, 2007
	Power Generation
	GEN-MW				GEN-WE			GEN-NE			Other			Total
	(in millions)
Discontinued operations		$	—			$	3		$	—		$	11		$	14
Illinois rate relief charge			(25	)			—			—			—			(25	)
Change in fair value of interest rate swaps, net of minority interest			(9	)			—			—			39			30
Settlement of Kendall toll			—				—			—			31			31
Total		$	(34	)		$	3		$	—		$	81		$	50

     Operating Income (Loss)

          Operating loss for Dynegy was $364 million for the three months ended June 30, 2008, compared to operating income of $182 million for the three months ended June 30, 2007. Operating loss for DHI was $364 million for the three months ended June 30, 2008, compared to operating income of $184 million for the three months ended June 30, 2007.

          Our operating loss for the second quarter of 2008 was driven, in large part, by mark-to-market losses on forward sales of power associated with our generating assets which are included in Revenues in the unaudited condensed consolidated statements of operations. Such losses, which totaled $481 million for the three months ended June 30, 2008, were a result of an increase in forward market power prices or forward spark spreads during the second quarter 2008 combined with greater outstanding notional amounts of forward positions compared to the same period in the prior year. We do not designate our commodity derivative instruments as cash flow hedges for accounting purposes. Please see Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion. The resulting mark-to-market accounting treatment results in the immediate recognition of gains and losses within revenues in the unaudited condensed consolidated statements of operations due to changes in the fair value of the derivative instruments. As such, these mark-to-market gains and losses are not reflected in the unaudited condensed consolidated statement of operations in the same period as the underlying power sales from generation activity for which the derivative instruments serve as economic hedges. Except for those positions that settled in the three months ended June 30, 2008, the expected cash impact of the settlement of these positions will be recognized over time through the end of 2010 based on the prices at which such positions are contracted. Our overall mark-to-market position and the related mark-to-market value will change as we buy or sell volumes within the forward market and as forward commodity prices fluctuate.

          Power Generation—Midwest Segment. Operating loss for GEN-MW was $170 million for the three months ended June 30, 2008, compared to operating income of $160 million for the three months ended June 30, 2007.

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          Revenues for the three months ended June 30, 2008 decreased by $340 million compared to the three months ended June 30, 2007, cost of sales decreased by $5 million and operating and maintenance expense decreased by $7 million, resulting in a net decrease of $328 million. The decrease was primarily driven by the following:

• Mark-to-market losses – GEN-MW’s results for the three months ended June 30, 2008 included mark-to-market losses of $286 million, compared to $54 million of mark-to-market gains for the three months ended June 30, 2007. Of the $286 million in 2008 mark-to-market losses, $110 million related to positions that settled or will settle in 2008, and the remaining $176 million related to positions that will settle in 2009 and beyond; and

• Decreased volumes – Generated volumes were 5.5 million MWh for the three months ended June 30, 2008, down from 6.0 million MWh for the three months ended June 30, 2007. The decrease in volumes was primarily driven by milder weather and transmission congestion as a result of flooding.

• Increased market prices were offset by widening basis differentials – The average actual on-peak prices in the Cin Hub and PJM West pricing regions increased from $67 and $74 per MWh, respectively, for the three months ended June 30, 2007 to $77 and $99 per MWh, respectively, for the three months ended June 30, 2008. However, in 2008, the price differential between the locations where we deliver generated power and the liquid market hubs where our forward power sales are located has continued to widen, in part due to congestion and transmission outages, as compared to the same period in the prior year. This widening price differential has had a negative impact on our results as the price we receive for delivered power at our physical delivery locations has not increased at the same rate as that of the liquid traded hubs; and

• In 2007, we recorded a pre-tax charge of $25 million related to our agreement to participate in a comprehensive rate relief package for Illinois electric consumers.

          Depreciation expense increased from $50 million for the second quarter 2007 to $52 million for the second quarter 2008.

          Power Generation—West Segment. Operating loss for GEN-WE was $32 million for the three months ended June 30, 2008, compared to a loss of $12 million for the three months ended June 30, 2007. Such amounts do not include results from our CoGen Lyondell and Calcasieu power generation facilities, which have been classified as discontinued operations for all periods presented.

          Revenues for the three months ended June 30, 2008 increased by $33 million compared to the three months ended June 30, 2007, cost of sales increased by $62 million and operating and maintenance expense remained unchanged, resulting in a net decrease of $29 million. The decrease was primarily driven by the following:

• Mark-to-market losses – GEN-WE’s results for the three months ended June 30, 2008 included mark-to-market losses of $55 million, compared to $31 million of mark-to-market losses for the three months ended June 30, 2007. Of the $55 million in 2008 mark-to-market losses, $26 million related to positions that settled or will settle in 2008, and the remaining $29 million related to positions that will settle in 2009 and beyond; and

• Decreased volumes – Generated volumes were 2.3 million MWh for the three months ended June 30, 2008, down from 2.7 million MWh for the three months ended June 30, 2007. The volume decrease was driven in large part by planned maintenance.

          These items were partially offset by a favorable tolling contract related to the Griffith power generating facility that went into effect during the second quarter 2008.

          In May 2008, we sold the beneficial interest in Oyster Creek Limited to General Electric for approximately $11 million, and recognized a gain on the sale of approximately $11 million. Depreciation expense increased from $23 million for the second quarter 2007 to $25 million for the second quarter 2008.

          Power Generation—Northeast Segment. Operating loss for GEN-NE was $142 million for the three months ended June 30, 2008, compared to operating income of $54 million for the three months ended June 30, 2007.

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          Revenues for the three months ended June 30, 2008 decreased by $201 million compared to the three months ended June 30, 2007, cost of sales decreased by $4 million and operating and maintenance expense decreased by $3 million, resulting in a net decrease of $194 million. The decrease was primarily driven by the following:

• Mark-to-market losses – GEN-NE’s results for the three months ended June 30, 2008 included mark-to-market losses of $140 million, compared to gains of $34 million for the three months ended June 30, 2007. Of the $140 million in 2008 mark-to-market losses, $40 million related to positions that settled or will settle in 2008, and the remaining $100 million related to positions that will settle in 2009 and beyond;

• Decreased spark spreads – Although on peak market power prices in New York Zone G and Zone A increased by 43 percent and 25 percent, respectively, spark spreads contracted as a result of higher fuel prices. Average market spark spreads in New York Zone A were negative for the three months ended June 30, 2008, as fuel prices rose at a greater rate than power prices; and

• Lower volumes – Generated volumes were 1.6 million MWh for the three months ended June 30, 2008, down from 1.8 million MWh for the three months ended June 30, 2007. The volume decrease was primarily driven by our Roseton facility, which was affected by higher fuel prices and decreased spark spreads making it less economic to run the facility as compared to the same period in the prior year.

          Depreciation expense increased from $12 million for the second quarter 2007 to $14 million for the second quarter 2008.

          Other. Dynegy’s other operating loss for the three months ended June 30, 2008 was $20 million, compared to a loss of $20 million for the three months ended June 30, 2007. Operating losses in both periods were comprised primarily of general and administrative expenses and results from our former customer risk management business. 2008 included an approximate $15 million gain related to our sale of our remaining NYMEX shares and both membership seats for approximately $16 million. 2008 also included a benefit of approximately $8 million related to the release of liabilities for state sales and franchise taxes. 2007 included a $31 million pre-tax gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the acquisition, 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—Acquisitions and Contributions—LS Power Business Combination for further discussion.

          Dynegy’s consolidated general and administrative expenses were $39 million and $48 million for the three months ended June 30, 2008 and 2007, respectively. General and administrative expenses for the three months ended June 30, 2007 included legal and settlement charges of $4 million and 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.

          DHI’s other operating loss for the three months ended June 30, 2008 was $20 million, compared to a loss of $18 million for the three months ended June 30, 2007. Operating losses in both periods were comprised primarily of general and administrative expenses and results from our former customer risk management business. 2008 included an approximate $15 million gain related to our sale of our remaining NYMEX shares and both membership seats for approximately $16 million. 2008 also included a benefit of approximately $8 million related to the release of liabilities for state sales and franchise taxes. 2007 included a $31 million pre-tax gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the acquisition, 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—Acquisitions and Contributions—LS Power Business Combination for further discussion.

          DHI’s consolidated general and administrative expenses were $39 million and $46 million for the three months ended June 30, 2008 and 2007, respectively. General and administrative expenses for the three months ended June 30, 2007 includes legal and settlement charges of $2 million and 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.

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     Earnings from Unconsolidated Investments

          Dynegy’s losses from unconsolidated investments were $3 million for the three months ended June 30, 2008. GEN-WE recognized $3 million of earnings related to its investment in the Sandy Creek Project. These earnings were comprised of our $13 million share of the gain on SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project, partly offset by our share of the partnership’s losses. Please see Note 6—Variable Interest Entities—Sandy Creek for further discussion. Equity earnings from the investment in Sandy Creek were more than offset by a $6 million loss related to Dynegy’s investment in DLS Power Development, included in Other. Losses from unconsolidated investments were $2 million for the three months ended June 30, 2007.

          DHI’s earnings from unconsolidated investments of $3 million for the three months ended June 30, 2008, related to the GEN-WE investment in the Sandy Creek Project. These earnings were comprised of our $13 million share of the gain on SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project, partly offset by our share of the partnership’s losses. Please see Note 6—Variable Interest Entities—Sandy Creek for further discussion. Earnings from unconsolidated investments were zero for the three months ended June 30, 2007.

     Other Items, Net

          Dynegy’s other items, net, totaled $17 million of income for the three months ended June 30, 2008, compared to $1 million of income for the three months ended June 30, 2007. These amounts included $2 million of minority interest income for the three months ended June 30, 2008, compared with $9 million of minority interest expense for the same period in 2007 related to the Plum Point development project. The minority interest income in 2008 and expense in 2007 is primarily related to the mark-to-market interest income and expense related to the interest rate swap agreements associated with the Plum Point Credit Facility Agreement. Please see “Interest Expense” below for further discussion. The remaining increase in other income was associated with higher interest income due to larger cash balances in 2008.

          DHI’s other items, net, totaled $16 million of income for the three months ended June 30, 2008, compared to $3 million of income for the three months ended June 30, 2007. These amounts included $2 million of minority interest income for the three months ended June 30, 2008, compared with $9 million of minority interest expense for the same period in 2007 related to the Plum Point development project. The minority interest income in 2008 and expense in 2007 is primarily related to the mark-to-market interest income and expense related to the interest rate swap agreements associated with the Plum Point Credit Facility Agreement. Please see “Interest Expense” below for further discussion. The remaining increase in other income was associated with higher interest income due to larger cash balances in 2008.

     Interest Expense

          Dynegy’s and DHI’s interest expense totaled $108 million for the three months ended June 30, 2008, compared to $84 million for the three months ended June 30, 2007. Included in interest expense for the three months ended June 30, 2007 is approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Term Facility. Effective July 1, 2007, these agreements were designated as cash flow hedges. Also included in interest expense for the three months ended June 30, 2007 is 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 is 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. After consideration of these items, interest expense was lower in the three months ended June 30, 2008 compared to the three months ended June 30, 2007 by $8 million due to lower interest rates.

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     Income Tax Benefit (Expense)

          Dynegy reported an income tax benefit from continuing operations of $186 million for the three months ended June 30, 2008, compared to an income tax expense from continuing operations of $30 million for the three months ended June 30, 2007. The 2008 effective tax rate was 41 percent, compared to 31 percent in 2007.

          DHI reported an income tax benefit from continuing operations of $184 million for the three months ended June 30, 2008, compared to an income tax expense of $21 million from continuing operations for the three months ended June 30, 2007. The 2008 effective tax rate was 41 percent, compared to 20 percent in 2007.

          In general, differences between these effective rates and the statutory rate of 35 percent resulted primarily from the effect of and incerase in state income taxes in the taxing jurisdictions in which our assets operate. During the three months ended June 30, 2007, the 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.

     Discontinued Operations

          Income From Discontinued Operations Before Taxes

          During the three months ended June 30, 2007, our pre-tax income from discontinued operations was $14 million which includes earnings of $3 million from the operation of the CoGen Lyondell and Calcasieu power generation facilities and income of $11 million related to a favorable settlement of a legacy receivable.

          Income Tax Expense From Discontinued Operations

          We recorded an income tax expense from discontinued operations of $5 million during the three months ended June 30, 2007. The effective rates for the three months ended June 30, 2007 was 36 percent. 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 percent.

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Six Months Ended June 30, 2008 and 2007

          Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the six month periods ended June 30, 2008 and 2007, respectively:

Dynegy’s Results of Operations for the Six Months Ended June 30, 2008
	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
	(in millions)
Revenues		$	230			$	309			$	329		$	—		$	868
Cost of sales			(261	)			(286	)			(368	)		8			(907	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(93	)			(63	)			(97	)		16			(237	)
Depreciation and amortization expense			(105	)			(49	)			(27	)		(5	)		(186	)
Gain on sale of assets, net			—				11				—			15			26
General and administrative expense			—				—				—			(78	)		(78	)
Operating loss		$	(229	)		$	(78	)		$	(163	)	$	(44	)	$	(514	)
Losses from unconsolidated investments			—				(2	)			—			(10	)		(12	)
Other items, net			2				4				6			25			37
Interest expense																	(217	)
Loss from continuing operations before income taxes																	(706	)
Income tax benefit																	282
Net loss																$	(424	)

Dynegy’s Results of Operations for the Six Months Ended June 30, 2007
	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
	(in millions)
Revenues		$	678			$	145			$	503		$	7		$	1,333
Cost of sales			(232	)			(102	)			(298	)		23			(609	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(94	)			(33	)			(91	)		(2	)		(220	)
Depreciation and amortization expense			(92	)			(24	)			(18	)		(6	)		(140	)
General and administrative expense			—				—				—			(101	)		(101	)
Operating income (loss)		$	260			$	(14	)		$	96		$	(79	)	$	263
Losses from unconsolidated investments			—				—				—			(2	)		(2	)
Other items, net			(9	)			—				—			18			9
Interest expense																	(151	)
Income from continuing operations before income taxes																	119
Income tax expense																	(36	)
Income from continuing operations																	83
Income from discontinued operations, net of taxes																	7
Net income																$	90

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          The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the six month periods ended June 30, 2008 and 2007, respectively:

DHI’s Results of Operations for the Six Months Ended June 30, 2008
	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
	(in millions)
Revenues		$	230			$	309			$	329			—		$	868
Cost of sales			(261	)			(286	)			(368	)		8			(907	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(93	)			(63	)			(97	)		16			(237	)
Depreciation and amortization expense			(105	)			(49	)			(27	)		(5	)		(186	)
Gain on sale of assets, net			—				11				—			15			26
General and administrative expense			—				—				—			(78	)		(78	)
Operating loss		$	(229	)		$	(78	)		$	(163	)	$	(44	)	$	(514	)
Losses from unconsolidated investments			—				(2	)			—			—			(2	)
Other items, net			2				4				6			24			36
Interest expense																	(217	)
Loss from continuing operations before income taxes																	(697	)
Income tax benefit																	275
Net loss																$	(422	)

DHI’s Results of Operations for the Six Months Ended June 30, 2007
	Power Generation
	GEN-MW				GEN-WE				GEN-NE				Other			Total
	(in millions)
Revenues		$	678			$	145			$	503		$	7		$	1,333
Cost of sales			(232	)			(102	)			(298	)		23			(609	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below			(94	)			(33	)			(91	)		(2	)		(220	)
Depreciation and amortization expense			(92	)			(24	)			(18	)		(6	)		(140	)
General and administrative expense			—				—				—			(82	)		(82	)
Operating income (loss)		$	260			$	(14	)		$	96		$	(60	)	$	282
Other items, net			(9	)			—				—			16			7
Interest expense																	(151	)
Income from continuing operations before income taxes																	138
Income tax expense																	(32	)
Income from continuing operations																	106
Income from discontinued operations, net of taxes																	6
Net income																$	112

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          The following table provides summary segmented operating statistics for the six months ended June 30, 2008 and 2007, respectively:

	Six Months Ended June 30,
	2008				2007
GEN-MW
Million Megawatt Hours Generated			11.4				11.6
In Market Availability for Coal Fired Facilities (1)			86	%			92	%
Average Capacity Factor for Combined Cycle Facilities (2)			11	%			—
Average Actual On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)		$	72			$	61
Commonwealth Edison (NI Hub)		$	71			$	58
PJM West		$	89			$	70
Average On-Peak Market Spark Spreads ($/MWh) (4):
PJM West		$	11			$	11
GEN-WE
Million Megawatt Hours Generated (5) (6)			4.7				2.7
Average Capacity Factor for Combined Cycle Facilities (2)			38	%			—
Average Actual On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)		$	89			$	65
Palo Verde		$	81			$	60
Average On-Peak Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)		$	18			$	12
Palo Verde		$	12			$	9
GEN-NE
Million Megawatt Hours Generated			3.6				3.8
In Market Availability for Coal Fired Facilities (1)			91	%			90	%
Average Capacity Factor for Combined Cycle Facilities (2)			23	%			—
Average Actual On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G		$	110			$	85
New York—Zone A		$	71			$	62
Mass Hub		$	102			$	79
Average On-Peak Market Spark Spreads ($/MWh) (4):
New York—Zone A		$	(3	)		$	7
Mass Hub		$	24			$	20
Fuel Oil		$	(38	)		$	—
Average natural gas price—Henry Hub ($/MMBtu) (7)		$	9.95			$	7.35

(1)	Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.
(2)	Reflects actual production as a percentage of available capacity.
(3)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices realized by the Company.
(4)	Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to the Company.
(5)	Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the six months ended June 30, 2008 and 2007, respectively.
(6)	Excludes approximately 1.5 million MWh generated by our CoGen Lyondell power generation facility, which we sold in August 2007, for the six months ended June 30, 2007 and less than 0.1 million MWh generated by our Calcasieu power generation facility, which we sold on March 31, 2008, for the six months ended June 30, 2008 and 2007, respectively.

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(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by the Company.

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

	Six Months Ended June 30, 2008
	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other		Total
	(in millions)
Release of state sales and franchise tax liabilities		$	—		$	—		$	—	$	16	$	16
Gain on sale of NYMEX shares			—			—			—		15		15
Gain on sale of Oyster Creek ownership interest			—			11			—		—		11
Gain on sale of Sandy Creek ownership interest			—			13			—		—		13
Total		$	—		$	24		$	—	$	31	$	55

	Six Months Ended June 30, 2007
	Power Generation
	GEN-MW				GEN-WE			GEN-NE			Other			Total
	(in millions)
Discontinued operations		$	—			$	—		$	—	$	11		$	11
Legal and settlement charges			—				—			—		(2	)		(2	)
Illinois rate relief charge			(25	)			—			—		—			(25	)
Change in fair value of interest rate swaps, net of minority interest			(9	)			—			—		39			30
Settlement of Kendall toll			—				—			—		31			31
Total—DHI			(34	)			—			—		79			45
Legal and settlement charges			—				—			—		(19	)		(19	)
Total—Dynegy		$	(34	)		$	—		$	—	$	60		$	26

     Operating Income (Loss)

          Operating loss for Dynegy was $514 million for the six months ended June 30, 2008, compared to operating income of $263 million for the six months ended June 30, 2007. Operating loss for DHI was $514 million for the six months ended June 30, 2008, compared to operating income of $282 million for the six months ended June 30, 2007.

          Our operating loss for the six months ended June 30, 2008 was driven, in large part, by mark-to-market losses on forward sales of power associated with our generating assets which are included in Revenues in the unaudited condensed consolidated statements of operations. Such losses, which totaled $765 million for the six months ended June 30, 2008, were a result of an increase in forward market power prices or forward spark spreads during the first half of 2008 combined with greater outstanding notional amounts of forward positions compared to the same period in 2007 partially due to the Merger. Effective April 2, 2007, we chose to cease designating our commodity derivative instruments as cash flow hedges for accounting purposes. Please see Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion. The resulting mark-to-market accounting treatment results in the immediate recognition of gains and losses within Revenues in the unaudited condensed consolidated statements of operations due to changes in the fair value of the derivative instruments. As such, these mark-to-market gains and losses are not reflected in the unaudited condensed consolidated statement of operations in the same period as the underlying power sales from generation activity for which the derivative instruments serve as economic hedges. Except for those positions that settled in the six months ended June 30, 2008, the expected cash

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impact of the settlement of these positions will be recognized over time through the end of 2010 based on the prices at which such positions are contracted. Our overall mark-to-market position and the related mark-to-market value will change as we buy or sell volumes within the forward market and as forward commodity prices fluctuate.

          Power Generation—Midwest Segment. Operating loss for GEN-MW was $229 million for the six months ended June 30, 2008, compared to operating income of $260 million for the six months ended June 30, 2007.

          Revenues for the six months ended June 30, 2008 decreased by $448 million compared to the six months ended June 30, 2007, cost of sales increased by $29 million and operating and maintenance expense decreased by $1 million, resulting in a net decrease of $476 million. The decrease was primarily driven by the following:

	•	Mark-to-market losses – GEN-MW’s results for the six months ended June 30, 2008 included mark-to-market losses of $479 million, compared to $35 million of mark-to-market gains for the six months ended June 30, 2007. Of the $479 million in 2008 mark-to-market losses, $258 million related to positions that settled or will settle in 2008, and the remaining $221 million related to positions that will settle in 2009 and beyond; and
	•	Lower volumes – In spite of the addition of the Midwest plants acquired through the Merger on April 2, 2007, generated volumes decreased by two percent, from 11.6 million MWh for the six months ended June 30, 2007, to 11.4 million MWh for the six months ended June 30, 2008. The decrease in volumes was primarily driven by forced outages, milder weather and transmission congestion as a result of flooding.
	These items were partly offset by the following:
	•	Kendall and Ontelaunee provided results of $55 million for the six months ended June 30, 2008 compared to $22 million for the six months ended June 30, 2007, exclusive of mark-to-market amounts discussed above;
	•	Increased market prices – The average actual on-peak prices in the Cin Hub and PJM West pricing regions increased from $61 and $70 per MWh, respectively, for the six months ended June 30, 2007 to $72 and $89 per MWh, respectively, for the six months ended June 30, 2008. However, in 2008, the price differential between the locations where we deliver generated power and the liquid market hubs where our forward power sales are located has continued to widen, in part due to congestion and transmission outages and regional weather differences, as compared to the same period in the prior year. This widening price differential has had a negative impact on our results as the price we receive for delivered power at our physical delivery locations has not increased at the same rate as that of the liquid traded hubs; and
	•	In 2007, we recorded a pre-tax charge of $25 million to support a comprehensive rate relief package for Illinois electric consumers.
Depreciation expense increased from $92 million for the six months ended June 30, 2007 to $105 million for the six months ended June 30, 2008 primarily as a result of the addition of Kendall and Ontelaunee.
Power Generation—West Segment. Operating loss for GEN-WE was $78 million for six months ended June 30, 2008, compared to a loss of $14 million for the six months ended June 30, 2007. Such amounts do not include results from our CoGen Lyondell and Calcasieu power generation facilities, which have been classified as discontinued operations for all periods presented.
Revenues for the six months ended June 30, 2008 increased by $164 million compared to the six months ended June 30, 2007, cost of sales increased by $184 million and operating and maintenance expense increased by $30 million, resulting in a net decrease of $50 million. The decrease was primarily driven by the following:
	•	Mark-to-market losses – GEN-WE’s results for the six months ended June 30, 2008 included mark-to-market losses of $102 million, compared to $33 million of mark-to-market losses for the six months ended June 30, 2007. Of the $102 million in 2008 mark-to-market losses, $68 million related to positions that settled or will settle in 2008, and the remaining $34 million related to positions that will settle in 2009 and beyond.

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• Mark-to-market losses were partially offset by increased volumes. Generated volumes were 4.7 million MWh for the six months ended June 30, 2008, up from 2.7 million MWh for the six months ended June 30, 2007. The volume increase was primarily driven by the West plants acquired on April 2, 2007, which provided total results of $63 million for the six months ended June 30, 2008, compared with $40 million for the same period 2007, exclusive of mark-to-market losses discussed above. Results for 2008 were negatively impacted by a forced outage.

          These items were partially offset by a favorable tolling contract related to the Griffith power generating facility that went into effect during the second quarter 2008.

          In May 2008, we sold a beneficial interest in Oyster Creek Limited to General Electric for approximately $11 million, and recognized a gain on the sale of approximately $11 million. Depreciation expense increased from $24 million for the six months ended June 30, 2007 to $49 million for the six months ended June 30, 2008 primarily as a result of the addition of the acquired plants.

          Power Generation—Northeast Segment. Operating loss for GEN-NE was $163 million for the six months ended June 30, 2008, compared to operating income of $96 million for the six months ended June 30, 2007.

          Revenues for the six months ended June 30, 2008 decreased by $174 million compared to the six months ended June 30, 2007, cost of sales increased by $70 million and operating and maintenance expense increased by $6 million, resulting in a net decrease of $250 million. The decrease was primarily driven by the following:

• Mark-to-market losses – GEN-NE’s results for the six months ended June 30, 2008 included mark-to-market losses of $184 million related to forward sales, compared to gains of $32 million for the six months ended June 30, 2007. Of the $184 million in 2008 mark-to-market losses, $65 million related to positions that settled or will settle in 2008, and the remaining $119 million related to positions that will settle in 2009 and beyond;

• Decreased spark spreads – Although on peak market prices in New York Zone G and Zone A increased by 29 percent and 15 percent, respectively, spark spreads contracted as a result of higher fuel prices. Average market spark spreads in New York Zone A were negative for the six months ended June 30, 2008, as fuel prices rose at a greater rate than power prices; and

• Lower volumes – In spite of the addition of the Northeast plants acquired through the Merger on April 2, 2007, generated volumes decreased by five percent, from 3.8 million MWh for the six months ended June 30, 2007 to 3.6 million MWh for the six months ended June 30, 2008. The volumes added by the new Northeast plants were more than offset by a decrease in generated volumes at our Roseton and Independence facilities, which were affected by higher fuel prices and decreased spark spreads.

• These items were partly offset by the addition of Bridgeport and Casco Bay, which provided results of $19 million for the six months ended June 30, 2008, compared with $9 million for the six months ended June 30, 2007, exclusive of mark-to-market losses discussed above.

          Depreciation expense increased from $18 million for the six months ended June 30, 2007 to $27 million for the six months ended June 30, 2008, primarily as a result of the addition of Bridgeport and Casco Bay.

          Other. Dynegy’s other operating loss for the six months ended June 30, 2008 was $44 million, compared to an operating loss of $79 million for the six months ended June 30, 2007. Operating losses in both periods were comprised primarily of general and administrative expenses and results from our former customer risk management business. 2008 included an approximate $15 million gain related to our sale of our remaining NYMEX shares and both membership seats for approximately $15 million. 2008 also included a benefit of approximately $16 million related to the release of liabilities for state sales and franchise taxes, as well as a $9 million benefit from the release of a liability associated with an assignment of a natural gas transportation contract. 2007 included a $31 million pre-tax gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the acquisition, 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—Acquisitions and Contributions—LS Power Business Combination for further discussion.

          Dynegy’s consolidated general and administrative expenses were $78 million and $101 million for the six months ended June 30, 2008 and 2007, respectively. General and administrative expenses for the six months ended

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June 30, 2007 included legal and settlement charges of $21 million and 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.

          DHI’s other operating loss for the six months ended June 30, 2008 was $44 million, compared to an operating loss of $60 million for the six months ended June 30, 2007. Operating losses in both periods were comprised primarily of general and administrative expenses and results from our former customer risk management business. 2008 included an approximate $15 million gain related to our sale of our remaining NYMEX shares and both membership seats for approximately $15 million. 2008 also included a benefit of approximately $16 million related to the release of liabilities for state sales and franchise taxes, as well as a $9 million benefit from the release of a liability associated with an assignment of a natural gas transportation contract. 2007 included a $31 million pre-tax gain associated with the acquisition of Kendall pursuant to EITF Issue No. 04-1. Prior to the acquisition, 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—Acquisitions and Contributions—LS Power Business Combination for further discussion.

          DHI’s consolidated general and administrative expenses were $78 million and $82 million for the six months ended June 30, 2008 and 2007, respectively. General and administrative expenses for the six months ended June 30, 2007 includes legal and settlement charges of $2 million and 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.

     Earnings from Unconsolidated Investments

          Dynegy’s losses from unconsolidated investments were $12 million for the six months ended June 30, 2008. GEN-WE recognized $2 million of losses related to its investment in the Sandy Creek Project. These losses were comprised of $15 million primarily associated with our share of the partnership’s losses, partially offset by our $13 million share of the gain on SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project. Please see Note 6—Variable Interest Entities—Sandy Creek for further discussion. The remaining $10 million loss related to its investment in DLS Power Development, included in Other. Losses from unconsolidated investments were $2 million for the six months ended June 30, 2007.

          DHI’s losses from unconsolidated investments were $2 million for the six months ended June 30, 2008. GEN-WE recognized $2 million of losses related to its investment in the Sandy Creek Project. These losses were comprised of $15 million primarily associated with our share of the partnership’s losses, partially offset by our $13 million share of the gain on SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project. Please see Note 6—Variable Interest Entities—Sandy Creek for further discussion. Earnings from unconsolidated investments were zero for the six months ended June 30, 2007.

     Other Items, Net

          Dynegy’s other items, net, totaled $37 million of income for the six months ended June 30, 2008, compared to $9 million of income for the six months ended June 30, 2007. These amounts included $2 million of minority interest income for the six months ended June 30, 2008, compared with $9 million of minority interest expense recorded in 2007 related to the Plum Point development project. The minority interest income in 2008 and expense in 2007 is primarily related to the mark-to-market interest income and expense related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion. In addition, during the first quarter 2008, we recognized income of $6 million related to insurance proceeds received in excess of the book value of damaged assets. The remaining increase in other income was associated with higher interest income due to larger cash balances in 2008.

          DHI’s other items, net, totaled $36 million of income for the six months ended June 30, 2008, compared to $7 million of income for the six months ended June 30, 2007. These amounts included $2 million of minority interest income for the six months ended June 30, 2008, compared with $9 million of minority interest expense recorded in 2007 related to the Plum Point development project. The minority interest income in 2008 and expense

60

in 2007 is primarily related to the mark-to-market interest income and expense related to the interest rate swap agreements associated with the Plum Point Credit Agreement. Please see “Interest Expense” below for further discussion. In addition, during the first quarter 2008, we recognized income of $6 million related to insurance proceeds received in excess of the book value of damaged assets. The remaining increase in other income was associated with higher interest income due to larger cash balances in 2008.

     Interest Expense

          Dynegy’s and DHI’s interest expense totaled $217 million for the six months ended June 30, 2008, compared to $151 million for the six months ended June 30, 2007. The increase was primarily attributable to the project debt assumed in connection with the Merger which was subsequently replaced, and secondarily to the associated growth in the size and utilization of our Credit Agreement. Included in interest expense for the six months ended June 30, 2007 is approximately $27 million of mark-to-market income from interest rate swap agreements associated with the Plum Point Term Facility. Effective July 1, 2007, these agreements have been designated as cash flow hedges. Also included in interest expense for the six months ended June 30, 2007 is 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 is 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.

     Income Tax Benefit (Expense)

          Dynegy reported an income tax benefit from continuing operations of $282 million for the six months ended June 30, 2008, compared to an income tax expense from continuing operations of $36 million for the six months ended June 30, 2007. The 2008 effective tax rate was 40 percent, compared to 30 percent in 2007.

          DHI reported an income tax benefit from continuing operations of $275 million for the six months ended June 30, 2008, compared to an income tax expense of $32 million from continuing operations for the six months ended June 30, 2007. The 2008 effective tax rate was 39 percent, compared to 23 percent in 2007.

          In general, differences between these effective rates and the statutory rate of 35 percent resulted primarily from the effect of an increase in state income taxes in the taxing jurisdictions in which our assets operate. During the six months ended June 30, 2007, the 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.

     Discontinued Operations

          Income From Discontinued Operations Before Taxes

          During the six months ended June 30, 2007, our pre-tax income from discontinued operations was $11 million which includes income of $11 million related to a favorable settlement of a legacy receivable.

          Income Tax Benefit (Expense) From Discontinued Operations

          We recorded an income tax benefit from discontinued operations of $1 million during the six months ended June 30, 2008 compared to an income tax expense of $4 million during the six months ended June 30, 2007. The effective rates for the six months ended June 30, 2008 and 2007 were 100 percent and 36 percent, 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 percent.

Outlook

          We expect that our future financial results will continue to reflect sensitivity to fuel and commodity prices, market structure and prices for electric energy, ancillary services, capacity and emissions allowances, transportation and transmission logistics, weather conditions and IMA. Our commercial team actively manages commodity price

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risk associated with our unsold power production by trading in the forward markets that are correlated with our assets. We also participate in various regional auctions and bilateral opportunities. Our regional commercial strategies are particularly driven by the types of units that we have within a given region and the operating characteristics of those units.

          Our fleet includes a diverse mixture of assets with various fuel, dispatch and merit order characteristics within each of our three regions. Our forward sales decisions are based on market fundamentals relative to each regional fleet profile. Our portfolio of sales agreements include short-term, medium-term and long-term contracts that range to five years and longer. Long-term contracts with terms of five years or longer, are generally intended to run to term and may include tolls or long-term power sale agreements related to our development projects. These contracts include terms designed to mitigate risks related to commodity prices and operation of the facilities such as a pass through of fuel costs and limited penalties for unavailability. Medium-term contracts, which range from two to five years, include structured deals and financial products, including options, and are intended to capture value from mid-term price trends but still provide some exposure to expected longer term upward price trends. We seek to commercialize the remainder of our fleet’s output via short-term sales, financial products, including options, spot sales and contract sales. We actively manage these positions, which are primarily associated with our baseload facilities, in an attempt to capitalize on commodity price volatility and other value capture opportunities. As a result, our fleet-wide forward sales profile is fluid and subject to change over time.

          We entered the year with a substantial portion of the output from our fleet of power generation facilities contracted for 2008. We commercialized nearly all of our output for the remainder of 2008 as we moved forward through the first half of 2008 and prices increased. As we look forward to 2009 and beyond, we are actively transacting in 2009 positions and expect to enter 2009 with a substantial portion of the output of our fleet contracted. Based on specific market conditions, at any point in time we may be above or below this level since we actively manage our near-term market positions of less than two years.

          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, electric energy and capacity markets.

          The following summarizes unique business issues impacting our individual regions’ outlook.

          GEN-MW. Our Midwest consent decree requires substantial emission reductions from our Illinois coal-fired power generating plants and the completion of several supplemental environmental projects in the Midwest. We have achieved all emission reductions scheduled to date under the Consent Decree and are installing additional emission control equipment to meet future Consent Decree emission limits. We expect our costs associated with the Midwest consent decree projects, which we expect to incur through 2012, to be approximately $960 million, which includes approximately $178 million spent to date. This estimate includes a number of assumptions and uncertainties beyond our control, including an assumption that labor and material costs will increase at four percent per year over the remaining project term.

          Our Midwest coal requirements are 100 percent contracted through 2010. For 2008, the prices associated with these contracts are fixed. Approximately 25 percent of our 2009 and 2010 coal requirements are currently unpriced, and will be priced in September 2008. The new prices determined in September will become effective January 1, 2009 and 2010, respectively. However, we expect that any price changes will be consistent with DMG’s historical price trend over the past several years.

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          PJM recently implemented a forward capacity auction, the Reliability Pricing Model. The auction has resulted in a generally upward trend 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 participating in the auction process, resulting in sales of capacity for the following planning years:

Planning Year	Net Capacity	Capacity Price
	(in MWs)	($ per MW-day)
2008-2009	885	112
2009-2010	2,240	102
2010-2011	2,057	174
2011-2012	2,061	110

          The MISO has delayed implementation of its ASM until September 2008. Upon implementation, MISO will administer the ASM through which load-serving entities will procure regulation and contingency reserves.

          GEN-WE. The Sandy Creek Project is currently in the construction phase and we anticipate it will begin commercial operations in 2012. Upon completion it will be a 898 MW facility to be located in McLennan County, Texas. Our interest in the facility, after giving effect to undivided interests in the project, is approximately 286 MW. In July 2006, the Texas Commission on Environmental Quality issued a Clean Air Act prevention of significant deterioration permit authorizing construction of the Sandy Creek power plant. Three environmental groups filed petitions for review of the air permit in District Court. Those petitions were dismissed by the District Court and in March 2007, the Petitioners appealed the decision. Oral argument on appeal was held on June 9, 2008. We believe that the Petitioners’ claims lack merit; however, an adverse result could cause delays in, or even abandonment of the Sandy Creek Project.

          GEN-NE. In the midst of steadily rising commodity prices for coal and oil, we continue to maintain sufficient coal and fuel oil inventories to effectively manage our operations. The balance of our coal supply requirements for 2008 is contracted at a fixed price. While domestic coal prices have been increasing significantly, we procure much of the coal for our Danskammer facility from South American suppliers at delivered prices that are competitively priced compared to domestic supplies. However, during the second quarter 2008, a foreign counterparty refused to comply with the terms of an agreement to supply coal to our Danskammer facility. While we have successfully resolved this contract dispute,  the cost of procuring our coal could increase further if our suppliers do not honor their contractual obligations. In addition, we are exploring various alternative contractual commitments and financial options to ensure stable fuel supplies and to further mitigate cost and supply risks for near and long-term coal supplies.

          In New England, the ISO-NE is in the process of restructuring its capacity market and will be transitioning to a forward capacity market in 2010. During the transition from the pre-existing capacity markets in ISO-NE to the forward capacity market, all listed Installed Capacity resources will receive monthly capacity payments, adjusted for each power year. The transitional payments for capacity commenced in December 2006, with a price of 3.05/KW-month, and gradually rise to $4.10/KW-month through June 1, 2010, when the forward capacity market will be fully effective. The auction for the 2010 power year was held in February 2008, and capacity prices cleared at $4.50/KW-month. The auction for the 2011 power year is planned for the Fall of 2008.

          Recently, we completed property tax settlements with the local taxing jurisdictions in connection with the assessed value of our Roseton and Danskammer generating facilities. While the amount of actual tax savings resulting from the reduction in the assessed value of these facilities will depend on future budgets of the various taxing jurisdictions, the projected savings in property taxes for the period 2008-2012 is approximately $55 million. As a result of the settlement, we will also receive a refund of $13 million in 2008 for prior years’ property tax payments.

     Regulatory Matters

          Clean Air Interstate Rule. The EPA issued CAIR on March 10, 2005 to significantly reduce SO2 and NOx emissions across 28 eastern states and the District of Columbia to address ozone and fine particulate nonattainment problems in downwind eastern states. A majority of our generating facilities were subject to the requirements of CAIR; however, on July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR.

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We are currently assessing the magnitude of the impact, if any, of this decision.

          RGGI. Our assets in New York, Connecticut and Maine are expected to become subject to RGGI as soon as 2009. The participating RGGI states have developed a model rule for regulating greenhouse gas using a cap-and-trade program to reduce carbon emissions by at least 10 percent of current emission levels by the year 2018.

          The RGGI rules proposed in Maine and New York would implement CO2 cap-and-trade programs, capping total authorized CO2 emissions from affected power generators beginning in 2009. The proposed rules would require that each affected power generator hold CO2 emission allowances equal to its annual CO2 emissions. Beginning in 2015, the CO2 emission caps and available allowances would be reduced each year until 2018. Compliance with the allowance requirement under a cap-and-trade program 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 state auctions. Although not all participating states will offer allowances in the first auction, the intent is to conduct the first RGGI auction of CO2 allowances in September 2008.

Cash Flow Disclosures

     Operating Cash Flow

          Dynegy. Dynegy’s cash flow provided by operations totaled $32 million for the six months ended June 30, 2008. During the six months ended June 30, 2008, our power generation business provided positive cash flow from operations of $324 million. Cash provided by the operation of our power generation facilities was partly offset by a $186 million increase in collateral postings, including the effect of cash inflows and outflows arising from the daily settlements of our exchange-traded or brokered commodity futures positions held with our futures clearing manager. Corporate and other operations include a use of approximately $292 million in cash primarily due to interest payments to service debt, general and administrative expenses and a $17 million legal settlement payment previously reserved, partially offset by interest income.

          Dynegy’s cash flow provided by operations totaled $157 million for the six months ended June 30, 2007. During the six months ended June 30, 2007, our power generation business provided positive cash flow from operations of $413 million primarily due to positive earnings for the period. Corporate and other operations include a use of approximately $256 million in cash primarily due to interest payments to service debt and general and administrative expenses and a $17 million legal settlement payment associated with the Illinova Arbitration offset by the receipt of approximately $32 million from the sale of a legacy receivable.

          DHI. DHI’s cash flow provided by operations totaled $29 million for the six months ended June 30, 2008. During the six months ended June 30, 2008, our power generation business provided positive cash flow from operations of $324 million from the operation of our power generation facilities. Cash provided by the operation of our power generation facilities was partly offset by a $186 million increase in collateral postings, including the effect of cash inflows and outflows arising from the daily settlements of our exchange-traded or brokered commodity futures positions held with our futures clearing manager. Corporate and other operations include a use of approximately $295 million in cash primarily due to interest payments to service debt, general and administrative expenses and a $17 million legal settlement payment previously reserved, partially offset by interest income.

          DHI’s cash flow provided by operations totaled $171 million for the six months ended June 30, 2007. During the six months ended June 30, 2007, our power generation business provided positive cash flow from operations of $413 million primarily due to positive earnings for the period. Corporate and other operations includes a use of approximately $242 million in cash primarily due to interest payments to service debt and general and administrative expense offset by the receipt of approximately $32 million from the sale of a legacy receivable.

     Capital Expenditures and Investing Activities

          Dynegy. Dynegy’s cash used in investing activities during the six months ended June 30, 2008 totaled $177 million. Capital spending of $299 million was primarily comprised of $249 million, $21 million and $22 million for

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our GEN-MW, GEN-WE and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $120 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 segment primarily related to maintenance and environmental projects, while spending in the GEN-NE and GEN-WE segments primarily related to maintenance projects. In addition, there was approximately $7 million of capital expenditures in Other.

          Dynegy also made $11 million in contributions to DLS Power Holdings during the six months ended June 30, 2008 offset by the distribution of approximately $7 million and repayment of approximately $3 million of an affiliate receivable from the Dynegy Member. Please see Note 6—Variable Interest Entities—Sandy Creek for further discussion.

          Proceeds from asset sales of $84 million, net of transaction costs, related to the sales of Calcasieu power generating facility, the NYMEX shares and seats, and the beneficial interest in Oyster Creek. Additionally, there was a $28 million cash inflow due to changes in restricted cash balances primarily due to a reduction of our cash collateral as a result of SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project, the release of restricted cash and the use of restricted cash for the ongoing construction of the Plum Point Project, partially offset by interest income. Finally, other included $7 million of insurance proceeds and $4 million of proceeds from the liquidation of an investment.

          Dynegy’s cash used in investing activities during the six months ended June 30, 2007 totaled $873 million. Capital spending of $153 million was primarily comprised of $115 million, $11 million, and $19 million for our GEN-MW, GEN-WE, and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $54 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 Dynegy’s GEN-NE segment primarily related to maintenance. Additionally, Dynegy made $5 million in contributions to DLS Power Holdings during the six months ended June 30, 2007.

          Cash used in connection with the completion of the Merger Agreement, net of cash acquired, was $126 million. Please see Note 2—Acquisitions and Contributions—LS Power Business Combination for further discussion. The increase in restricted cash of $589 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.

          DHI. DHI’s cash used in investing activities during the six months ended June 30, 2008 totaled $169 million. Capital spending of $299 million was primarily comprised of $249 million, $21 million and $22 million for our GEN-MW, GEN-WE and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $120 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 segment primarily related to maintenance and environmental projects, while spending in the GEN-NE and GEN-WE segments primarily related to maintenance projects. In addition, there was approximately $7 million of capital expenditures in Other.

          We also received a distribution of approximately $7 million and repayment of approximately $3 million of an affiliate receivable from the Dynegy Member. Please see Note 6—Variable Interest Entities—Sandy Creek for further discussion.

          Proceeds from asset sales of $84 million, net of transaction costs, related to the sales of Calcasieu power generating facility, the NYMEX shares and seats, and the beneficial interest in Oyster Creek. Additionally, there was a $28 million cash inflow due to changes in restricted cash balances primarily due to a reduction of our cash collateral as a result of SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project, the release of restricted cash and the use of restricted cash for the ongoing construction of the Plum Point Project, partially offset by interest income. Finally, other included $7 million of insurance proceeds.

          DHI’s cash used in investing activities during the six months ended June 30, 2007 totaled $737 million. Capital spending of $153 million was primarily comprised of $115 million, $11 million, and $19 million for our GEN-MW, GEN-WE, and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes

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$54 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 Dynegy’s GEN-NE segment primarily related to maintenance.

          The decrease in restricted cash of $589 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.

     Financing Activities

          Dynegy. Dynegy’s cash provided by financing activities during the six months ended June 30, 2008 totaled $88 million, which primarily related to $111 million proceeds from long-term borrowings under the Plum Point Credit Agreement Facility, partly offset by a $21 million principal payment on our 9.00 percent secured bonds due 2013.

          Dynegy’s cash provided by financing activities during the six months ended June 30, 2007 totaled $668 million. During the six months ended June 30, 2007, Dynegy received proceeds from long-term borrowings from the following sources, net of approximately $31 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
•	$34 million in aggregate principal amount on our Plum Point Credit Agreement Facility.
These borrowings were partially offset by $1,994 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 Term Loan;
•	$150 million in aggregate principal amount on our Gen Finance Term Loan;
•	$275 million promissory note to LS;
•	$70 million Griffith debt;
•	$19 million in aggregate principal amount on our 8.50 percent secured bonds due 2007; and
•	$15 million in aggregate principal amount on our letter of credit facilities.

          DHI. DHI’s cash provided by financing activities during the six months ended June 30, 2008 totaled $86 million, which primarily related to $111 million proceeds from long-term borrowings under the Plum Point Credit Agreement Facility, partly offset by a $21 million principal payment on our 9.00 percent secured bonds due 2013.

          DHI’s cash provided by financing activities during the six months ended June 30, 2007 totaled $603 million. During the six months ended June 30, 2007, DHI received proceeds from long-term borrowings from the following sources, net of approximately $31 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

• $34 million in aggregate principal amount on our Plum Point Credit Agreement Facility.

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          These borrowings were partially offset by $1,719 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 Term Loan;

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

• $70 million Griffith debt;

• $19 million in aggregate principal amount on our 8.50 percent secured bonds due 2007; and

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

          Cash used in financing activities for the six months ended June 30, 2007 also included dividend payments to Dynegy totaling $342 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 Six Months Ended June 30, 2008
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2008		$	(100	)
Risk-management losses recognized through the income statement in the period, net			(764	)
Cash paid related to risk-management contracts settled in the period, net			14
Changes in fair value as a result of a change in valuation technique (1)			—
Non-cash adjustments and other (2)			(7	)
Fair value of portfolio at June 30, 2008		$	(857	)

(1)	Our modeling methodology has been consistently applied.
(2)	This amount consists of changes in value associated with fair value and cash flow hedges on debt.

          The net risk management liability of $857 million is the aggregate of the following line items on our unaudited 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. During the period from December 31, 2007 to June 30, 2008, our Current Assets—Assets from risk-management activities and Current Liabilities—Liabilities from risk-management activities increased by $3.0 billion and $3.6 billion, respectively. This increase was primarily a result of increased volumes of purchases and sales of commodities via financial instruments. These amounts are reflected gross on our condensed consolidated balance sheets, as we do not offset fair value amounts recognized for derivative instruments executed with the same counterparties under a master netting agreement. However, a substantial portion of the financial instruments are with the same counterparty, resulting in a significantly smaller increase in our net risk-management liability, as denoted above. Please see Item 3.—Quantitative and Qualitative Disclosures About Market Risk—Credit Risk for further discussion regarding our counterparty credit exposure associated with risk-management accounts.

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          Risk-Management Asset and Liability Disclosures. The following tables depict the mark-to-market value and cash flow components of our net risk-management assets and liabilities at June 30, 2008 and December 31, 2007. We may receive or pay cash in periods other than those depicted below as opportunities arise to monetize positions that we believe will result in an economic benefit to us:

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

	Total			2008 (2)				2009			2010			2011		2012		Thereafter
	(in millions)
June 30, 2008	$	(816	)		$	(409	)	$	(374	)	$	(40	)	$	2	$	1		$	4
December 31, 2007		(66	)			(30	)		(29	)		(12	)		1		1			3
Decrease (increase) (3)	$	(750	)		$	(379	)	$	(345	)	$	(28	)	$	1	$	—		$	1

(1)	The table reflects the fair value of our risk-management liability 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 liability at June 30, 2008 of $857 million on the unaudited condensed consolidated balance sheets includes the $816 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 July 1 to December 31, 2008 values in the June 30, 2008 row and January 1 to December 31, 2008 values in the December 31, 2007 row.
(3)	The increase in the net risk management liability is due to an increase in the volume of outstanding positions during the six months ended June 30, 2008 as well as a significant increase in the prices associated with these positions.

Cash Flow Components of Net Risk-Management Liability

	Six Months Ended June 30, 2008			Six Months Ended December 31, 2008				Total 2008			2009			2010			2011		2012		Thereafter
	(in millions)
June 30, 2008 (1)		$	3		$	(405	)	$	(402	)	$	(371	)	$	(38	)	$	2	$	1		$	6
December 31, 2007									(28	)		(27	)		(12	)		2		1			5
Decrease (increase)								$	(374	)	$	(344	)	$	(26	)	$	—	$	—		$	1

(1) The cash flow values for 2008 reflect realized cash flows for the six months ended June 30, 2008 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 credit or valuation 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 June 30, 2008, based on our valuation methodology:

Net Fair Value of Risk-Management Portfolio

	Total			2008			2009			2010			2011		2012		Thereafter
	(in millions)
Market Quotations (1)(2)	$	(740	)	$	(354	)	$	(370	)	$	(23	)	$	2	$	1		$	4
Prices Based on Models(2)		(117	)		(62	)		(38	)		(17	)		—		—			—
Total	$	(857	)	$	(416	)	$	(408	)	$	(40	)	$	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.
(2)	The market quotations and prices based on models categorization differs from the SFAS No. 157 categories of Level 1, Level 2, and Level 3 due to the application of the different methodologies. Please see Note 4—

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Risk Management Activities, Derivatives and Financial Instruments—Fair Value Measurements for further discussion.

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:

• beliefs about commodity pricing and generation volumes;

• sufficiency of and access to coal, fuel oil and natural gas inventories and transportation;

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

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

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

• 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 climate change;

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

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

• beliefs and assumptions relating to liquidity;

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

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

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

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

• expectations and estimates regarding the Midwest 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.

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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 “Critical Accounting Policies” of Dynegy’s and DHI’s Form 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 in Dynegy’s and DHI’s Form 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 liabilities, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of June 30, 2008.

          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 remaining legacy customer risk management 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. In addition, the actual change in the fair value of several financially-settled heat rate call-option agreements acquired as a result of the Merger may differ significantly from the calculated VaR. The increase in the June 30, 2008 VaR was primarily due to increased forward sales and higher volatility compared to December 31, 2007.

Daily and Average VaR for Risk-Management Portfolios

	June 30, 2008			December 31, 2007
	(in millions)
One Day VaR—95 percent Confidence Level		$	50		$	24
One Day VaR—99 percent Confidence Level		$	70		$	35
Average VaR for the Year-to-Date Period—95 percent Confidence Level		$	43		$	20

          Credit Risk. The following table represents our credit exposure at June 30, 2008 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		$	97
Utility and Power Generators			36
Other			3
Total		$	136

          Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of June 30, 2008, our fixed rate debt instruments, as a percentage of total debt instruments, were approximately 76 percent. Adjusted for interest rate swaps, net notional fixed rate debt as a percentage of total debt was approximately 82 percent. Based on sensitivity analysis of the variable rate financial obligations in our debt

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portfolio as of June 30, 2008, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the 12 months ended June 30, 2009 would either decrease or increase interest expense by approximately $11 million. This exposure would be partially offset by an approximate $9 million increase in interest income related to the restricted cash balance of $850 million posted as collateral to support the term letter of credit facility. 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 June 30, 2008 and December 31, 2007, respectively:

Absolute Notional Contract Amounts

	June 30, 2008			December 31, 2007
Cash flow hedge interest rate swaps (in millions of U.S. dollars)		$	406		$	310
Fixed interest rate paid on swaps (percent)			5.32			5.32
Fair value hedge interest rate swaps (in millions of U.S. dollars)		$	25		$	25
Fixed interest rate received on swaps (percent)			5.70			5.70
Interest rate risk-management contract (in millions of U.S. dollars)		$	231		$	231
Fixed interest rate paid (percent)			5.35			5.35
Interest rate risk-management contract (in millions of U.S. dollars)		$	206		$	206
Fixed interest rate received (percent)			5.28			5.28

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

     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 second quarter 2008 relating to Dynegy’s and DHI’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, as of June 30, 2008, as a result of the material weakness identified and discussed below, Dynegy’s and DHI’s disclosure controls and procedures were not effective to ensure that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the requisite time periods.

          Notwithstanding the material weakness that existed at June 30, 2008, management believes, based on its knowledge, that the financial statements and other financial information included in this report, fairly present, in all material respects in accordance with GAAP, our financial condition, results of operations and cash flows as of and for the periods presented in this report.

     Material Weakness Related to Revenues and Cost of Sales

          As of March 31, 2008, we did not maintain effective controls over the accuracy of our revenues and cost of sales amounts. Our processes, procedures and controls related to the calculation and analysis of the presentation of revenues and cost of sales related to energy trading activities on a net basis were not effective to ensure that the revenues and cost of sales amounts were accurately reflected in the financial statements. This control deficiency resulted in the restatement of our March 31, 2008 financial statements by a material amount.

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          In order to remediate this material weakness, we implemented the following steps: (i) further formalized and documented the change management procedures surrounding the quarterly revenue netting calculation; (ii) expanded the management review of the calculation; and (iii) formalized and documented additional analysis to be performed on our revenues and cost of sales amounts.

          We believe we have taken the steps necessary to remediate this material weakness. However, the controls have not been in place for an adequate period of time to test and conclude that they are operating effectively. Therefore, as of June 30, 2008, we concluded that this control deficiency continues to constitute a material weakness. Additionally, we will continue to vigorously monitor the effectiveness of these processes, procedures and controls and will make any further changes management deems are necessary.

     Changes in Internal Controls Over Financial Reporting

          Other than as noted above in this Item 4, 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 second quarter 2008.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

PART II. OTHER INFORMATION

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

          See Note 10—Commitments and Contingencies—Legal Proceedings 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.

Because most of our power generation facilities operate mostly without term power sales agreements and because wholesale power prices are subject to significant volatility, our revenues and profitability are subject to significant fluctuations.

          Most of our facilities operate as “merchant” facilities without term power sales agreements. Without term power sales agreements, we cannot be sure that we will be able to sell any or all of the electric energy, capacity or ancillary services from our facilities at commercially attractive rates or that our facilities will be able to operate profitably. This could lead to decreased financial results as well as future impairments of our property, plant and equipment or to the retirement of certain of our facilities resulting in economic losses and liabilities.

          Because we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other power markets on a term basis, we are not guaranteed any rate of return on our capital investments. Rather, our financial condition, results of operations and cash flows are likely to depend, in large part, upon prevailing market prices for power and the fuel to generate such power. Wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable. Indeed, the trend toward construction of renewable generation is impacting transmission flows and putting downward pressure on off-peak power prices in certain regions. Continuation of this trend could further depress off-peak power prices and negatively impact our commercial activities and financial results.

          Given the volatility of power commodity prices, to the extent we do not secure term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to increased volatility, and our financial condition, results of operations and cash flows could be materially adversely affected.

We are exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies because some of our facilities do not have long-term coal, natural gas or fuel oil supply agreements.

          Many of our power generation facilities, specifically those that are natural gas-fired, purchase their fuel requirements under short-term contracts or on the spot market. As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match that required for energy sales, due in part to our need to pre-purchase fuel inventories for reliability and dispatch requirements.

          Moreover, operation of many of our coal-fired generation facilities is highly dependent on our ability to procure coal. Power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. In particular, transportation of South American coal, which we use for our Northeastern coal assets, is subject to local political and other factors that could have a negative impact on our coal deliveries. Additionally, during the second quarter 2008, upward pressure on international coal prices resulted in a foreign counterparty’s refusal to comply with the terms of an agreement to supply coal for our Danskammer facility. Permit limitations associated with the loading and unloading of coal at that facility limit our options for coal fuel supply and, when coupled with continued strong coal prices and uncertainties associated with international contracting, create continuing risk for us in terms of our ability to procure coal for periods and at prices we believe are firm and favorable. If we are unable to procure fuel for physical delivery at prices we consider favorable, or if we experience transportation delays or disruptions, our financial condition, results of operations and cash flows could be materially adversely affected.

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We have recently reported a material weakness in our internal control over financial reporting, which caused a restatement of our unaudited condensed consolidated financial statements as of and for the three months ended March 31, 2008. Additionally, we may identify material weaknesses in the future that could adversely affect investor confidence and impair the value of our common stock.

          In connection with our management’s assessments of the effectiveness of our internal control over financial reporting as of June 30, 2008, our management concluded that, as of March 31, 2008 and June 30, 2008, we did not maintain effective internal control over our financial reporting due to a material weakness in our processes, procedures and controls related to the calculation and analysis of the presentation of revenues and cost of sales related to energy trading activities on a net basis. This control deficiency has resulted in the restatement to our condensed consolidated financial statements as of and for the three months ended March 31, 2008. As further described in Item 4 “Controls and Procedures”, we believe we have taken the steps necessary to remediate this material weakness. However, the controls have not been in place for an adequate period of time to test and conclude that they are operating effectively. Accordingly, we cannot assure you that these processes, procedures and controls will result in remediation or that we will be able to maintain effective internal control over financial reporting in the future. Moreover, we have experienced from time to time deficiencies in our internal control over our financial reporting that have not risen to the level of a material weakness. Although we have been able to remediate these deficiencies in the past, we cannot assure you that a material weakness will not exist in the future, as additional deficiencies in our internal control over financial reporting may be discovered which may rise to the level of a material weakness.

          Any failure to remedy additional deficiencies in our internal control over financial reporting that may be discovered in the future or to implement new or improved controls, or difficulties encountered in the implementation of such controls, could cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Any such failure could, in turn, affect the future ability of our management to certify that our internal control over our financial reporting is effective and, moreover, affect the results of our independent registered public accounting firm’s attestation report regarding our management’s assessment. Inferior internal control over financial reporting could also subject us to the scrutiny of the SEC, the New York Stock Exchange (on which our Class A common stock is listed and traded) and other regulatory bodies and could cause investors to lose confidence in our reported financial information, which could have an adverse effect on the trading price of our common stock.

          See Item 1A—Risk Factors, of Dynegy’s and DHI’s Form 10-K for additional factors, risks and uncertainties that may affect future results.

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

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

Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share	(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April	111,287	$8.13	—	N/A
May	—	—	—	N/A
June	—	—	—	N/A
Total	111,287	$8.13	—	N/A

          These were the only repurchases of equity securities made by us during the three months ended June 30, 2008. Dynegy does not have a stock repurchase program.

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

          Our 2008 annual meeting of stockholders was held on May 14, 2008. 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 2009 annual meeting of stockholders; and
2.	To act upon a proposal to ratify the appointment of Ernst & Young LLP as our independent auditors for 2008.

          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, Howard B. Sheppard, 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	393,397,717	42,063,352
2.	Thomas D. Clark, Jr.	394,970,890	40,490,179
3.	Victor J. Grijalva	403,908,061	31,553,008
4.	Patricia A. Hammick	403,827,460	31,633,608
5.	George L. Mazanec	395,057,675	40,403,394
6.	Howard B. Sheppard	419,452,830	16,008,239
7.	William L. Trubeck	395,127,193	40,333,876
8.	Bruce A. Williamson	401,334,008	34,127,060

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Class B Directors
		FOR	WITHHELD
1.	James T. Bartlett	340,000,000	—
2.	Frank E. Hardenbergh	340,000,000	—
3.	Mikhail Segal	340,000,000	—

          The following votes were cast with respect to the proposal to ratify the selection of Ernst & Young LLP as our independent auditors for 2008, which passed. There were no broker non-votes.

FOR	AGAINST	ABSTAIN
770,509,426	1,208,071	3,743,571

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	Facility and Security Agreement, dated June 17, 2008, by and among Dynegy Holdings Inc., Morgan Stanley Capital Group Inc., as lender and as issuing bank and as collateral agent (as incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on June 18, 2008, File No. 1-33443).
**10.2	Dynegy Inc. Restoration 401(k) Savings Plan.
**10.3	First Amendment to Dynegy Inc. Restoration 401(k) Savings Plan.
**10.4	Dynegy Inc. Restoration Pension Plan.
**10.5	First Amendment to Dynegy Inc. Restoration Pension Plan.
**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.

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Exhibit Number	Description
†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.

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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: August 7, 2008	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: August 7, 2008	By:	/s/   HOLLI C. NICHOLS
		Holli C. Nichols
		Executive Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

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