Edgar Filing: DYNEGY HOLDINGS INC

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________

FORM 10-Q

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

For the quarterly period ended June 30, 2009

¨ 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 T No ¨
Dynegy Holdings Inc.	Yes T No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Dynegy Inc.	Yes ¨ No ¨
Dynegy Holdings Inc.	Yes ¨ No ¨

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 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	Smaller reporting company
			(Do not check if a smaller reporting company)

Dynegy Inc.	T	¨	¨	¨
Dynegy Holdings Inc.	¨	¨	T	¨

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

Dynegy Inc.	Yes ¨ No T
Dynegy Holdings Inc.	Yes ¨ No T

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, 504,969,128 shares outstanding as of August 3, 2009; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of August 3, 2009. All of Dynegy Holdings Inc.’s outstanding common stock is owned 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, 2009 and December 31, 2008		4
Condensed Consolidated Statements of Operations—Dynegy Inc.:
	For the three and six months ended June 30, 2009 and 2008		5
Condensed Consolidated Statements of Cash Flows—Dynegy Inc.:
	For the six months ended June 30, 2009 and 2008		6
Condensed Consolidated Statements of Comprehensive Loss—Dynegy Inc.:
	For the three and six months ended June 30, 2009 and 2008		7
Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.:
	June 30, 2009 and December 31, 2008		8
Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.:
	For the three and six months ended June 30, 2009 and 2008		9
Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.:
	For the six months ended June 30, 2009 and 2008		10
Condensed Consolidated Statements of Comprehensive Loss—Dynegy Holdings Inc.:
	For the three and six months ended June 30, 2009 and 2008		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.	48
Item 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.	80
Item 4.		CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.	81

PART II. OTHER INFORMATION

Item 1.		LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	82
Item 1A.		RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	82
Item 2.		UNREGISTERED SALES OF SECURITIES AND USE OF PROCEEDS—DYNEGY INC.	82
Item 4.		SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS—DYNEGY INC.	82
Item 6.		EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	84

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 nearly 100 percent of Dynegy’s total consolidated revenue for the six-month period ended June 30, 2009 and constituting nearly 100 percent of Dynegy’s total consolidated asset base as of June 30, 2009. 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. Discussions or areas of this report that apply only to Dynegy or DHI are clearly noted in such section.

Table of Contents

DEFINITIONS

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

ACES	The American Clean Energy and Security Act of 2009
APB	Accounting Principles Board
BTA	Best technology available
Cal ISO	The California Independent System Operator
CARB	California Air Resources Board
CCA	Coal combustion ash
CDWR	California Department of Water Resources
CEC	California Energy Commission
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
FSP	FASB Staff Position
GAAP	Generally Accepted Accounting Principles of the United States of America
GEN	Our power generation business
GEN-MW	Our power generation business - Midwest segment
GEN-NE	Our power generation business - Northeast segment
GEN-WE	Our power generation business - West segment
GHG	Greenhouse Gas
ICC	Illinois Commerce Commission
IMA	In-market asset availability
ISO	Independent System Operator
LNG	Liquefied natural gas
MISO	Midwest Independent Transmission Operator, Inc.
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt hour
NPDES	National Pollutant Discharge Elimination System
NRG	NRG Energy, Inc.
NYSDEC	New York State Department of Environmental Conservation
PJM	PJM Interconnection, LLC
PPEA	Plum Point Energy Associates, LLC
PUHCA	Public Utility Holding Company Act of 1935, as amended
RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must Run
RSG	Revenue Sufficiency Guarantee
SCEA	Sandy Creek Energy Associates, LP
SCH	Sandy Creek Holdings LLC
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SPDES	State Pollutant Discharge Elimination System
VaR	Value at Risk
VIE	Variable Interest Entity

Table of Contents

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, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	594		$	693
Restricted cash and investments		121			87
Short-term investments		2			25
Accounts receivable, net of allowance for doubtful accounts of $22 and $22, respectively		252			340
Accounts receivable, affiliates		1			1
Inventory		179			184
Assets from risk-management activities		1,414			1,263
Deferred income taxes		4			6
Prepayments and other current assets		296			204
Total Current Assets		2,863			2,803
Property, Plant and Equipment		10,892			10,869
Accumulated depreciation		(2,347	)		(1,935	)
Property, Plant and Equipment, Net		8,545			8,934
Other Assets
Unconsolidated investments		—			15
Restricted cash and investments		1,157			1,158
Assets from risk-management activities		207			114
Goodwill		—			433
Intangible assets		418			437
Accounts receivable, affiliates		7			4
Other long-term assets		343			315
Total Assets	$	13,540		$	14,213

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	191		$	303
Accrued interest		71			56
Accrued liabilities and other current liabilities		177			160
Liabilities from risk-management activities		1,164			1,119
Notes payable and current portion of long-term debt		93			64
Deferred income taxes		8			—
Total Current Liabilities		1,704			1,702
Long-term debt		5,895			5,872
Long-term debt, affiliates		200			200
Long-Term Debt		6,095			6,072
Other Liabilities
Liabilities from risk-management activities		291			288
Deferred income taxes		1,052			1,166
Other long-term liabilities		474			500
Total Liabilities		9,616			9,728
Commitments and Contingencies (Note 13)
Stockholders’ Equity
Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at June 30, 2009 and December 31, 2008; 507,423,614 and 505,821,277 shares issued and outstanding at June 30, 2009 and December 31, 2008, respectively		5			5
Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at June 30, 2009 and December 31, 2008; 340,000,000 shares issued and outstanding at June 30, 2009 and December 31, 2008		3			3
Additional paid-in capital		6,490			6,485
Subscriptions receivable		(2	)		(2	)
Accumulated other comprehensive loss, net of tax		(183	)		(215	)
Accumulated deficit		(2,370	)		(1,690	)
Treasury stock, at cost, 2,777,299 and 2,568,286 shares at June 30, 2009 and December 31, 2008, respectively		(71	)		(71	)
Total Dynegy Inc. Stockholders’ Equity		3,872			4,515
Noncontrolling interests		52			(30	)
Total Stockholders’ Equity		3,924			4,485
Total Liabilities and Stockholders’ Equity	$	13,540		$	14,213

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenues	$	493		$	322		$	1,397		$	865
Cost of sales		(285	)		(456	)		(666	)		(907	)
Operating and maintenance expense, exclusive of depreciation shown separately below		(144	)		(125	)		(266	)		(236	)
Depreciation and amortization expense		(94	)		(92	)		(186	)		(184	)
Gain on sale of assets		—			26			—			26
Goodwill impairments		—			—			(433	)		—
Impairment and other charges, exclusive of goodwill impairments shown separately above		(405	)		—			(410	)		—
General and administrative expenses		(45	)		(39	)		(83	)		(78	)

Operating loss		(480	)		(364	)		(647	)		(514	)
Earnings (losses) from unconsolidated investments		13			(3	)		21			(12	)
Interest expense		(98	)		(108	)		(196	)		(217	)
Other income and expense, net		4			15			8			35

Loss from continuing operations before income taxes		(561	)		(460	)		(814	)		(708	)
Income tax benefit (Note 15)		209			186			124			282

Loss from continuing operations		(352	)		(274	)		(690	)		(426	)
Income from discontinued operations, net of tax (expense) benefit of $(4), zero, $(4) and $1, respectively (Note 2)		6			—			7			—

Net loss		(346	)		(274	)		(683	)		(426	)
Less: Net loss attributable to the noncontrolling interests		(1	)		(2	)		(3	)		(2	)
Net loss attributable to Dynegy Inc.	$	(345	)	$	(272	)	$	(680	)	$	(424	)

Loss Per Share (Note 12):
Basic loss per share:
Loss from continuing operations attributable to Dynegy Inc.	$	(0.42	)	$	(0.32	)	$	(0.82	)	$	(0.51	)
Income from discontinued operations attributable to Dynegy Inc.		0.01			—			0.01			—

Basic loss per share attributable to Dynegy Inc.	$	(0.41	)	$	(0.32	)	$	(0.81	)	$	(0.51	)

Diluted loss per share:
Loss from continuing operations attributable to Dynegy Inc.	$	(0.42	)	$	(0.32	)	$	(0.82	)	$	(0.51	)
Income from discontinued operations attributable to Dynegy Inc.		0.01			—			0.01			—

Diluted loss per share attributable to Dynegy Inc.	$	(0.41	)	$	(0.32	)	$	(0.81	)	$	(0.51	)

Basic shares outstanding		842			840			842			839
Diluted shares outstanding		844			842			843			841

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(683	)	$	(426	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization		189			188
Goodwill impairments		433			—
Impairment and other charges, exclusive of goodwill impairments shown separately above		410			—
(Earnings) losses from unconsolidated investments, net of cash distributions		(21	)		12
Risk-management activities		(65	)		760
Gain on sale of assets		(10	)		(26	)
Deferred income taxes		(129	)		(281	)
Other		43			2
Changes in working capital:
Accounts receivable		35			(77	)
Inventory		(9	)		23
Prepayments and other assets		(88	)		(178	)
Accounts payable and accrued liabilities		(13	)		61
Changes in non-current assets		(38	)		(35	)
Changes in non-current liabilities		6			9

Net cash provided by operating activities		60			32

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(303	)		(299	)
Unconsolidated investments		1			(1	)
Proceeds from asset sales, net		105			84
Decrease in short-term investments		14			—
Decrease (increase) in restricted cash and restricted investments		(33	)		28
Other investing		3			11

Net cash used in investing activities		(213	)		(177	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		54			111
Repayments of long-term borrowings, net		—			(21	)
Proceeds from issuance of capital stock		—			2
Other financing, net		—			(4	)

Net cash provided by financing activities		54			88

Net decrease in cash and cash equivalents		(99	)		(57	)
Cash and cash equivalents, beginning of period		693			328

Cash and cash equivalents, end of period	$	594		$	271

Other non-cash investing activity:
Non-cash capital expenditures	$	42		$	34

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)

	Three Months Ended June 30,
	2009			2008

Net loss	$	(346	)	$	(274	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net		81			20
Reclassification of mark-to-market losses to earnings, net		—			(1	)
Deferred losses on cash flow hedges, net		(3	)		(2	)

Changes in cash flow hedging activities, net (net of tax expense of $7 and $5, respectively)		78			17
Amortization of unrecognized prior service cost and actuarial loss (net of tax benefit of $2 and zero)		3			1
Net unrealized loss on securities, net (net of tax benefit of zero and $5, respectively)		—			(8	)
Unconsolidated investments other comprehensive income (loss), net (net of tax (expense) benefit of $(2) and $4)		5			(7	)

Other comprehensive income, net of tax		86			3

Comprehensive loss		(260	)		(271	)
Less: Comprehensive income attributable to the noncontrolling interests		56			7

Comprehensive loss attributable to Dynegy Inc.	$	(316	)	$	(278	)

	Six Months Ended June 30,
	2009			2008

Net loss	$	(683	)	$	(426	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		115			(6	)
Reclassification of mark-to-market gains to earnings, net		—			7
Deferred losses on cash flow hedges, net		(6	)		(2	)

Changes in cash flow hedging activities, net (net of tax expense of $(16) and zero, respectively)		109			(1	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $1 and zero)		2			1
Net unrealized loss on securities, net (net of tax benefit of zero and $8, respectively)		—			(12	)
Unconsolidated investments other comprehensive income (loss), net (net of tax (expense) benefit of $(4) and $4)		6			(7	)

Other comprehensive income (loss), net of tax		117			(19	)

Comprehensive loss		(566	)		(445	)
Less: Comprehensive income (loss) attributable to the noncontrolling interests		82			(4	)

Comprehensive loss attributable to Dynegy Inc.	$	(648	)	$	(441	)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEET

(unaudited) (in millions)

	June 30, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	411		$	670
Restricted cash and investments		121			87
Short-term investments		2			24
Accounts receivable, net of allowance for doubtful accounts of $20 and $20, respectively		254			343
Accounts receivable, affiliates		1			1
Inventory		179			184
Assets from risk-management activities		1,414			1,263
Deferred income taxes		4			4
Prepayments and other current assets		296			204
Total Current Assets		2,682			2,780
Property, Plant and Equipment		10,892			10,869
Accumulated depreciation		(2,347	)		(1,935	)
Property, Plant and Equipment, Net		8,545			8,934
Other Assets
Restricted cash and investments		1,157			1,158
Assets from risk-management activities		207			114
Goodwill		—			433
Intangible assets		418			437
Accounts receivable, affiliates		7			4
Other long-term assets		342			314
Total Assets	$	13,358		$	14,174

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	191		$	284
Accrued interest		71			56
Accrued liabilities and other current liabilities		174			157
Liabilities from risk-management activities		1,164			1,119
Notes payable and current portion of long-term debt		93			64
Deferred income taxes		10			1
Total Current Liabilities		1,703			1,681
Long-term debt		5,895			5,872
Long-term debt, affiliates		200			200
Long-Term Debt		6,095			6,072
Other Liabilities
Liabilities from risk-management activities		291			288
Deferred income taxes		906			1,052
Other long-term liabilities		475			498
Total Liabilities		9,470			9,591
Commitments and Contingencies (Note 13)
Stockholders’ Equity
Capital Stock, $1 par value, 1,000 shares authorized at June 30, 2009 and December 31, 2008		—			—
Additional paid-in capital		5,545			5,684
Affiliate receivable		(827	)		(827	)
Accumulated other comprehensive loss, net of tax		(183	)		(215	)
Accumulated deficit		(699	)		(29	)
Total Dynegy Holdings Inc. Stockholder’s Equity		3,836			4,613
Noncontrolling interests		52			(30	)
Total Stockholders’ Equity		3,888			4,583
Total Liabilities and Stockholders’ Equity	$	13,358		$	14,174

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenues	$	493		$	322		$	1,397		$	865
Cost of sales		(285	)		(456	)		(666	)		(907	)
Operating and maintenance expense, exclusive of depreciation shown separately below		(144	)		(125	)		(268	)		(236	)
Depreciation and amortization expense		(94	)		(92	)		(186	)		(184	)
Gain on sale of assets		—			26			—			26
Goodwill impairments		—			—			(433	)		—
Impairment and other charges, exclusive of goodwill impairments shown separately above		(405	)		—			(410	)		—
General and administrative expenses		(45	)		(39	)		(83	)		(78	)

Operating loss		(480	)		(364	)		(649	)		(514	)
Earnings (losses) from unconsolidated investments		13			3			20			(2	)
Interest expense		(98	)		(108	)		(196	)		(217	)
Other income and expense, net		3			14			7			34

Loss from continuing operations before income taxes		(562	)		(455	)		(818	)		(699	)
Income tax benefit (Note 15)		220			184			138			275

Loss from continuing operations		(342	)		(271	)		(680	)		(424	)
Income from discontinued operations, net of tax (expense) benefit of ($4), zero, ($4) and $1, respectively (Note 2)		6			—			7			—

Net loss		(336	)		(271	)		(673	)		(424	)
Less: Net loss attributable to the noncontrolling interests		(1	)		(2	)		(3	)		(2	)
Net loss attributable to Dynegy Holdings Inc.	$	(335	)	$	(269	)	$	(670	)	$	(422	)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Six Months Ended June 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(673	)	$	(424	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization		189			188
Goodwill impairments		433			—
Impairment and other charges, exclusive of goodwill impairments shown separately above		410			—
(Earnings) losses from unconsolidated investments, net of cash distributions		(20	)		2
Risk-management activities		(65	)		760
Gain on sale of assets, net		(10	)		(26	)
Deferred income taxes		(139	)		(273	)
Other		43			—
Changes in working capital:
Accounts receivable		35			(78	)
Inventory		(9	)		23
Prepayments and other assets		(88	)		(178	)
Accounts payable and accrued liabilities		5			61
Changes in non-current assets		(38	)		(35	)
Changes in non-current liabilities		7			9

Net cash provided by operating activities		80			29

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(303	)		(299	)
Unconsolidated investments		—			10
Proceeds from asset sales, net		105			84
Decrease in short-term investments		13			—
Decrease (increase) in restricted cash and restricted investments		(33	)		28
Affiliate transactions		(3	)		1
Other investing		3			7

Net cash used in investing activities		(218	)		(169	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		54			111
Repayments to long-term borrowings		—			(21	)
Dividend to affiliate		(175	)		—
Other financing, net		—			(4	)

Net cash provided by (used in) financing activities		(121	)		86

Net decrease in cash and cash equivalents		(259	)		(54	)
Cash and cash equivalents, beginning of period		670			292

Cash and cash equivalents, end of period	$	411		$	238

Other non-cash investing activity:
Non-cash capital expenditures	$	42		$	34

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)

	Three Months Ended June 30,
	2009			2008

Net loss	$	(336	)	$	(271	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains arising during period, net		81			20
Reclassification of mark-to-market losses to earnings, net		—			(1	)
Deferred losses on cash flow hedges, net		(3	)		(2	)

Changes in cash flow hedging activities, net (net of tax expense of $7 and $5, respectively)		78			17
Amortization of unrecognized prior service cost and actuarial loss (net of tax benefit of $2 and zero)		3			1
Net unrealized loss on securities, net (net of tax benefit of zero and $5, respectively)		—			(8	)
Unconsolidated investments other comprehensive income (loss), net (net of tax (expense) benefit of $(2) and $4)		5			(7	)

Other comprehensive income, net of tax		86			3

Comprehensive loss		(250	)		(268	)
Less: Comprehensive income attributable to the noncontrolling interests		56			7
Comprehensive loss attributable to Dynegy Holdings Inc.	$	(306	)	$	(275	)

	Six Months Ended June 30,
	2009			2008

Net loss	$	(673	)	$	(424	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		115			(6	)
Reclassification of mark-to-market gains to earnings, net		—			7
Deferred losses on cash flow hedges, net		(6	)		(2	)

Changes in cash flow hedging activities, net (net of tax (expense) benefit of $(16) and zero, respectively)		109			(1	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $1 and zero)		2			1
Net unrealized loss on securities, net (net of tax benefit of zero and $8, respectively)		—			(12	)
Unconsolidated investments other comprehensive income (loss), net (net of tax (expense) benefit of $(4) and $4)		6			(7	)

Other comprehensive income (loss), net of tax		117			(19	)

Comprehensive loss		(556	)		(443	)
Less: Comprehensive income (loss) attributable to the noncontrolling interests		82			(4	)
Comprehensive loss attributable to Dynegy Holdings Inc.	$	(638	)	$	(439	)

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, 2009 and 2008

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, as adjusted for the adoption of SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”) as discussed below. These interim financial statements do 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, 2008 filed on February 26, 2009, 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. 141(R). On January 1, 2009, we adopted 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 of the financial statements all the information they need to evaluate and understand the nature and financial effect of the business combination. The adoption of this statement had no impact on our financial statements.

SFAS No. 157. On January 1, 2009, we adopted SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”) for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis, which had been deferred under FSP SFAS No. 157-2. Please read Note 5—Fair Value Measurements for further discussion.

SFAS No. 160. On January 1, 2009, we adopted SFAS No. 160. Please read Note 3—Noncontrolling Interests for further discussion.

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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, 2009 and 2008

SFAS No. 161. On January 1, 2009, we adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (“SFAS No. 161”). Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

SFAS No. 165. On June 30, 2009, we adopted SFAS No. 165, “Subsequent Events” (“SFAS No. 165”). SFAS No. 165 provides guidance on management’s assessment of subsequent events. We have evaluated subsequent events through August 10, 2009, the date our financial statements were issued and up to the time of the filing of our financial statements with the SEC. SFAS No. 165 is effective for interim or annual financial periods ending after June 15, 2009.

EITF Issue 08-5. On January 1, 2009, we adopted EITF Issue 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third Party Credit Enhancement” (“EITF Issue No. 08-5”). Please read Note 5—Fair Value Measurements for further discussion.

FSP SFAS 107-1. On June 30, 2009, we adopted FSP SFAS 107-1 and APB 28-1, “Disclosures about Fair Value of Financial Instruments” (“FSP 107-1 and APB 28-1”). Please read Note 5—Fair Value Measurements for further discussion.

FSP SFAS 157-4. On June 30, 2009, we adopted FSP SFAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP 157-4”). Please read Note 5—Fair Value Measurements for further discussion.

Accounting Principle Not Yet Adopted

FSP SFAS 132(R)-1. FSP SFAS 132(R)-1 amends SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. The objectives of the disclosures about plan assets in an employer’s defined benefit pension or other postretirement plan are to provide users of financial statements with an understanding of: (i) how investment allocation decisions are made, including the factors that are pertinent to an understanding of investment policies and strategies; (ii) the major categories of plan assets; (iii) the inputs and valuation techniques used to measure the fair value of plan assets; (iv) the effect of fair value measurements using significant unobservable inputs (Level 3) on changes in plan assets for the period and (v) significant concentrations of risk within plan assets. The disclosures about plan assets required by this FSP are to be provided for fiscal years ending after December 15, 2009. We are currently evaluating the disclosure implications of this standard; however, this statement will have no impact on our financial condition, results of operations or cash flows.

SFAS No. 167. On June 12, 2009, the FASB issued SFAS No. 167, “Amendments to FIN 46(R)” (“SFAS No. 167”), which amends the consolidation guidance that applies to variable interest entities. The FASB’s objective in issuing this statement is to improve financial reporting by enterprises involved with variable interest entities. The FASB undertook this project to address (i) the effects on certain provisions of FASB Interpretation No. 46, as a result of the elimination of the qualifying special-purpose entity concept in FASB Statement No. 166, “Accounting for Transfers of Financial Assets”, and (ii) constituent concerns about the application of certain key provisions of Interpretation 46(R), including those in which the accounting and disclosures under the Interpretation do not always provide timely and useful information about an enterprise’s involvement in a variable interest entity. This statement is effective for fiscal years beginning after November 15, 2009. We are currently evaluating the impact of this standard on our consolidated financial statements.

SFAS No. 168. On June 29, 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles - a replacement of FASB Statement No. 162” (“SFAS No. 168”). SFAS No. 168 will become the source of authoritative U.S. GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of this Statement, the Codification will supersede all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification will become non-authoritative. This statement is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We anticipate this statement will have no impact on our financial condition, results of operations or cash flows.

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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, 2009 and 2008

Note 2—Dispositions and Discontinued Operations

Dispositions

LS Power Transaction. On August 9, 2009, we entered into a purchase and sale agreement with LS Power Partners, L.P. and certain of its affiliates (collectively, “LS Power”) pursuant to which we agreed to (i) sell to LS Power our interests in: Dynegy Arlington Valley, LLC; Griffith Energy LLC; Bridgeport Energy LLC; Rocky Road Power, LLC; Tilton Energy LLC; Riverside Generating Company, L.L.C.; Bluegrass Generation Company, L.L.C.; Renaissance Power, L.L.C.; Sandy Creek Services, LLC; and Dynegy Sandy Creek Holdings, LLC, and (ii) issue to LS Power $235 million aggregate principal amount of DHI 7.50 percent senior unsecured notes due 2015. In exchange for the ownership interests and notes, we will receive (i) $1.025 billion in cash (consisting, in part, of $175 million of restricted cash on our unaudited condensed consolidated balance sheets to be released to Dynegy from the Sandy Creek restricted account) and (ii) 245 million shares of Dynegy’s Class B common stock (currently held by LS Power), with the remaining 95 million shares of Dynegy’s Class B common stock held by LS Power to be converted at closing to an equivalent number of shares of Dynegy’s Class A common stock. Concurrent with the execution of the purchase and sale agreement, LS Power and Dynegy entered into a new Shareholder Agreement, which upon closing of the transaction, will eliminate special approval rights, board representation and certain other rights associated with the former Class B common shares and limit the acquisition and transfer of Dynegy’s common stock held by LS Power. This agreement provides that we have agreed not to issue Dynegy’s equity securities for our own purposes until the earlier of (i) 121 days following the closing of the transaction with LS Power and (ii) the first date following closing of the transaction in which LS Power owns, in aggregate, less than 10 percent of Dynegy’s then outstanding Class A common stock. The parties have made customary representations and warranties and the completion of the transaction is conditioned upon obtaining certain regulatory approvals and the expiration or termination of the Hart-Scott-Rodino waiting period. The agreement also includes other customary closing conditions, including the lack of a material adverse effect and contains customary termination rights by both parties. Assuming all necessary conditions are satisfied, the sale is expected to close in the second half of 2009.

In connection with discussions leading to the agreement with LS Power, we determined it was more likely than not that certain assets would be sold prior to the end of their previously estimated useful lives. Therefore, we updated our March 31, 2009 impairment analysis for each of the asset groups that we were considering for sale as part of the transaction with LS Power. As a result of this evaluation, we recorded pre-tax impairment charges of $197 million during the second quarter 2009, which are included in Impairment and other charges in our unaudited condensed consolidated statements of operations. The asset groups included in this transaction do not meet the criteria of held for sale at June 30, 2009. Based on the fair value at June 30, 2009 of the consideration to be received from LS Power as now reflected in the definitive transaction documents, we expect to record further pre-tax impairment charges of approximately $355 million in the third quarter 2009 upon the asset groups meeting the criteria of held for sale, as well as a net loss on sale of assets of approximately $130 million upon closing of the transaction, based on our stock price and the value of our investment in Sandy Creek at June 30, 2009. However, the estimates of the total impairment charges and loss on sale could change materially based on changes in the fair value of the shares of Class B common stock that is part of the consideration to be received from LS Power transaction. Please read Note 6—Impairment Charges for further discussion of these impairments.

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 partially offset by a reduction of $8 million, net of tax of $5 million, in our unaudited condensed consolidated statements of other comprehensive loss.

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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, 2009 and 2008

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

Discontinued Operations

Heard County. On April 30, 2009, we completed the sale of our interest in the Heard County power generation facility for approximately $105 million. We recorded a $10 million pre-tax gain during the second quarter 2009 related to the sale, which is included in Income from discontinued operations on our unaudited condensed consolidated statements of operations.

Heard County was classified as held for sale during the first quarter 2009. At that time, we discontinued depreciation and amortization of Heard County’s property, plant and equipment. Depreciation and amortization expense related to Heard County totaled approximately zero and $1 million in the three- and six-month periods ended June 30, 2009, respectively, compared to approximately $1 million and $2 million in the three- and six-month periods ended June 30, 2008, respectively. We are reporting the results of Heard County’s operations in discontinued operations for all periods presented.

Calcasieu. On March 31, 2008, we completed the sale of the Calcasieu power generation facility for approximately $56 million, net of transaction costs.

Calcasieu was classified as held for sale during the first quarter 2007. At that time, we discontinued depreciation and amortization of Calcasieu’s property, plant and equipment. Depreciation and amortization expense related to Calcasieu totaled zero in the three- and six-month periods ended June 30, 2008. We are reporting the results of Calcasieu’s operations in discontinued operations for the three-month period ended March 31, 2008.

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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, 2009 and 2008

Summary. The following table summarizes information related to both Dynegy’s and DHI’s discontinued operations (all of which are included in our GEN-WE segment)

	Heard County		Calcasieu			Total
	(in millions)
Three Months Ended June 30, 2009
Gain on sale before taxes	$	10	$	—		$	10
Gain on sale after taxes		6		—			6

Three Months Ended June 30, 2008
Revenues	$	1	$	—		$	1

Six Months Ended June 30, 2009
Revenues	$	2	$	—		$	2
Income from operations before taxes		1		—			1
Income from operations after taxes		1		—			1
Gain on sale before taxes		10		—			10
Gain on sale after taxes		6		—			6
Six Months Ended June 30, 2008 Revenues	$	3	$	—		$	3
Loss on sale before taxes		—		(1	)		(1	)
Loss on sale after taxes		—		—			—

Note 3—Noncontrolling Interests

On January 1, 2009, we adopted SFAS No. 160, which requires: (i) ownership interests in subsidiaries held by parties other than the parent to be clearly identified, labeled, and presented in the consolidated statements of financial position within equity, but separate from the parent’s equity; (ii) the amount of consolidated net income (loss) attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statements of operations; (iii) changes in a parent’s ownership interests that do not result in deconsolidation to be accounted for as equity transactions; and (iv) that a parent recognize a gain or loss in net income upon deconsolidation of a subsidiary, with any retained noncontrolling equity investment in the former subsidiary initially measured at fair value. The following table presents the net loss attributable to Dynegy’s and DHI’s stockholders:

	Dynegy Inc.						Dynegy Holdings Inc.
	Three Months Ended June 30,						Three Months Ended June 30,
	2009			2008			2009			2008
	(in millions)
Loss from continuing operations	$	(351	)	$	(272	)	$	(341	)	$	(269	)
Income from discontinued operations, net of tax expense of $4, zero, $4 and zero, respectively		6			—			6			—

Net loss	$	(345	)	$	(272	)	$	(335	)	$	(269	)

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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, 2009 and 2008

	Dynegy Inc.						Dynegy Holdings Inc.
	Six Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions)
Loss from continuing operations	$	(687	)	$	(424	)	$	(677	)	$	(422	)
Income from discontinued operations, net of tax benefit (expense) of ($4), $1, ($4) and $1, respectively		7			—			7			—

Net loss	$	(680	)	$	(424	)	$	(670	)	$	(422	)

The following table presents a reconciliation of the carrying amount of total equity, equity attributable to Dynegy and the equity attributable to the noncontrolling interests at the beginning and the end of the six months ended June 30, 2009:

	Controlling Interest			Noncontrolling Interests			Total
	(in millions)
December 31, 2008	$	4,515		$	(30	)	$	4,485
Net loss		(680	)		(3	)		(683	)
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market gains arising during period		25			90			115
Reclassification of mark-to-market gains (losses) to earnings		(2	)		2			—
Deferred gains (losses) on cash flow hedges		1			(7	)		(6	)
Amortization of unrecognized prior service cost and actuarial loss		2			—			2
Unconsolidated investments other comprehensive income		6			—			6
Total other comprehensive income, net of tax		32			85			117
Other equity activity:
Options exercised		(1	)		—			(1	)
Options and restricted stock granted		5			—			5
401(k) plan and profit sharing stock		3			—			3
Board of directors stock compensation		(2	)		—			(2	)

June 30, 2009	$	3,872		$	52		$	3,924

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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, 2009 and 2008

	Controlling Interest			Noncontrolling Interests			Total
	(in millions)
December 31, 2007	$	4,506		$	23		$	4,529
Net loss		(424	)		(2	)		(426	)
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market losses arising during period		(6	)		—			(6	)
Reclassification of mark-to-market gains (losses) to earnings		8			(1	)		7
Deferred losses on cash flow hedges		(1	)		(1	)		(2	)
Amortization of unrecognized prior service cost and actuarial loss		1			—			1
Unconsolidated investments other comprehensive loss		(7	)		—			(7	)
Net unrealized loss on securities		(12	)		—			(12	)
Total other comprehensive loss, net of tax		(17	)		(2	)		(19	)
Other equity activity:
Subscriptions receivable		2			—			2
Options exercised		1			—			1
401(k) plan and profit sharing stock		3			—			3
Options and restricted stock granted		9			—			9

June 30, 2008	$	4,080		$	19		$	4,099

The following table presents a reconciliation of the carrying amount of total equity, equity attributable to DHI and the equity attributable to the noncontrolling interests at the beginning and the end of the of the six months ended June 30, 2009.

	Controlling Interest			Noncontrolling Interests			Total
	(in millions)
December 31, 2008	$	4,613		$	(30	)	$	4,583
Net loss		(670	)		(3	)		(673	)
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market gains arising during period		25			90			115
Reclassification of mark-to-market gains (losses) to earnings		(2	)		2			—
Deferred gains (losses) on cash flow hedges		1			(7	)		(6	)
Amortization of unrecognized prior service cost and actuarial loss		2			—			2
Unconsolidated investments other comprehensive income		6			—			6
Total other comprehensive income, net of tax		32			85			117
Other equity activity:
Dividend to Dynegy		(175	)		—			(175	)
Contribution from Dynegy		36			—			36

June 30, 2009	$	3,836		$	52		$	3,888

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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, 2009 and 2008

	Controlling Interest			Noncontrolling Interests			Total
	(in millions)
December 31, 2007	$	4,597		$	23		$	4,620
Net loss		(422	)		(2	)		(424	)
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market losses arising during period		(6	)		—			(6	)
Reclassification of mark-to-market gains (losses) to earnings		8			(1	)		7
Deferred losses on cash flow hedges		(1	)		(1	)		(2	)
Amortization of unrecognized prior service cost and actuarial loss		1			—			1
Unconsolidated investments other comprehensive loss		(7	)		—			(7	)
Net unrealized loss on securities		(12	)		—			(12	)
Total other comprehensive loss, net of tax		(17	)		(2	)		(19	)
Other equity activity:
Affiliate activity		10			—			10

June 30, 2008	$	4,168		$	19		$	4,187

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 seeks to manage these commodity price risks with financially settled and other types of contracts consistent with our commodity risk management policy. Our treasury team seeks to manage our financial risks and exposures associated with interest expense variability.

Our commodity risk management strategy gives us the flexibility to sell energy and capacity through a combination of spot market sales and near-term contractual arrangements (generally over a rolling 12 to 36 month time frame). Our commodity risk management goal is to increase predictability of cash flows in the near-term while keeping the ability to capture value from rising commodity prices over the longer term. Many of our contractual arrangements are derivative instruments and must be accounted for at fair value. We also manage commodity price risk by entering into capacity forward sales arrangements, tolling arrangements, RMR contracts, fixed price coal purchases and other arrangements that do not receive fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase normal sales.” As a result, the gains and losses with respect to these arrangements are not reflected in the unaudited condensed consolidated statements of operations until the settlement dates.

Quantitative Disclosures Related to Financial Instruments and Derivatives

On January 1, 2009, we adopted SFAS No. 161, which 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.

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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, 2009 and 2008

The following disclosures and tables present information concerning the impact of derivative instruments on our unaudited condensed consolidated balance sheets and statements of operations. In the table below, commodity contracts primarily consist of derivative contracts related to our power generation business that we have not designated as accounting hedges, that are entered into for purposes of economically hedging future fuel requirements and sales commitments and securing commodity prices. Interest rate contracts primarily consist of derivative contracts related to managing our interest rate risk. As of June 30, 2009, our commodity derivatives were comprised of both long and short positions; a long position is a contract to purchase a commodity, while a short position is a contract to sell a commodity. As of June 30, 2009, we had net long/(short) commodity derivative contracts outstanding and notional interest rate swaps outstanding in the following quantities:

Contract Type	Hedge Designation	Quantity			Unit of Measure	Net Fair Value
		(in millions)				(in millions)
Commodity derivative contracts:
Electric energy (1)	Not designated		(75	)	MW	$	281
Natural gas (1)	Not designated		264		MMBtu	$	(9	)
Other (2)	Not designated		2		Misc.	$	—

Interest rate contracts:
Interest rate swaps	Cash flow hedge		(511	)	Dollars	$	(106	)
Interest rate swaps	Fair value hedge		(25	)	Dollars	$	2
Interest rate swaps	Not designated		231		Dollars	$	(18	)
Interest rate swaps	Not designated		(206	)	Dollars	$	16

____________________________

(1)

Mainly comprised of swaps, options and physical forwards.

(2)

Comprised of emissions, coal, crude oil, and fuel oil options, swaps and physical forwards.

Derivatives on the Balance Sheet. The following table presents the fair value and balance sheet classification of derivatives in the unaudited condensed consolidated balance sheet as of June 30, 2009, segregated between designated, qualifying hedging instruments and those that are not, and by type of contract segregated by assets and liabilities. 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 that allow an entity to offset the fair value amounts 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 unaudited condensed consolidated balance sheets present derivative assets and liabilities, as well as cash collateral paid or received, on a gross basis. As of June 30, 2009, included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets, we had approximately $166 million of cash collateral postings, which represent the effect of net cash outflows arising from daily settlements of our exchange-traded or brokered commodity futures positions held with our futures clearing manager. In addition, as of June 30, 2009, included in Accrued liabilities and other current liabilities on our unaudited condensed consolidated balance sheets, we had approximately $45 million of cash collateral receipts, which represent the effect of net cash inflows to collateralize mark-to-market values of various positions.

Contract Type	Balance Sheet Location	June 30, 2009			December 31, 2008
		(in millions)
Derivatives designated as hedging instruments:
Derivative Assets:
Interest rate contracts	Assets from risk management activities	$	2		$	3
Derivative Liabilities:
Interest rate contracts	Liabilities from risk management activities		(106	)		(238	)

Total derivatives designated as hedging instruments, net			(104	)		(235	)

Derivatives not designated as hedging instruments:
Derivative Assets:
Commodity contracts	Assets from risk management activities		1,603			1,355
Interest rate contracts	Assets from risk management activities		16			19
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities		(1,331	)		(1,147	)
Interest rate contracts	Liabilities from risk management activities		(18	)		(22	)

Total derivatives not designated as hedging instruments, net			270			205

Total derivatives, net		$	166		$	(30	)

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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, 2009 and 2008

Impact of Derivatives on the Consolidated Statements of Operations

The following discussion and tables present the disclosure of the location and amount of gains and losses on derivative instruments in our unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2009 and 2008 segregated between designated, qualifying hedging instruments and those that are not, by type of contract.

Cash Flow Hedges. We enter into financial derivative instruments that qualify, and that we may elect to designate, as cash flow hedges. Interest rate swaps have been used to convert floating interest rate obligations to fixed interest rate obligations.

In the second quarter 2007, one of our consolidated subsidiaries, PPEA, entered into three interest rate swap agreements with an initial aggregate notional amount of approximately $183 million. These interest rate swap agreements convert certain of PPEA’s floating rate debt exposure to a fixed interest rate of approximately 5.3 percent. The aggregate notional amount of the swaps at June 30, 2009 was approximately $511 million. These interest rate swap agreements expire in June 2040. Effective July 1, 2007, we designated these agreements as cash flow hedges. Therefore, the effective portion of the changes in value after that date are reflected in other comprehensive income (loss), and subsequently reclassified to interest expense contemporaneously with the related accruals of interest expense, or depreciation expense in the event the interest was capitalized, in either case to the extent of hedge effectiveness.

During the three and six months ended June 30, 2009, we recorded no income and for the three and six months ended June 30, 2008, we recorded no income and $2 million, respectively, related to ineffectiveness from changes in fair value of derivative positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in either of the periods. During the three and six months ended June 30, 2009 and 2008, 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 within Accumulated other comprehensive income (loss), net at June 30, 2009 is expected to be reclassified to future earnings when the forecasted hedged transaction impacts earnings. Because a significant majority of the interest expense incurred by PPEA is capitalized, a significant portion of the current and future derivative settlements will continue to be deferred in Accumulated other comprehensive income (loss) and will be reclassified to depreciation expense over the expected life of the plant once the Plum Point Project commences operations. Because not all of the interest expense is capitalized, of this amount, after-tax losses of approximately $1 million are currently estimated to be reclassified into earnings over the 12-month period ending June 30, 2010. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market prices, hedging strategies, the probability of forecasted transactions occurring and other factors.

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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, 2009 and 2008

The impact of interest rate swap contracts designated as cash flow hedges and the related hedged item on our unaudited condensed consolidated statements of operations for the three months ended June 30, 2009 and 2008 is presented below:

Derivatives in SFAS No. 133 Cash Flow Hedging	Amount of Gain Recognized in OCI on Derivatives (Effective Portion) For the Three Months Ended June 30,				Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income (Effective Portion) For the Three Months Ended June 30,
Relationships	2009		2008		(Effective Portion)	2009		2008
	(in millions)					(in millions)
Interest rate contracts	$	81	$	20	Interest expense	$	—	$	2

Total	$	81	$	20		$	—	$	2

The impact of interest rate swap contracts designated as cash flow hedges and the related hedged item on our unaudited condensed consolidated statements of operations for the six months ended June 30, 2009 and 2008 is presented below:

Derivatives in SFAS No. 133 Cash Flow Hedging	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) For the Six Months Ended June 30,					Location of Gain (Loss) Reclassified from Accumulated OCI into Income	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) For the Six Months Ended June 30,
Relationships	2009		2008			(Effective Portion)	2009		2008
	(in millions)						(in millions)
Interest rate contracts	$	115	$	(6	)	Interest expense	$	—	$	2
Commodity contracts(1)		—		—		Revenues		—		(10	)
Total	$	115	$	(6	)		$	—	$	(8	)

__________

(1)

Beginning April 2, 2007, we chose to cease designating derivatives related to our power generation business as hedges. These amounts represent reclassifications into earnings of amounts that were previously frozen in Accumulated other comprehensive loss upon de-designation in April 2007.

Fair Value Hedges. We also enter into derivative instruments that qualify, and that we may elect to 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. The maximum length of time for which we have hedged our exposure for fair value hedges is through 2012. During the three and six months ended June 30, 2009 and 2008, 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 three and six months ended June 30, 2009 and 2008, there were no gains or losses related to the recognition of firm commitments that no longer qualified as fair value hedges.

The impact of interest rate swap contracts designated as fair value hedges and the related hedged item on our unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2009 and 2008 was immaterial.

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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, 2009 and 2008

Financial Instruments Not Designated as Hedges. We elect not to designate derivatives related to our power generation business and certain interest rate instruments as cash flow or fair value hedges. Thus, we apply mark-to-market accounting treatment to these derivatives. As a result, 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 activity for which the derivative instruments serve as economic hedges.

For the three-month period ended June 30, 2009, our revenues included approximately $104 million of mark-to-market losses related to this activity compared to $481 million of mark-to-market losses in the same period in the prior year. For the six-month period ended June 30, 2009, our revenues included approximately $64 million of mark-to-market gains related to this activity compared to $760 million of mark-to-market losses in the same period in the prior year.

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the three months ended June 30, 2009 and 2008 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we expect to realize when the underlying physical transactions settle.

Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in Income on	Amount of All Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended June 30,
Instruments under SFAS No. 133	Derivatives	2009		2008
		(in millions)
Commodity contracts	Revenues	$	32	$	(501	)
Interest rate contracts	Interest expense		—		1

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the six months ended June 30, 2009 and 2008 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we expect to realize when the underlying physical transactions settle.

Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in Income on	Amount of All Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended June 30,
Instruments under SFAS No. 133	Derivatives	2009		2008
		(in millions)
Commodity contracts	Revenues	$	299	$	(781	)
Interest rate contracts	Interest expense		—		—

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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, 2009 and 2008

Note 5—Fair Value Measurements

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, 2009. 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, 2009
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Assets from commodity risk management activities	$	—	$	1,525	$	78	$	1,603
Assets from interest rate swaps		—		18		—		18
Other (1)		—		11		—		11

Total	$	—	$	1,554	$	78	$	1,632

Liabilities:
Liabilities from commodity risk management activities	$	—	$	1,296	$	35	$	1,331
Liabilities from interest rate swaps		—		124		—		124

Total	$	—	$	1,420	$	35	$	1,455

______________

(1)

Other represents short-term investments and long-term investments.

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, 2009
	(in millions)
Balance at March 31, 2009	$	33
Realized and unrealized gains, net		28
Purchases, issuances and settlements		(18	)
Transfer to Level 3		—

Balance at June 30, 2009	$	43

Unrealized gains relating to instruments still held as of June 30, 2009	$	24

	Six Months Ended June 30, 2009
	(in millions)
Balance at December 31, 2008	$	60
Realized and unrealized gains, net		23
Purchases, issuances and settlements		(40	)
Transfer to Level 3		—

Balance at June 30, 2009	$	43

Unrealized gains relating to instruments still held as of June 30, 2009	$	18

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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, 2009 and 2008

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 generally serve as economic hedges of our power 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.

On January 1, 2009, we adopted EITF Issue No. 08-5, which applies to liabilities issued with an inseparable third-party credit enhancement when they are measured or disclosed at fair value on a recurring basis. The underlying principle in the consensus in EITF Issue No. 08-5 is that a third-party credit enhancement does not relieve the issuer of its ultimate obligation under the liability. We had approximately $166 million of cash collateral postings as of June 30, 2009 included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets, which represents 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. In addition, we had approximately $1,024 million of letters of credit issued as of June 30, 2009. Substantially all of our derivative positions with our derivative counterparties are supported by letters of credit issued pursuant to our Fifth Amended and Restated Credit Facility (the “Credit Facility”) or by cash collateral postings. As a result of the consensus in EITF Issue No. 08-5, we no longer can consider the letters of credit as credit enhancements in our valuation of our derivative liabilities beginning in 2009. Based on our net risk management asset position as of January 1, 2009 and June 30, 2009, our adoption of EITF Issue No. 08-5 did not result in a material effect on our unaudited condensed consolidated financial statements for the three- or six-month periods ended June 30, 2009.

On January 1, 2009, we adopted SFAS No. 157 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis, which had been deferred under FSP SFAS No. 157-2. The following table sets forth by level within the fair value hierarchy our fair value measurements with respect to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis as of June 30, 2009. These 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 Measurements as of June 30, 2009
	Level 1		Level 2		Level 3		Total		Total Losses
	(in millions)
Assets:
Goodwill	$	—	$	—	$	—	$	—	$	(433	)
Assets held and used		—		—		228		228		(410	)

Total	$	—	$	—	$	228	$	228	$	(843	)

During the first quarter 2009, goodwill with a carrying amount of $433 million was written down to its implied fair value of zero, resulting in an impairment charge of $433 million, which is included in Goodwill impairment on our unaudited condensed consolidated statements of operations. Please read Note 9—Goodwill for further discussion and disclosures addressing the description of the inputs and information used to develop the inputs as well as the valuation techniques used to measure the goodwill impairment.

During the first half 2009, long-lived assets held and used with a carrying amount of $638 million were written down to their fair value of $228 million, resulting in an impairment charge of $410 million, which is included in Impairment and other charges on our unaudited condensed consolidated statements of operations. Please read Note 6—Impairment Charges for further discussion.

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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, 2009 and 2008

On June 30, 2009, we adopted FSP SFAS 157-4, which provides guidance on (i) estimating the fair value of an asset or liability when the volume and level of activity for the asset or liability have significantly decreased and (ii) identifying transactions that are not orderly. The adoption of FSP SFAS 157-4 had no impact on our financial statements.

Fair Value of Financial Instruments. On June 30, 2009, we adopted FSP FAS 107-1 and APB 28-1, which requires the disclosure of the estimated fair value of financial instruments. We have determined the estimated fair-value amounts using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair-value amounts.

The carrying values of financial assets and liabilities approximate fair values due to the short-term maturities of these instruments. The carrying amounts and fair values of debt are included in Note 10—Debt.

	June 30, 2009						December 31, 2008
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(in millions)
Interest rate derivatives designated as cash flow accounting hedges (1)	$	(106	)	$	(106	)	$	(238	)	$	(238	)
Interest rate derivatives designated as fair value accounting hedges (1)		2			2			3			3
Interest rate derivatives not designated as accounting hedges (1)		(2	)		(2	)		(2	)		(2	)
Commodity-based derivative contracts not designated as accounting hedges (1)		272			272			207			207
Other (2)		11			11			25			25

Total	$	177		$	177		$	(5	)	$	(5	)

____________

(1)

Included in both current and non-current assets and liabilities on the consolidated balance sheets.

(2)

Other represents short-term and long-term investments.

Note 6—Impairment Charges

During the first quarter 2009, we performed a goodwill impairment test due to changes in market conditions that would more likely than not reduce the fair values of our GEN-MW, GEN-WE and GEN-NE reporting units below their carrying amounts. Please read Note 9—Goodwill for further discussion. This decline in value also triggered testing of the recoverability of our long-lived assets. We performed an impairment analysis and recorded a pre-tax impairment charge of $5 million ($3 million after tax). This charge, which relates to the Bluegrass power generation facility, is included in Impairment and other charges in our unaudited condensed consolidated statements of operations. We determined the fair value of the Bluegrass facility using assumptions that reflected our best estimate of third party market participants’ considerations.

At June 30, 2009, in connection with discussions leading to the agreement with LS Power discussed further in Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction, we determined it was more likely than not that certain assets would be sold prior to the end of their previously estimated useful lives. Therefore, we updated our March 31, 2009 long-lived asset impairment analysis for each of the asset groups that we were considering for sale as part of the proposed transaction as of June 30, 2009. As a result, we recorded a pre-tax impairment charge of $197 million ($120 million after-tax). Of this charge, $179 million relates to the Bridgeport power generation facility and related assets and is recorded in the GEN-NE segment. The remaining $18 million ($11 million after-tax) relates to the Bluegrass power generation facility and related assets and is recorded in the GEN-MW segment. This additional impairment charge for the Bluegrass power generation facility reflects updated assumptions regarding the terms of a potential sale as well as continued weakening of forward capacity prices in the second quarter 2009. These charges are included in Impairment and other charges in our unaudited condensed consolidated statements of operations. We determined the fair value of these generation facilities and related assets using assumptions that reflect our best estimate of third party market participants’ considerations and corroborated these estimates indirectly based on our assumptions regarding the terms of and the overall value inherent in the proposed transaction with LS Power.

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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, 2009 and 2008

In performing the June 30, 2009 impairment analysis, we used an 80 percent likelihood at June 30, 2009 of reaching an agreement for sale of the assets, and certain assumptions about the terms of such a sale. If we had been certain at June 30, 2009 of reaching the agreement with LS Power discussed further in Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction, we would have used 100 percent of the estimated sales proceeds to calculate the impairment and would have recorded additional estimated impairment charges of approximately $160 million in our GEN-MW segment and $195 million in our GEN-WE segment, based on the fair value at June 30, 2009 of the consideration ultimately agreed upon under the agreement with LS Power. We expect to record these additional charges in the third quarter of 2009 upon the asset groups meeting the criteria of held-for-sale; however, this estimate of the total impairment charge could change materially based on changes in the fair value of the shares of Class B common stock that is part of the consideration to be received from LS Power in the transaction.

In updating our impairment analysis for assets that were being considered for sale as discussed above, we noted that the aggregate carrying value of the assets included in the proposed transaction exceeded the aggregate fair value of the consideration to be received. In addition, we noted a continued weakening in forward capacity and forward power prices in certain of the markets in which we operate. This indicated a possible decline in the value of power generation assets in all three of our reportable segments. Therefore, at June 30, 2009, we updated our March 31, 2009 impairment analysis for our remaining power generation facilities not currently under consideration for sale. As a result of changes in market conditions in the second quarter 2009 within the Northeast region, we recorded a pre-tax impairment charge of $208 million ($129 million after-tax) related to the Roseton and Danskammer power generation facilities. This charge is included in Impairment and other charges in our unaudited condensed consolidated statements of operations. We determined the fair value of these facilities using assumptions that reflect our best estimate of third party market participants’ considerations. This involved using the present value technique, incorporating our best estimate of third party market participants’ assumptions about the best use of assets, future power and fuel costs and the costs of complying with environmental regulations.

Our impairment analysis of our generating assets is based on forward-looking projections of our estimated future cash flows based on discrete financial forecasts developed by management for planning purposes. These projections incorporate certain assumptions including forward power and capacity prices, forward fuel costs and costs of complying with environmental regulations. As additional information becomes available regarding the significant assumptions used in our analysis, we may conclude that it is necessary to update our impairment analyses in future periods to assess the recoverability of our assets additional impairment charges could be required.

Note 7—Accumulated Other Comprehensive Loss

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

	June 30, 2009			December 31, 2008
	(in millions)
Cash flow hedging activities, net	$	(101	)	$	(125	)
Unrecognized prior service cost and actuarial loss		(64	)		(66	)
Accumulated other comprehensive loss—unconsolidated investments		(18	)		(24	)

Accumulated other comprehensive loss, net of tax	$	(183	)	$	(215	)

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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, 2009 and 2008

Note 8—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. There was no material change during the three and six months ended June 30, 2009. Please see Note 12—Variable Interest Entities—Hydroelectric Generation Facilities in our Form 10-K for discussion of these entities.

PPEA Holding Company LLC. We own an approximate 37 percent interest in PPEA Holding Company LLC (“PPEA Holding”) which, through its wholly-owned subsidiary, Plum Point Energy Associates, LLC (“PPEA”) owns an approximate 57 percent undivided interest in a 665 MW coal fired power generation facility (the “Plum Point Project”), which is under construction in Mississippi County, Arkansas. Our net investment in PPEA Holding at June 30, 2009 was a liability of approximately $77 million. Our unaudited condensed consolidated balance sheet included $554 million of plant construction in progress at June 30, 2009 that is collateral for the Plum Point Project debt, which is nonrecourse to us. As of June 30, 2009, we have posted a $15 million letter of credit issued under our Credit Facility to support our contingent equity contribution to the Plum Point Project. Please see Note 15—Debt—Plum Point Credit Agreement Facility in our Form 10-K for discussion of Plum Point’s borrowings. PPEA Holding meets the definition of a VIE, and we have determined we are the primary beneficiary of this entity; therefore, we have consolidated it. Please see Note 12—Variable Interest Entities—PPEA Holding Company LLC in our Form 10-K for further discussion.

Summarized aggregate financial information for PPEA Holding, included in our unaudited condensed consolidated financial statements, is included below:

	June 30, 2009			December 31, 2008
	(in millions)
As of:
Current assets	$	2		$	1
Property, plant and equipment, net		556			507
Intangible asset		193			193
Other non-current asset		24			29
Total assets		775			730
Current liabilities		25			19
Long-term debt		671			615
Non-current liabilities		109			244
Noncontrolling interest		52			(30	)
For the period ending:
Operating loss		—			(1	)
Net loss		(2	)		(3	)

DLS Power Holdings and DLS Power Development. In December 2008, Dynegy executed an agreement with LS Associates to dissolve DLS Power Holdings and DLS Power Development effective January 1, 2009. Under the terms of the dissolution, Dynegy acquired exclusive rights, ownership and developmental control of substantially all repowering or expansion opportunities related to its existing portfolio of operating assets. In the first quarter 2009, Dynegy subsequently contributed these assets to DHI. LS Associates received approximately $19 million in cash from Dynegy on January 2, 2009, and acquired full ownership and developmental rights associated with various “greenfield” power generation and transmission development projects not related to Dynegy’s existing operating portfolio of assets.

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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, 2009 and 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 Sandy Creek Energy Associates, LP (“SCEA”). SCEA owns an approximate 64 percent 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 ongoing operations. However, we are not the primary beneficiary of the entities, and therefore, do not consolidate them. We account for our investments in SCH and SC Services as equity method investments. At June 30, 2009, we had $7 million included in non-current Accounts receivable, affiliate and $48 million included in Other long-term liabilities on our unaudited consolidated balance sheets. We believe that our maximum exposure to economic loss from these VIEs is limited to $282 million.

On August 9, 2009, we entered into an agreement to sell our interests in SCH and SC Services to LS Power. At the closing of the transaction we expect to record a loss of approximately $90 million based on the June 30, 2009 value of these investments. This estimate could change materially based on changes in the value of our investment prior to close of the transaction. Please read Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further discussion.

Note 9—Goodwill

Assets and liabilities of companies acquired in purchase transactions are recorded at fair value at the date of acquisition. Goodwill represents the excess purchase price over the fair value of net assets acquired, plus any identifiable intangibles. We review goodwill for potential impairment as of November 1st of each year or more frequently if events or circumstances occur that would more likely than not reduce the fair value of a reporting unit below its carrying amount. During the first quarter 2009, there were several events and circumstances which, when considered in the aggregate, indicated such a reduction in the fair value of our GEN-MW, GEN-WE and GEN-NE reporting units:

The first quarter 2009 was characterized by a steep decline in forward commodity prices. Forward market prices for natural gas decreased by 27 percent and 17 percent, respectively, for the calendar years 2009 and 2010, significantly impacting the current market and corresponding forward market prices for power;

During the first quarter 2009, acquisition activity related to power generation facilities was very low, indicating a lack of demand for such transactions;

Dynegy’s market capitalization continued to decline through the first quarter 2009, with Dynegy’s stock price falling from an average of $2.51 per share in the fourth quarter 2008 to an average of $1.73 per share in the first quarter 2009 and a closing price of $1.41 at March 31, 2009; and

General economic indicators, such as economic growth forecasts and unemployment forecasts, deteriorated further during the first quarter 2009.

Considered individually, none of the foregoing events and circumstances would necessarily indicate a significant reduction in the fair value of our reporting units. Dynegy’s stock price is likely to remain volatile throughout 2009, and may change significantly from the closing price on March 31, 2009. However, in light of the significant drop in forward power prices during the first quarter 2009 and the further deterioration in general economic indicators, it was deemed unlikely that Dynegy’s market capitalization would exceed its book equity in the near future. As a result, we concluded that an impairment test of our goodwill on our GEN-MW, GEN-WE and GEN-NE reporting units was required as of March 31, 2009.

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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, 2009 and 2008

The impairment test is performed in two steps at the reporting unit level. The first step compares the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit is higher than its carrying amount, no impairment of goodwill is indicated and no further testing is required. However, if the fair value of the reporting unit is below its carrying amount, a second step must be performed to determine the goodwill impairment required, if any.

Consistent with historical practice, on November 1, 2008, we determined the fair value of our reporting units using the income approach based on a discounted cash flows model. This approach used forward-looking projections of our estimated future operating results based on discrete financial forecasts developed by management for planning purposes. Cash flows beyond the discrete forecasts were estimated using a terminal value calculation, which incorporated historical and forecasted financial trends and considered long-term earnings growth rates based on growth rates observed in the power sector. In performing our impairment test at November 1, 2008, the results of our fair value assessment using the income approach were corroborated using market information about recent sales transactions for comparable assets within the regions in which we operate.

Due to further declines in our market capitalization through December 31, 2008, we determined that assumptions utilized in the November 1, 2008 analysis required updating. We evaluated key assumptions including forward natural gas and power pricing, power demand growth, and cost of capital. While some of the assumptions had changed subsequent to the November 1, 2008 analysis, we determined that the impact of updating those assumptions would not have caused the fair value of the individual reporting units to be below their respective carrying values at December 31, 2008.

As a result of the events and circumstances discussed above, as of March 31, 2009, we updated our fair value assessment using the income approach, taking into account the significant drop in forward prices we observed over the three months ended March 31, 2009. As our long-term outlook on power demand remained unchanged, we did not change our expectations regarding commodity prices beyond 2011 for purposes of this analysis. Additionally, we updated the weighted average cost of capital assumptions used in our income approach to reflect current market data as of March 31, 2009.

Based on the decline in acquisition activity during the first quarter 2009 and the length of time from the most recent asset sales transactions we used to corroborate the results of our income approach valuation in November 2008, we were not able to rely fully on recent sales transactions to corroborate the results of our fair value assessment using the income approach in March 2009. Therefore, for our first quarter 2009 analysis, we also used a market-based approach, comparing our forecasted earnings and Dynegy’s market capitalization to those of similarly situated public companies by considering multiples of earnings.

For each of the reporting units included in our analysis, fair value assessed using the income approach exceeded the fair value assessed using this market-based approach. However, given that Dynegy’s market capitalization had continued to remain below its book equity for more than six months and given the absence of recent asset sales transaction activity to reasonably corroborate the results of our income approach valuation, we had determined that there has been a shift in the manner in which market participants were valuing our business, and believed that the market-based approach has become more relevant for estimating the fair value of our reporting units as of March 31, 2009. We therefore concluded that it was appropriate to place equal weight on the market-based approach (rather than relying primarily on the income approach) for the purpose of determining fair value in step one of the impairment analysis. Based on the results of our analysis discussed above, our GEN-MW, GEN-WE and GEN-NE reporting units did not pass the first step as of March 31, 2009.

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Having determined that the carrying values of the GEN-MW, GEN-WE and GEN-NE reporting units exceeded their fair values, we performed the second step of the analysis. This second step compares the implied fair value of each reporting unit’s goodwill with the carrying amount of such goodwill. We performed a hypothetical allocation of the fair value of the reporting units determined in step one to all of the assets and liabilities of the unit, including any unrecognized intangible assets. After making these hypothetical allocations, we determined no residual value remained that could be allocated to goodwill within each of our GEN-MW, GEN-WE or GEN-NE segments. We recorded first quarter 2009 impairment charges on all three of these reporting units, as follows:

	GEN-MW			GEN-WE			GEN-NE			Total
	(in millions)
Goodwill at December 31, 2008	$	76		$	260		$	97		$	433
Impairment of Goodwill		(76	)		(260	)		(97	)		(433	)

Goodwill at June 30, 2009	$	—		$	—		$	—		$	—

We finalized the second step of our impairment analysis early in the second quarter 2009 and determined no further adjustments were necessary.

Note 10—Debt

	June 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Term Loan B, due 2013	$	69	$	61	$	69	$	52
Term Facility, floating rate due 2013		850		761		850		639
Senior Notes and Debentures:
6.875 percent due 2011		502		481		502		427
8.75 percent due 2012		501		481		501		426
7.5 percent due 2015		550		461		550		388
8.375 percent due 2016		1,047		889		1,047		742
7.125 percent due 2018		173		118		173		110
7.75 percent due 2019		1,100		853		1,100		762
7.625 percent due 2026		171		105		172		93
Subordinated Debentures payable to affiliates, 8.316 percent, due 2027		200		95		200		83
Sithe Senior Notes, 9.0 percent due 2013		344		335		344		328
Plum Point Credit Agreement Facility, floating rate due 2010 (1)		571		332		515		365
Plum Point Tax Exempt Bonds, floating rate due 2036		100		100		100		100
		6,178				6,123
Unamortized premium on debt, net		10				13
		6,188				6,136
Less: Amounts due within one year, including non-cash amortization of basis adjustments		93				64
Total Long-Term Debt	$	6,095			$	6,072

(1)

Upon completion of the construction of the Plum Point Project, the Construction Loan will terminate and the debt thereunder will be replaced by the Bank Loan. The Bank Loan matures on the thirtieth anniversary of the later of the date on which substantial completion of the facility has occurred or the first date of commercial operation under any of the power purchase agreements then in effect. The expected commercial operations date is August 2010. Please read Note 15—Debt—Plum Point Credit Agreement Facility in our Form 10-K for further discussion.

As of June 30, 2009, DHI’s available liquidity under the Credit Facility was reduced temporarily as a result of borrowing limitations under the covenant regarding the ratio of secured debt to EBITDA. Although our available liquidity is reduced, we have adequate liquidity to meet expected needs for the remainder of this quarter. As of September 30, 2009, the reduction is expected to be lifted in connection with Amendment No. 4 to DHI's Credit Facility.

Credit Facility Amendment. On August 5, 2009, we entered into Amendment No. 4 (“Amendment No. 4”) to DHI’s Credit Facility, which includes, among other items, the following material amendments:

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For the Interim Periods Ended June 30, 2009 and 2008

Ratio of Secured Debt to EBITDA. To allow for more flexibility, the financial covenants were amended to provide that the ratio of Secured Debt to EBITDA (as defined in the Credit Facility) (measured as of the last day of the specified measurement period) shall be no greater than: 2.50:1 (measurement period ending June 30, 2009); 3.00:1 (measurement periods ending September 30, 2009 and December 31, 2009);3.25:1 (measurement periods ending March 31, 2010 and June 30, 2010); 3.50:1 (measurement periods ending September 30, 2010, December 31, 2010, March 31, 2011 and June 30, 2011); 3.25:1 (measurement period ending September 30, 2011); 3.00:1 (measurement period ending December 31, 2011); and 2.50:1 (measurement periods ending thereafter).

Ratio of EBITDA to Consolidated Interest Expense. To allow for more flexibility, the financial covenants were amended to provide that the ratio of EBITDA to Consolidated Interest Expense (as defined in the Credit Facility) (measured as of the last day of the specified measurement period) shall be no less than: 1.625:1 (measurement period ending June 30, 2009); 1.75:1 (measurement periods ending September 30, 2009 and December 31, 2009); 1.70:1 (measurement period ending March 31, 2010); 1.60:1 (measurement period ending June 30, 2010); 1.30:1 (measurement periods ending September 30, 2010 and December 31, 2010);1.35:1 (measurement period ending March 31, 2011);1.40:1 (measurement period ending June 30, 2011); 1.60:1 (measurement periods ending September 30, 2011 and December 31, 2011); and 1.75:1 (measurement periods ending thereafter).

Ratio of Total Indebtedness to EBITDA. Prior to incurring certain DHI indebtedness, adding revolver commitments, making certain investments, or certain sales of assets or engaging in certain other permitted activities, we must satisfy certain conditions precedent, including satisfaction, on a pro forma basis, of a separate ratio test of Total Indebtedness to EBITDA (as defined in the Credit Facility). To allow for more flexibility, Amendment No. 4 amended this ratio test (measured as of the last day of the specified measurement period) to no greater than: 6.50:1 (for measurement periods ending prior to and through June 2009); 6.00:1 (for measurement periods ending at any time from July 1, 2009 through December 31, 2009); 6.50:1 (for measurement periods ending at any time from January 1, 2010 through June 30, 2011); 6.25:1 (for measurement periods ending at any time from July 1, 2011 through September 30, 2011;6.00:1 (for measurement periods ending at any time from October 1, 2011 through December 31, 2011); and 5.00:1 (for measurement periods ending thereafter).

Post-Amendment Asset Sales. We may designate up to $500 million of proceeds from the sale of assets after August 5, 2009, as excluded from the asset sale, reinvestment and prepayment provisions of the Credit Facility.

Prepayment Covenants. The debt prepayment covenants were amended to provide that, in the event the maturity date of any of the 6.875 percent Senior Notes due 2011 or the 8.75 percent Senior Notes due 2012 issued by DHI is extended to a date, or refinanced with debt maturing, after the April 2, 2013 Term L/C Facility maturity date, DHI may prepay other longer-dated indebtedness in the amount of any such notes so extended or refinanced.

Margin for Borrowings. The margin for borrowings was amended to provide that the applicable margin will be either 2.375 percent or 2.75 percent per annum for base rate loans and either 3.375 percent or 3.75 percent per annum for Eurodollar loans, with the lower applicable margin being payable if the ratings for the Credit Facility by S&P or Moody’s are BB+ or Ba1 or higher, respectively, and the higher applicable margin being payable if such ratings are both less than BB+ and Ba1.

Unused Commitment Fee. The unused commitment fee was amended to increase the fee to either 0.625 percent or 0.75 percent payable on the unused portion of the Revolving Facility, with the lower commitment fee being payable if the ratings for the Revolving Facility by S&P or Moody’s or BB+ or Ba1 or higher, respectively, and the higher commitment fee being payable if such ratings are both less than BB+ and Ba1.

We are currently in compliance with our covenants.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2009 and 2008

Note 11—Related Party Transactions

Equity Investments. We hold two investments in joint ventures in which LS Power or its affiliates are also investors. DHI has 50 percent ownership interests in SCEA and SC Services, and subsidiaries of LS Power held the remaining 50 percent interests. Please see Note 8—Variable Interest Entities—Sandy Creek for further discussion.

Agreement with LS Power. On August 9, 2009, we entered into an agreement to sell certain assets to LS Power, including our interests in SCH and SC Services. Please read Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further discussion.

Other. On January 8, 2009, DHI paid a dividend of $175 million to Dynegy.

Subsequent to the dissolution of DLS Power Holdings and DLS Power Development, Dynegy acquired exclusive rights, ownership and developmental control of substantially all repowering or expansion opportunities related to its existing portfolio of operating assets, and subsequently contributed approximately $15 million of these assets and approximately $19 million of deferred tax assets associated with these assets to DHI. Please read Note 8—Variable Interest Entities—DLS Power Holdings and DLS Power Development for further information.

Note 12—Dynegy’s Loss Per Share

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

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions, except per share amounts)
Loss from continuing operations	$	(352	)	$	(274	)	$	(690	)	$	(426	)
Less: Net loss attributable to the noncontrolling interest		(1	)		(2	)		(3	)		(2	)
Loss from continuing operations attributable to Dynegy Inc for basic and diluted loss per share	$	(351	)	$	(272	)	$	(687	)	$	(424	)

Basic weighted-average shares		842			840			842			839
Effect of dilutive securities:
Stock options and restricted stock		2			2			1			2
Diluted weighted-average shares		844			842			843			841

Loss per share from continuing operations attributable to Dynegy Inc.:

Basic	$	(0.42	)	$	(0.32	)	$	(0.82	)	$	(0.51	)
Diluted (1)	$	(0.42	)	$	(0.32	)	$	(0.82	)	$	(0.51	)

____________________________

(1)

Entities with a net loss from continuing operations are prohibited from including 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, 2009 and 2008.

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For the Interim Periods Ended June 30, 2009 and 2008

Note 13—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. 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.

Cooling Water Intake Permits. The cooling water intake structures at several of our facilities are regulated under section 316(b) of the Clean Water Act. This provision generally requires that standards set for facilities require that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available (“BTA”) for minimizing adverse environmental impact. These standards are developed and implemented for power generating facilities through the National Pollutant Discharge Elimination System (“NPDES”) permits or individual State Pollutant Discharge Elimination System (“SPDES”) permits. Historically, standards for minimizing adverse environmental impacts of cooling water intakes have been made by permitting agencies on a case-by-case basis considering the best professional judgment of the permitting agency.

The environmental groups that participate in NPDES and SPDES permit proceedings generally argue that only closed cycle cooling meets the BTA requirement. The issuance and renewal of NPDES or SPDES permits for three of our facilities have been challenged on this basis.

Danskammer SPDES Permit — In January 2005, the New York State Department of Environmental Conservation (“NYSDEC”) issued a Draft SPDES Permit renewal for the Danskammer facility. Three environmental groups sought to impose a permit requirement that the Danskammer facility install a closed cycle cooling system. Following a formal evidentiary hearing, the revised Danskammer SPDES Permit was issued on June 1, 2006 without requiring installation of a closed cycle cooling system. The permit was upheld on appeal by the Appellate Division and petitions for leave to appeal to the New York Court of Appeals were denied.

Roseton SPDES Permit — In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton facility. The Draft Roseton SPDES Permit would require the facility to actively manage its water intake to substantially reduce mortality of aquatic organisms. In July 2005, a public hearing was held to receive comments on the Draft Roseton SPDES Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking to impose a permit requirement that the Roseton facility install a closed cycle cooling system. In September 2006, the administrative law judge issued a ruling admitting the petitioners to 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 the petitioners, NYSDEC staff and us. The adjudicatory hearing on the Draft Roseton SPDES Permit will be scheduled after the Commissioner decides the appeal. We believe that the petitioners’ claims lack merit and we plan to oppose those claims vigorously.

Moss Landing NPDES Permit — The California Regional Water Quality Control Board (“Water Board”) issued an NPDES permit for the Moss Landing Facility in 2000 in connection with modernization of the facility. A local environmental group sought review of the permit contending that the once through seawater-cooling system at Moss Landing should be replaced with a closed cycle cooling system to meet the BTA requirements. Following an initial remand from the courts, the Water Board affirmed its BTA finding. The Water Board’s decision was affirmed by the Superior Court in 2004 and by the Court of Appeals in 2007. The petitioners filed a petition for review by the Supreme Court of California, which was granted in March 2008. Further action was deferred pending final disposition of the U.S. Supreme Court challenge regarding the Cooling Water Intake Structures Phase II regulations (“Phase II Rules”), as further described below. We believe that petitioner’s claims lack merit and we plan to oppose those claims vigorously.

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(Unaudited)

For the Interim Periods Ended June 30, 2009 and 2008

Due to the nature of the claims, an adverse result in these proceedings could have a material effect on our financial condition, results of operations and cash flows.

In 2004, the U.S. EPA issued the Phase II Rules, which set forth standards to implement the BTA requirements for cooling water intakes at existing facilities. The rules were challenged by several environmental groups and in 2007 were struck down by the U.S. Court of Appeals for the Second Circuit in Riverkeeper, Inc. v. EPA. The Court’s decision remanded several provisions of the rules to the U.S. EPA for further rulemaking. Several parties sought review of the decision before the U.S. Supreme Court. On April 1, 2009, the U.S. Supreme Court ruled that the U.S. EPA permissibly relied on cost-benefit analysis in setting the national BTA performance standard and in providing for cost-benefit variances from those standards as part of the Phase II Rules. We believe the U.S. Supreme Court’s decision supports our position in the actions described above.

On June 30, 2009, the California State Water Resources Control Board issued its draft policy on the use of coastal and estuarine waters for power plant cooling. If the policy becomes final in its present form, it will require that existing power plants either: i) reduce water intake flow rate to a level commensurate with that which can be achieved by a closed-cycle wet cooling system; or ii) reduce impingement mortality and entrainment to a level comparable to that achieved by such a reduced water intake flow rate using operational or structural controls, or both. The policy may allow less stringent requirements under limited circumstances for very efficient generating units such as Moss Landing units 1 and 2. Compliance with the policy would be required at our South Bay power generation facility by December 31, 2012, at our Morro Bay power generation facility by December 31, 2015 and at our Moss Landing power generation facility by December 17, 2017.

Given the numerous variables and factors involved in calculating the potential costs associated with installing a closed cycle cooling system, any decision to install such a system at any of our plants, should one be required, would be made on a case-by-case basis considering all relevant factors at such time. If capital expenditures related to cooling water systems become great enough to render the operation of the plant uneconomical, we could, at our option, and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate that facility and forego the capital expenditures.

Gas Index Pricing Litigation. We, several of our affiliates and other energy companies are named as defendants in numerous lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to certain index publications in the 2000-2002 timeframe (the “Gas Index Pricing Litigation”). The cases are pending in Nevada federal district court and Tennessee state appellate court. Recent developments include:

In February 2007, the Tennessee state court dismissed a putative class action on defendants’ motion. Plaintiffs appealed and in October 2008, the appellate court reversed the dismissal and remanded the case for further proceedings. In December 2008, the defendants appealed the decision to the Tennessee Supreme Court. The matter is fully briefed and we await further action from the court.

In February 2008, the United States District Court in Las Vegas, Nevada granted defendants’ motion for summary judgment in a putative class action in Colorado, which was transferred to Nevada through the multi-district litigation management process, thereby dismissing the case and all of plaintiffs’ claims against certain defendants (including Dynegy). Plaintiffs moved for reconsideration and the court ordered additional briefing on plaintiffs’ declaratory judgment claims against certain defendants (including Dynegy). In January 2009, the court dismissed plaintiffs’ remaining declaratory judgment claims. The decision is subject to appeal.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2009 and 2008

In June 2009, we and the plaintiff in an action pending in Nevada federal court entered into a confidential settlement agreement to resolve the litigation. The settlement is without admission of wrongdoing and we continue to deny plaintiff’s allegations.

The remaining five cases, three of which seek class certification, are also pending in Nevada federal court. All of the cases were transferred through the multi-district litigation management process from other states, including Kansas, Wisconsin, Missouri and Illinois. The cases allege 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. In December 2008, plaintiffs in the class actions filed motions for class certification. The motion is expected to be fully briefed in the third quarter of 2009.

We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining 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 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 which are now fully briefed. A hearing on defendants’ motions was scheduled for May 2009, however the court took the motion off calendar and will consider the submissions of the parties. No timetable is established for the court’s order. We believe the plaintiffs’ suit lacks merit and we intend to oppose their claims vigorously.

Information Request under Section 114 of the Clean Air Act. On March 9, 2009, we received an information request from the U.S. EPA regarding maintenance, repair and replacement projects undertaken between January 1, 2000 and the present at the Danskammer power generation facility. We submitted responses to the information request on April 7 and July 17, 2009 and are continuing to cooperate with the U.S. EPA to provide additional information as requested. The information request is related to a nationwide enforcement initiative by the U.S. EPA targeting electric utilities. The U.S. EPA’s inquiry may lead to claims of CAA violations that could result in an enforcement action, the scope of which cannot be predicted with confidence at this time, but which could have a material effect on our financial condition, results of operations and cash flows.

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 affect our financial condition, results of operations or cash flows.

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. Related to the indemnifications discussed below, we have accrued approximately $2 million as of June 30, 2009.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2009 and 2008

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 provides that we will manage the Gas Index Pricing Litigation 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. West Coast Power is no longer a party to any active Gas Index Pricing Litigation matters. 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 U.S. Supreme Court, which remanded the case to FERC for further review.

Targa Indemnities. During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa Resources, Inc. (“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 remediation 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 tax reserve associated with this indemnification.

Illinois Power Indemnities. As a condition of Dynegy’s 2004 sale of Illinois Power and its interest in Electric Energy Inc.’s plant in Joppa, Illinois, Dynegy provided indemnifications to third parties regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, Dynegy has indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased natural gas and investments in specified items. Although there is no limitation on Dynegy’s liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses. Dynegy has made certain payments in respect of these indemnities following regulatory action by the ICC, and has established reserves for further potential indemnity claims. Further 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 regulatory actions.

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. As of June 30, 2009, no claims have been made against these indemnities which expire on September 30, 2009. 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 Rolling Hills, Calcasieu, CoGen Lyondell and Heard County power generating facilities. As of June 30, 2009, no claims have been made against these indemnities.

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For the Interim Periods Ended June 30, 2009 and 2008

Note 14—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 our Form 10-K.

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

	Pension Benefits						Other Benefits
	Three Months Ended June 30,
	2009			2008			2009		2008
	(in millions)
Service cost benefits earned during period	$	3		$	2		$	—	$	—
Interest cost on projected benefit obligation		3			3			1		1
Expected return on plan assets		(4	)		(4	)		—		—
Recognized net actuarial loss		1			1			—		—

Net periodic benefit cost	$	3		$	2		$	1	$	1

	Pension Benefits						Other Benefits
	Six Months Ended June 30,
	2009			2008			2009		2008
	(in millions)
Service cost benefits earned during period	$	6		$	5		$	1	$	1
Interest cost on projected benefit obligation		6			6			2		2
Expected return on plan assets		(7	)		(7	)		—		—
Recognized net actuarial loss		2			1			—		—

Net periodic benefit cost	$	7		$	5		$	3	$	3

Contributions. During the six months ended June 30, 2009 we made $3 million in contributions to our pension plans and other postretirement benefit plans. We made no contributions to our pension plans or other postretirement benefit plans during the six months ended June 30, 2008. We expect to make contributions of approximately $26 million to our pension plans and $1 million to other benefit plans during 2009.

Note 15—Income Taxes

Effective Tax Rate. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant unusual or extraordinary transactions. Income taxes for significant unusual or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. Dynegy’s income taxes included in continuing operations were as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions, except rates)
Income tax benefit	$	209		$	186		$	124		$	282

Effective tax rate		37	%		41	%		15	%		40	%

For the six months ended June 30, 2009, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to nondeductible goodwill. Additionally, a change in state income tax law resulted in additional income tax expense of approximately $21 million. As a result of the LS Power transaction, we revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore we recorded valuation allowances resulting in additional state tax expense of $10 million for the three and six months ended June 30, 2009. 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.

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(Unaudited)

For the Interim Periods Ended June 30, 2009 and 2008

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(in millions, except rates)
Income tax benefit	$	220		$	184		$	138		$	275

Effective tax rate		39	%		41	%		17	%		39	%

For the six months ended June 30, 2009, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to nondeductible goodwill. Additionally, a change in state income tax law resulted in additional income tax expense of approximately $15 million. As a result of the LS Power transaction, we revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore we recorded valuation allowances resulting in additional state tax expense of $7 million for the three and six months ended June 30, 2009. 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.

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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, 2009 and 2008

Note 16—Segment Information

We report results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

Reportable segment information for Dynegy, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2009 and 2008 is presented below:

Dynegy’s Segment Data as of and for the Three Months Ended June 30, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	172		$	141		$	181		$	(1	)	$	493

Total revenues	$	172		$	141		$	181		$	(1	)	$	493

Depreciation and amortization	$	(57	)	$	(18	)	$	(16	)	$	(3	)	$	(94	)
Impairment and other charges		(18	)		—			(387	)		—			(405	)

Operating income (loss)	$	(85	)	$	37		$	(382	)	$	(50	)	$	(480	)

Earnings from unconsolidated investments		—			13			—			—			13
Other items, net		—			2			—			2			4
Interest expense														(98	)

Loss from continuing operations before income taxes														(561	)
Income tax benefit														209

Loss from continuing operations														(352	)
Income from discontinued operations, net of taxes														6

Net loss														(346	)
Less: Net loss attributable to the noncontrolling interests														(1	)

Net loss attributable to Dynegy Inc.													$	(345	)

Identifiable assets:
Domestic	$	7,075		$	2,946		$	1,986		$	1,514		$	13,521
Other		—			—			—			19			19

Total	$	7,075		$	2,946		$	1,986		$	1,533		$	13,540

Capital expenditures	$	(146	)	$	(7	)	$	(11	)	$	(1	)	$	(165	)

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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, 2009 and 2008

Dynegy’s Segment Data as of and for the Three Months Ended June 30, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	66		$	177		$	56		$	1		$	300
Other		—			—			22			—			22

Total revenues	$	66		$	177		$	78		$	1		$	322

Depreciation and amortization	$	(52	)	$	(24	)	$	(14	)	$	(2	)	$	(92	)

Operating loss	$	(170	)	$	(32	)	$	(142	)	$	(20	)	$	(364	)

Earnings (losses) from unconsolidated investments		—			3			—			(6	)		(3	)
Other items, net		—			4			—			11			15
Interest expense														(108	)

Loss from continuing operations before income taxes														(460	)
Income tax benefit														186

Loss from continuing operations														(274	)
Loss from discontinued operations, net of taxes														—

Net loss														(274	)
Less: Net loss attributable to the noncontrolling interests														(2	)
Net loss attributable to Dynegy Inc.													$	(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	)

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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, 2009 and 2008

Dynegy’s Segment Data as of and for the Six Months Ended June 30, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	697		$	223		$	478		$	(1	)	$	1,397

Total revenues	$	697		$	223		$	478		$	(1	)	$	1,397

Depreciation and amortization	$	(109	)	$	(40	)	$	(31	)	$	(6	)	$	(186	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges		(23	)		—			(387	)		—			(410	)

Operating income (loss)	$	115		$	(250	)	$	(425	)	$	(87	)	$	(647	)

Earnings from unconsolidated investments		—			20			—			1			21
Other items, net		2			2			—			4			8
Interest expense														(196	)

Loss from continuing operations before income taxes														(814	)
Income tax benefit														124

Loss from continuing operations														(690	)
Income from discontinued operations, net of taxes														7

Net loss														(683	)
Less: Net loss attributable to the noncontrolling interests														(3	)

Net loss attributable to Dynegy Inc.													$	(680	)

Identifiable assets:
Domestic	$	7,075		$	2,946		$	1,986		$	1,514		$	13,521
Other		—			—			—			19			19

Total	$	7,075		$	2,946		$	1,986		$	1,533		$	13,540

Capital expenditures	$	(274	)	$	(8	)	$	(18	)	$	(3	)	$	(303	)

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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, 2009 and 2008

Dynegy’s Segment Data as of and for the Six Months Ended June 30, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	230		$	306		$	235		$	—		$	771
Other		—			—			94			—			94

Total revenues	$	230		$	306		$	329		$	—		$	865

Depreciation and amortization	$	(105	)	$	(47	)	$	(27	)	$	(5	)	$	(184	)

Operating loss	$	(229	)	$	(78	)	$	(163	)	$	(44	)	$	(514	)

Losses from unconsolidated investments		—			(2	)		—			(10	)		(12	)
Other items, net		—			4			6			25			35
Interest expense														(217	)

Loss from continuing operations before income taxes														(708	)
Income tax benefit														282

Loss from continuing operations														(426	)
Income from discontinued operations, net of taxes														—

Net loss														(426	)
Less: Net loss attributable to the noncontrolling interests														(2	)

Net loss attributable to Dynegy Inc.													$	(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	)

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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, 2009 and 2008

Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2009 and 2008 is presented below:

DHI’s Segment Data as of and for the Three Months Ended June 30, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	172		$	141		$	181		$	(1	)	$	493

Total revenues	$	172		$	141		$	181		$	(1	)	$	493

Depreciation and amortization	$	(57	)	$	(18	)	$	(16	)	$	(3	)	$	(94	)
Impairment and other charges		(18	)		—			(387	)		—			(405	)

Operating income (loss)	$	(85	)	$	37		$	(382	)	$	(50	)	$	(480	)

Earnings from unconsolidated investments		—			13			—			—			13
Other items, net		—			2			—			1			3
Interest expense														(98	)

Loss from continuing operations before income taxes														(562	)
Income tax benefit														220

Loss from continuing operations														(342	)
Income from discontinued operations, net of taxes														6

Net loss														(336	)
Less: Net loss attributable to the noncontrolling interests														(1	)

Net loss attributable to Dynegy Holdings Inc.													$	(335	)

Identifiable assets:
Domestic	$	7,075		$	2,946		$	1,986		$	1,332		$	13,339
Other		—			—			—			19			19

Total	$	7,075		$	2,946		$	1,986		$	1,351		$	13,358

Capital expenditures	$	(146	)	$	(7	)	$	(11	)	$	(1	)	$	(165	)

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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, 2009 and 2008

DHI’s Segment Data as of and for the Three Months Ended June 30, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	66		$	177		$	56		$	1		$	300
Other		—			—			22			—			22

Total revenues	$	66		$	177		$	78		$	1		$	322

Depreciation and amortization	$	(52	)	$	(24	)	$	(14	)	$	(2	)	$	(92	)

Operating loss	$	(170	)	$	(32	)	$	(142	)	$	(20	)	$	(364	)

Earnings from unconsolidated investments		—			3			—			—			3
Other items, net		—			4			—			10			14
Interest expense														(108	)

Loss from continuing operations before income taxes														(455	)
Income tax benefit														184

Loss from continuing operations														(271	)
Loss from discontinued operations, net of taxes														—

Net loss														(271	)
Less: Net loss attributable to the noncontrolling interests														(2	)

Net loss attributable to Dynegy Holdings Inc.													$	(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	)

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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, 2009 and 2008

DHI’s Segment Data as of and for the Six Months Ended June 30, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	697		$	223		$	478		$	(1	)	$	1,397

Total revenues	$	697		$	223		$	478		$	(1	)	$	1,397

Depreciation and amortization	$	(109	)	$	(40	)	$	(31	)	$	(6	)	$	(186	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges		(23	)		—			(387	)		—			(410	)

Operating income (loss)	$	115		$	(250	)	$	(425	)	$	(89	)	$	(649	)

Earnings from unconsolidated investments		—			20			—			—			20
Other items, net		2			2			—			3			7
Interest expense														(196	)

Loss from continuing operations before income taxes														(818	)
Income tax benefit														138

Loss from continuing operations														(680	)
Income from discontinued operations, net of taxes														7

Net loss														(673	)
Less: Net loss attributable to the noncontrolling interests														(3	)

Net loss attributable to Dynegy Holdings Inc.													$	(670	)

Identifiable assets:
Domestic	$	7,075		$	2,946		$	1,986		$	1,332		$	13,339
Other		—			—			—			19			19

Total	$	7,075		$	2,946		$	1,986		$	1,351		$	13,358

Capital expenditures	$	(274	)	$	(8	)	$	(18	)	$	(3	)	$	(303	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2009 and 2008

DHI’s Segment Data as of and for the Six Months Ended June 30, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	230		$	306		$	235		$	—		$	771
Other		—			—			94			—			94

Total revenues	$	230		$	306		$	329		$	—		$	865

Depreciation and amortization	$	(105	)	$	(47	)	$	(27	)	$	(5	)	$	(184	)

Operating loss	$	(229	)	$	(78	)	$	(163	)	$	(44	)	$	(514	)

Losses from unconsolidated investments		—			(2	)		—			—			(2	)
Other items, net		—			4			6			24			34
Interest expense														(217	)

Loss from continuing operations before income taxes														(699	)
Income tax benefit														275

Loss from continuing operations														(424	)
Income from discontinued operations, net of taxes														—

Net loss														(424	)
Less: Net loss attributable to the noncontrolling interests														(2	)

Net loss attributable to Dynegy Holdings Inc.													$	(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	)

Note 17—Subsequent Events

We have evaluated subsequent events through August 10, 2009, the date our financial statements were issued and up to the time of the filing of our financial statements with the SEC.

On August 9, 2009, we entered into an agreement to sell our interests in several power generation facilities and our equity investment in the Sandy Creek joint ventures. Please read Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further discussion.

In addition, on August 5, 2009, we entered into Amendment No. 4 to the Credit Facility. Please read Note 10—Debt—Credit Facility Amendment for further discussion.

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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, 2009 and 2008

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 Form 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 Holding, which through its wholly owned subsidiary owns a 57 percent undivided interest in the Plum Point Project, 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 SCEA, which owns an approximate 64 percent undivided interest in the Sandy Creek Project, an 898 MW power generation facility under construction in Texas, which is included in GEN-WE. On August 9, 2009, we entered into a transaction with LS Power to sell our interests in the Sandy Creek Project. Please read Recent Developments below for further information.

Recent Developments

LS Power Transaction. On August 9, 2009, we entered into a purchase and sale agreement with LS Power in which we agreed: (i) to sell our ownership interests in 4,788 MW of peaking and combined-cycle power generation assets, as well as our remaining noncontrolling interests in the Sandy Creek Project under construction in Texas and (ii) to issue $235 million principal amount of DHI 7.50 percent senior unsecured notes due 2015. We will receive $1.025 billion in cash (consisting, in part, of $175 million of restricted cash on our unaudited condensed consolidated balance sheets to be released to Dynegy from the Sandy Creek restricted account) and 245 million of Dynegy’s Class B shares from LS Power.

Upon closing of the transaction, which is expected to occur during the second half of 2009 subject to receipt of required regulatory approvals, the remaining 95 million shares of Dynegy’s Class B common stock held by LS Power will be converted into an equivalent number of shares of Dynegy’s Class A common stock, representing approximately 15 percent of Dynegy’s outstanding Class A common stock. Concurrent with the execution of the purchase and sale agreement, LS Power and Dynegy entered into a new Shareholder Agreement, which, upon closing of the transaction, generally will restrict LS Power from increasing their future ownership above 15 percent for a specified period and eliminate special approval, board representation and other certain rights associated with the former Class B common shares. Please see Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further information.

Based on the fair value at June 30, 2009 of the consideration to be received from LS Power as now reflected in the definitive transaction documents, we expect to record further pre-tax impairment charges of approximately $355 million in the third quarter 2009 upon the asset groups meeting the criteria of held for sale, as well as a net loss on sale of assets of approximately $130 million upon closing of the transaction, based on our stock price and the value of our investment in Sandy Creek at June 30, 2009. However, the estimates of the total impairment charge and loss on sale could change materially based on changes in the fair value of the shares of Class B common stock that is part of the consideration to be received in the sales transaction. Please read Note 6—Impairment Charges for further discussion of these impairments.

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Credit Facility Amendment. On August 5, 2009, we entered into Amendment No. 4 to the Credit Facility. Among certain other changes, Amendment No. 4 (a) modifies the financial covenants relating to the ratios of Secured Debt to EBITDA and of EBITDA to Consolidated Interest Expense; (b) further modifies certain conditions precedent to, incurring of certain DHI indebtedness, adding revolver commitments, making certain investments, or certain sales of assets and engaging in certain other permitted activities; (c) increases the amount of assets eligible for disposition outside the asset sale, reinvestment and prepayment provisions of the Credit Facility; (d) expands our ability to prepay additional debt of DHI under certain conditions; and (e) increases applicable margin for borrowings and the unused commitment fee payable on the unused portion of the revolving facility. Please read Note 10—Debt—Credit Facility Amendment for further discussion.

Cost Saving Initiative. Beginning in the third quarter 2009, we have implemented an extensive, multi-year program to reduce costs across the company. We expect to begin realizing these savings in 2010. Savings are expected to be generated through reductions in capital expenditures, operations and maintenance costs, and corporate general and administrative expenses. We expect to record a restructuring charge of less than $5 million in the third quarter 2009 in connection with this effort.

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, 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, fuel oil and coal, facility maintenance costs and other costs such as payroll.

Our primary sources of internal liquidity are cash flows from operations, cash on hand, available capacity under our Credit Facility, of which the revolver capacity is scheduled to mature in April 2012 and the term letter of credit capacity of $850 million is scheduled to mature in April 2013. Additionally, DHI may borrow money from time to time from Dynegy. Our primary sources of external liquidity are asset sales proceeds and proceeds from capital market transactions to the extent we engage in these transactions.

Operating cash flows provided by our power generation assets and the available cash we currently hold are expected to be sufficient to fund the operation of our business, as well as our planned capital expenditure program, including expenditures in connection with the Midwest consent decree (“Midwest Consent Decree”), and debt service requirements over the next twelve months. We maintain capacity under the Credit Facility in order to post collateral in the form of letters of credit or cash, and we believe we have sufficient capacity should we be required to post additional collateral. Please read Note 10—Debt— Credit Facility Amendment for a discussion of the financial covenants contained in the Credit Facility.

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Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at August 3, 2009, June 30, 2009 and December 31, 2008:

	August 3, 2009			June 30, 2009			December 31, 2008
	(in millions)
Revolver capacity (1)(2)	$	903		$	875			$	1,080
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				377
Available contingent letter of credit facility capacity (3)		—			—				—
Outstanding letters of credit		(947	)		(1,024	)			(1,135	)

Unused capacity		1,158			1,053				1,147

Cash—DHI		532			411				670

Total available liquidity—DHI		1,690			1,464				1,817
Cash—Dynegy		183			183				23

Total available liquidity—Dynegy	$	1,873		$	1,647			$	1,840

(1)

We currently have a syndicate of lenders participating in the revolving portion of our Credit Facility with commitments ranging from $10 million to $105 million. We have not experienced, nor do we currently anticipate, any difficulties in obtaining funding from any of the lenders at this time. However, we continue to monitor the environment, and any lack of or delay in funding by a significant member or multiple members of our banking group would negatively affect our liquidity position.

(2)

(3)

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

Cash on Hand. At August 3, 2009 and June 30, 2009, Dynegy had cash on hand of $715 million and $594 million, respectively, as compared to $693 million at December 31, 2008. The decrease in cash on hand as compared to the end of 2008 is primarily attributable to capital expenditures and an increase in cash collateral on futures and exchange-cleared derivatives partially offset by cash provided by the operating activities of our power generation business and the receipt of proceeds from the Heard County sale.

At August 3, 2009 and June 30, 2009, DHI had cash on hand of $532 million and $411 million, respectively, as compared to $670 million at December 31, 2008. The decrease in cash on hand as compared to the end of 2008 is primarily attributable to a dividend of $175 million paid to Dynegy in January 2009, an increase in capital expenditures and cash collateral on futures and exchange-cleared derivatives partially offset by cash provided by the operating activities of our power generation business and the receipt of proceeds from the Heard County sale.

Operating Activities

Historical Operating Cash Flows. Dynegy’s cash flow provided by operations totaled $60 million for the six months ended June 30, 2009. DHI’s cash flow provided by operations totaled $80 million for the six months ended June 30, 2009. During the period, our power generation business provided positive cash flow from operations of $338 million from the operation of our power generation facilities. Cash provided by the operations of our power generation facilities was partly offset by a $166 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 included a use of approximately $278 million and $258 million in cash by Dynegy and DHI, respectively, primarily due to interest payments to service debt and general and administrative expenses, partially offset by interest income. Dynegy’s operating cash flow also reflected the payment of $19 million to LS Associates in conjunction with the dissolution of DLS Power Holdings and DLS Power Development.

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Dynegy’s cash flow provided by operations totaled $32 million for the six months ended June 30, 2008. DHI’s cash flow provided by operations totaled $29 million for the six months ended June 30, 2008. During the period, our power generation business provided positive cash flow from operations of $324 million. Cash provided by the operations 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 and $295 million in cash by Dynegy and DHI, respectively, 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.

Future Operating Cash Flows. 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, collateral requirements, the value of capacity and ancillary services and legal, environmental and regulatory requirements. Additionally, the increased costs associated with the Credit Facility amendment, the cost savings initiative and LS Power transaction will impact our future operating cash flows. 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 increased maintenance and environmental costs, in balance with ensuring that our plants are available to operate when markets offer attractive returns.

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 3, 2009, June 30, 2009 and December 31, 2008:

	August 3, 2009		June 30, 2009		December 31, 2008
	(in millions)
By Business:
Generation	$	1,042	$	1,119	$	1,064
Other		189		189		189

Total	$	1,231	$	1,308	$	1,253
By Type:
Cash (1)	$	284	$	284	$	118
Letters of Credit		947		1,024		1,135

Total	$	1,231	$	1,308	$	1,253

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(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, 2008 to June 30, 2009 and to August 3, 2009 are primarily related to increases in initial margin requirements associated with the volume of forward power sales and fuel purchase transactions.

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.

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Investing Activities

Capital Expenditures. We continue to tightly manage our operating costs and capital expenditures. We had approximately $303 million and $299 million in capital expenditures during the six months ended June 30, 2009 and 2008. Our capital spending by reportable segment was as follows:

	For the Six Months Ended June 30,
	2009		2008
	(in millions)

GEN-MW	$	274	$	249
GEN-WE		8		21
GEN-NE		18		22
Other		3		7

Total	$	303	$	299

Capital spending in our GEN-MW segment primarily consisted of environmental and maintenance capital projects, as well as approximately $47 million and $120 million spent on development capital related to the Plum Point Project during the six months ended June 30, 2009 and 2008, respectively. Capital spending in our GEN-WE and GEN-NE segments primarily consisted of maintenance projects.

During the first quarter 2009, we revised our estimate of the timing regarding a maintenance capital project at our Moss Landing facility in GEN-WE. We expect capital expenditures for the remainder of 2009 to be approximately $45 million higher than originally planned, primarily due to the change in timing.

Asset Dispositions. On April 30, 2009, we completed our sale of the Heard County power generation facility to Oglethorpe for approximately $105 million, net of transaction costs. Please read Note 2—Discontinued Operations—Heard County for further discussion.

On August 9, 2009, we entered into a purchase and sale agreement with LS Power in which we agreed to: (i) sell our ownership interests in 4,788 MW of peaking and combined-cycle power generation assets, as well as our remaining noncontrolling interest in the Sandy Creek Project under construction in Texas and (ii) issue $235 million principal amount of DHI 7.50 percent senior unsecured notes due 2015. We will receive $1.025 billion in cash (consisting, in part, of $175 million of restricted cash on our unaudited condensed consolidated balance sheets to be released to Dynegy from the Sandy Creek restricted account) and 245 million of Dynegy’s Class B shares held by LS Power. Please see Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further information.

Proceeds from asset sales during the six months ended June 30, 2008 totaled $84 million and primarily related to the sale of our Calcasieu power generating facility, net of transaction costs, the NYMEX shares and seats, and the beneficial interest in Oyster Creek. Please read Note 2—Dispositions 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 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. We have previously indicated that we consider Plum Point a non-core asset and intend to pursue alternatives regarding our remaining ownership interest.

Other Investing Activities. Cash inflow related to short-term investments during the six months ended June 30, 2009 totaled $14 million and $13 million for both Dynegy and DHI, respectively, reflecting a distribution from our short-term investments. There was a $33 million cash outflow during the six months ended June 30, 2009 related to changes in restricted cash balances primarily due to a $39 million increase in the Independence restricted cash balance. Other included $3 million of insurance proceeds.

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Dynegy 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 8—Variable Interest Entities—Sandy Creek for further discussion.

There was a $28 million cash inflow during the six months ended June 30, 2008 related 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 during the six months ended June 30, 2008.

Financing Activities

Historical Cash Flow from Financing Activities. Dynegy’s net cash provided by financing activities during the six months ended June 30, 2009 totaled $54 million, primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility. DHI’s net cash used in financing activities during the six months ended June 30, 2009 totaled $121 million. This included a one-time dividend payment from DHI to Dynegy of $175 million offset by $54 million primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.

Dynegy’s cash provided by financing activities during the six months ended June 30, 2008 totaled $88 million, which primarily related to proceeds of $111 million 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, 2008 totaled $86 million, which primarily related to proceeds of $111 million 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.

Financing Trigger Events. Our debt instruments and other financial obligations include provisions which, if not met, could require early payment, additional collateral support or similar actions. These trigger events include financial covenants, insolvency events, defaults on scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events. However, certain interest rate swaps to which Plum Point is a party could be terminated if a credit downgrade of Plum Point occurs and there is also a default by the insurer that has provided credit insurance for the swaps. The fair value of the Plum Point interest rate swaps at June 30, 2009 was $105 million of a liability.

Capital-Structuring Transactions. Following the pending transaction with LS Power, we will be focused on deploying the proceeds from the transaction in a manner that best aligns with our capital allocation objectives. We are considering executing one or more financing transactions in the near-term designed to reduce existing debt or other obligations or replace certain debt obligations with longer-term obligations. Transactions to redeem outstanding debt may require us to pay a premium over market price. 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 financing agreements as well as the provisions of the agreements with LS Power. 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.

Further, 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, including public or private debt or equity issuances. Matters to be considered will include reducing cash interest expense, covenant flexibility, return on investment and maturity profile, all to be balanced with maintaining adequate liquidity. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory or environmental requirements as well as any decisions to seek an improved credit profile. 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, including current market conditions. Any issuance of equity by Dynegy likely would have other effects as well, including stockholder dilution, and our ability to issue equity securities will be limited by the agreements with LS Power entered into on August 9, 2009. This agreement provides that we have agreed not to issue Dynegy’s equity securities for our own purposes until the earlier of (i) 121 days following the closing of the transaction with LS Power and (ii) the first date following closing of the transaction in which LS Power owns, in aggregate, less than 10 percent of Dynegy’s then outstanding Class A common stock. Further, our ability to issue debt securities is limited by our financing agreements, including our Credit Facility.

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

Dividends and Dynegy Common Stock. Dividend payments on Dynegy’s common stock are at the discretion of its Board of Directors. Dynegy did not declare or pay a dividend on its common stock during the second quarter 2009, and does not expect to pay a dividend on any class of its common stock in the foreseeable future.

Credit Ratings

Our credit rating status is currently “non-investment grade”; our senior unsecured debt is rated “B” by Standard & Poor’s, “B3” by Moody’s, and “B+” by Fitch. On April 8, 2009, Moody’s downgraded our corporate family and probability of default ratings of the electricity utility to “B2” from “B1” based on projected lower power prices affecting credit metrics. The agency also cut our senior secured bank facilities rating to “Ba2” from “Ba1”, and senior unsecured debt rating to “B3” from “B2”. The downgrades did not trigger any of our financing arrangements or other obligations and otherwise have not impacted our operations or liquidity.

Disclosure of Contractual Obligations and Contingent Financial Commitments

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

As of June 30, 2009, there were no material changes to our contractual obligations and contingent financial commitments since December 31, 2008.

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

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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, 2009 and 2008. 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. 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, 2009 and 2008

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, 2009 and 2008, respectively:

Dynegy’s Results of Operations for the Three Months Ended June 30, 2009

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues	$	172		$	141		$	181		$	(1	)	$	493
Cost of sales		(120	)		(55	)		(110	)		—			(285	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(62	)		(31	)		(50	)		(1	)		(144	)
Depreciation and amortization expense		(57	)		(18	)		(16	)		(3	)		(94	)
Impairment and other charges		(18	)		—			(387	)		—			(405	)
General and administrative expense		—			—			—			(45	)		(45	)
Operating income (loss)	$	(85	)	$	37		$	(382	)	$	(50	)	$	(480	)
Earnings from unconsolidated investments		—			13			—			—			13
Other items, net		—			2			—			2			4
Interest expense														(98	)

Loss from continuing operations before income taxes														(561	)
Income tax benefit														209

Loss from continuing operations														(352	)
Income from discontinued operations, net of taxes														6
Net loss														(346	)

Less: Net loss attributable to the noncontrolling interests														(1	)

Net loss attributable to Dynegy Inc.													$	(345	)

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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

Revenues	$	66		$	177		$	78		$	1		$	322
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	)		(24	)		(14	)		(2	)		(92	)
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		—			4			—			11			15
Interest expense														(108	)

Loss from continuing operations before income taxes														(460	)
Income tax benefit														186

Net loss														(274	)
Less: Net loss attributable to the noncontrolling interests														(2	)

Net loss attributable to Dynegy Inc.													$	(272	)

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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, 2009 and 2008, respectively:

DHI’s Results of Operations for the Three Months Ended June 30, 2009

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues	$	172		$	141		$	181		$	(1	)	$	493
Cost of sales		(120	)		(55	)		(110	)		—			(285	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(62	)		(31	)		(50	)		(1	)		(144	)
Depreciation and amortization expense		(57	)		(18	)		(16	)		(3	)		(94	)
Impairment and other charges		(18	)		—			(387	)		—			(405	)
General and administrative expense		—			—			—			(45	)		(45	)
Operating income (loss)	$	(85	)	$	37		$	(382	)	$	(50	)	$	(480	)
Earnings from unconsolidated investments		—			13			—			—			13
Other items, net		—			2			—			1			3
Interest expense														(98	)

Loss from continuing operations before income taxes														(562	)
Income tax benefit														220

Loss from continuing operations														(342	)
Income from discontinued operations, net of taxes														6

Net loss														(336	)
Less: Net loss attributable to the noncontrolling interests														(1	)

Net loss attributable to Dynegy Holdings Inc.													$	(335	)

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

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues	$	66		$	177		$	78		$	1		$	322
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	)		(24	)		(14	)		(2	)		(92	)
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		—			4			—			10			14
Interest expense														(108	)

Loss from continuing operations before income taxes														(455	)
Income tax benefit														184

Net loss														(271	)
Less: Net loss attributable to the noncontrolling interests														(2	)

Net loss attributable to Dynegy Holdings Inc.													$	(269	)

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The following table provides summary segmented operating statistics for the three months ended June 30, 2009 and 2008, respectively:

	Three Months Ended June 30,
	2009			2008
GEN-MW
Million Megawatt Hours Generated		5.9			5.5
In Market Availability for Coal Fired Facilities (1)		92	%		91	%
Average Capacity Factor for Combined Cycle Facilities (2)		28	%		11	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	34		$	77
Commonwealth Edison (NI Hub)	$	32		$	75
PJM West	$	40		$	99
Average Market Spark Spreads ($/MWh) (4):
PJM West	$	12		$	14

GEN-WE
Million Megawatt Hours Generated (5)		1.3			2.3
Average Capacity Factor for Combined Cycle Facilities (2)		21	%		38	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)	$	31		$	97
Palo Verde	$	30		$	92
Average Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)	$	5		$	18
Palo Verde	$	7		$	15

GEN-NE
Million Megawatt Hours Generated		2.1			1.6
In Market Availability for Coal Fired Facilities (1)		92	%		88	%
Average Capacity Factor for Combined Cycle Facilities (2)		39	%		22	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	44		$	123
New York—Zone A	$	31		$	75
Mass Hub	$	39		$	114
Average Market Spark Spreads ($/MWh) (4):
New York—Zone A	$	2		$	(9	)
Mass Hub	$	11		$	29
Fuel Oil	$	(53	)	$	(41	)

Average natural gas price—Henry Hub ($/MMBtu) (6)	$	3.69		$	11.32

__________________

(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 us.

(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 us.

(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, 2009 and 2008, respectively.

(6)

Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

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The following table summarizes significant items on a pre-tax basis, affecting net loss for the period presented:

	Three Months Ended June 30, 2009
	Power Generation
	GEN-MW			GEN-WE		GEN-NE			Other		Total
	(in millions)
Impairments	$	(18	)	$	—	$	(387	)	$	—	$	(405	)
Sandy Creek mark-to-market gains (1)		—			15		—			—		15
Discontinued operations (2)		—			10		—			—		10

Total	$	(18	)	$	25	$	(387	)	$	—	$	(380	)

________

(1)

These mark-to-market gains represent our 50 percent share.

(2)

Discontinued operations represents a gain of $10 million on the sale of the Heard County power generation facility.

	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

Operating Loss

Dynegy’s and DHI’s operating loss was $480 million for the three months ended June 30, 2009, compared to an operating loss of $364 million for the three months ended June 30, 2008.

Our operating loss for the three months ended June 30, 2009 was driven, in large part, by $405 million of asset impairments. Please read Note 6—Impairment Charges for further discussion.

The operating loss for the three months ended June 30, 2009 also included mark-to-market losses of $103 million, which were related to the impact of rising 2010 and 2011 power prices in the Midwest on our forward sales, and the settlement of risk management positions that matured during the quarter which are included in Revenues in the unaudited condensed consolidated statements of operations. This compares to mark-to-market losses of $481 million in the second quarter of 2008.

We do not designate our commodity derivative instruments as cash flow hedges for accounting purposes. Please read 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 a result, 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. Except for those positions that settled in the three months ended June 30, 2009, the expected cash impact of the settlement of these positions will be recognized over time largely 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 $85 million for the three months ended June 30, 2009, compared to an operating loss of $170 million for the three months ended June 30, 2008.

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Revenues for the three months ended June 30, 2009 increased by $106 million compared to the three months ended June 30, 2008, cost of sales decreased by $17 million and operating and maintenance expense increased by $15 million, resulting in a net increase of $108 million. The increase was primarily driven by the following:

Reduced mark-to-market losses – GEN-MW’s results for the three months ended June 30, 2009 included mark-to-market losses of $129 million related to forward sales, compared to $286 million of mark-to-market losses for the three months ended June 30, 2008. Of the $129 million in 2009 mark-to-market losses, $68 million related to positions that settled or will settle in 2009, and the remaining $61 million related to positions that will settle in 2010 and beyond;

Additional capacity sales of approximately $6 million, as a result of improved capacity prices for 2009 compared with 2008;

Increased volumes —Generated volumes increased by 9 percent, from 5.5 million MWh for the three months ended June 30, 2008, to 5.9 million MWh for the three months ended June 30, 2009. The increase in volumes was primarily driven by lower natural gas prices and higher market heat rates at our Kendall and Ontelaunee facilities, partly offset by outages at our coal-fired facilities; and

Results were favorably impacted in 2008 by $7 million of sales of emission credits.

These items were partly offset by the following:

Decreased market prices – The average actual on-peak prices in the Cin Hub pricing region decreased from $77 per MWh for the three months ended June 30, 2008 to $34 per MWh for the three months ended June 30, 2009. Although the impact of lower market prices was partly offset by hedging, results were affected by lower realized prices; and

Increased operating expense – operating expenses increased from $47 million for the three months ended June 30, 2008 to $62 million for the three months ended June 30, 2009, primarily as a result of a planned outage at our Havana facility.

Depreciation expense increased from $52 million for the second quarter 2008 to $57 million for the second quarter 2009 as a result of capital projects placed into service during 2009. The capital projects were primarily related to Hennepin and Havana Baghouse projects.

In addition, we recorded an $18 million impairment of our Bluegrass power generating facility and related assets, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations. Please read Note 6—Impairment Charges for further discussion.

Power Generation—West Segment. Operating income for GEN-WE was $37 million for three months ended June 30, 2009, compared to a loss of $32 million for the three months ended June 30, 2008. Such amounts do not include results from our Heard County power generating facility, which has been reclassified as discontinued operations for all periods presented.

Revenues for the three months ended June 30, 2009 decreased by $36 million compared to the three months ended June 30, 2008, cost of sales decreased by $108 million and operating and maintenance expense decreased by $2 million, resulting in a net increase of $74 million. The increase was primarily driven by the following:

Mark-to-market gains – GEN-WE’s results for the three months ended June 30, 2009 included mark-to-market gains of $18 million, compared to $55 million of mark-to-market losses for the three months ended June 30, 2008. Of the $18 million in 2009 mark-to-market gains, $9 million related to positions that settled or will settle in 2009, and the remaining $9 million related to positions that will settle in 2010 and beyond; and

Increased tolling revenues of $5 million.

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These increases were partly offset by decreased volumes. Generated volumes were 1.3 million MWh for the three months ended June 30, 2009, down from 2.3 million MWh for the three months ended June 30, 2008. The volume decrease was driven in large part by decreased market spark spreads and reduced dispatch opportunities.

In May 2008, we sold our beneficial interest in Oyster Creek Limited for approximately $11 million, and recognized a gain on the sale of approximately $11 million, reflected in Gain on sale of assets in our unaudited condensed consolidated statements of operations. Please read Note 2—Dispositions and Discontinued Operations for further discussion.

Depreciation expense decreased from $24 million for the second quarter 2008 to $18 million for the second quarter 2009, largely as a result of an increase in the estimated useful life of one of our generation facilities.

Power Generation—Northeast Segment. Operating loss for GEN-NE was $382 million for the three months ended June 30, 2009, compared to an operating loss of $142 million for the three months ended June 30, 2008.

Revenues for the three months ended June 30, 2009 increased by $103 million compared to the three months ended June 30, 2008, cost of sales decreased by $45 million and operating and maintenance expense decreased by $1 million, resulting in a net increase of $149 million. The increase was primarily driven by the following:

Mark-to-market gains – GEN-NE’s results for the three months ended June 30, 2009 included mark-to-market gains of $8 million related to forward sales, compared to losses of $140 million for the three months ended June 30, 2008. Of the $8 million in 2009 mark-to-market gains, $15 million related to positions that settled or will settle in 2009, partly offset by $7 million of losses related to positions that will settle in 2010 and beyond; and

Increased volumes – Although on-peak market prices in New York Zone G, New York Zone A and Mass Hub decreased by 64 percent, 58 percent and 65 percent, respectively, spark spreads improved as a result of lower fuel prices resulting in higher volumes at our combined cycle facilities.

These items were partly offset by a coal inventory write-down of approximately $8 million recorded during the second quarter 2009.

Depreciation expense increased from $14 million for the second quarter 2008 to $16 million for the second quarter 2009.

In addition, we recorded a $179 million impairment of our Bridgeport power generating facility and related assets, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations. Furthermore, we recorded a $208 million impairment of our Roseton and Danskammer power generation facilities. Please read Note 6—Impairment Charge for further discussion.

Other. Dynegy’s and DHI’s other operating loss for the three months ended June 30, 2009 was $50 million, compared to an operating loss of $20 million for the three months ended June 30, 2008. Operating losses in both periods were comprised primarily of general and administrative expenses.

Operating and maintenance expense for the three months ended June 30, 2008 included a benefit from the release of $8 million of sales and use tax liability. Gain on sale of assets for the three months ended June 30, 2008 included an approximate $15 million gain related to our sale of our remaining NYMEX shares and both membership seats for approximately $16 million.

Consolidated general and administrative expenses were $45 million and $39 million for the three months ended June 30, 2009 and 2008, respectively.

Earnings (Losses) from Unconsolidated Investments

Dynegy’s earnings from unconsolidated investments were $13 million for the three months ended June 30, 2009, related to the GEN-WE investment in Sandy Creek. The $13 million consisted of $15 million mark-to-market gains primarily related to interest rate swap contracts partly offset by $2 million of financing costs. 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, partially offset by our share of the partnership’s losses. Please see Note 8—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.

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DHI’s earnings from unconsolidated investments of $13 million for the three months ended June 30, 2009 related to the GEN-WE investment in Sandy Creek. The $13 million consisted of $15 million mark-to-market gains primarily related to interest rate swap contracts partly offset by $2 million of financing costs. Earnings from unconsolidated investments for the three months ended June 30, 2008 were $3 million, related to the GEN-WE investment in Sandy Creek. 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 8—Variable Interest Entities—Sandy Creek for further discussion.

Other Items, Net

Dynegy’s and DHI’s other items, net, totaled $4 million and $3 million, respectively, of income for the three months ended June 30, 2009, compared to $15 million and $14 million, respectively, of income for the three months ended June 30, 2008. The decrease is primarily associated with lower interest income due to lower LIBOR rates in 2009.

Interest Expense

Dynegy’s and DHI’s interest expense totaled $98 million for the three months ended June 30, 2009, compared to $108 million for the three months ended June 30, 2008. The decrease was primarily attributable to lower LIBOR rates on our variable-rate debt in 2009.

Income Tax Benefit

Dynegy reported an income tax benefit from continuing operations of $209 million for the three months ended June 30, 2009, compared to an income tax benefit from continuing operations of $186 million for the three months ended June 30, 2008. The 2009 effective tax rate was 37 percent, compared to 41 percent in 2008.

DHI reported an income tax benefit from continuing operations of $220 million for the three months ended June 30, 2009, compared to an income tax benefit of $184 million from continuing operations for the three months ended June 30, 2008. The 2009 effective tax rate was 39 percent, compared to 41 percent in 2008.

As a result of the LS Power transaction, we revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore Dynegy and DHI recorded valuation allowances resulting in additional state tax expense of $10 million and $7 million, respectively for the three months ended June 30, 2009. For the period ended June 30, 2008, the difference between the effective rate of 41 percent for Dynegy and DHI, respectively and the statutory rate of 35 percent resulted primarily from the effect of state income taxes in the taxing jurisdictions in which our assets operate.

Discontinued Operations

Income From Discontinued Operations Before Taxes

During the three months ended June 30, 2009, our pre-tax income from discontinued operations was $10 million, related to the sale of the Heard County power generation facility.

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Income Tax (Expense) Benefit From Discontinued Operations

We recorded an income tax expense from discontinued operations of $4 million during the three months ended June 30, 2009, compared to an income tax benefit of less than $1 million during the three months ended June 30, 2008. These amounts reflect effective rates of 40 percent and zero 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.

Six Months Ended June 30, 2009 and 2008

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, 2009 and 2008, respectively:

Dynegy’s Results of Operations for the Six Months Ended June 30, 2009

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues	$	697		$	223		$	478		$	(1	)	$	1,397
Cost of sales		(261	)		(109	)		(296	)		—			(666	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(113	)		(64	)		(92	)		3			(266	)
Depreciation and amortization expense		(109	)		(40	)		(31	)		(6	)		(186	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above		(23	)		—			(387	)		—			(410	)
General and administrative expense		—			—			—			(83	)		(83	)
Operating income (loss)	$	115		$	(250	)	$	(425	)	$	(87	)	$	(647	)
Earnings from unconsolidated investments		—			20			—			1			21
Other items, net		2			2			—			4			8
Interest expense														(196	)

Loss from continuing operations before income taxes														(814	)
Income tax benefit														124

Loss from continuing operations														(690	)
Income from discontinued operations, net of taxes														7
Net loss														(683	)

Less: Net loss attributable to the noncontrolling interests														(3	)

Net loss attributable to Dynegy Inc.													$	(680	)

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

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues	$	230		$	306		$	329		$	—		$	865
Cost of sales		(261	)		(286	)		(368	)		8			(907	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(93	)		(62	)		(97	)		16			(236	)
Depreciation and amortization expense		(105	)		(47	)		(27	)		(5	)		(184	)
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		—			4			6			25			35
Interest expense														(217	)

Loss from continuing operations before income taxes														(708	)
Income tax benefit														282

Net loss														(426	)
Less: Net loss attributable to the noncontrolling interests														(2	)

Net loss attributable to Dynegy Inc.													$	(424	)

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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, 2009 and 2008, respectively:

DHI’s Results of Operations for the Six Months Ended June 30, 2009

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues	$	697		$	223		$	478		$	(1	)	$	1,397
Cost of sales		(261	)		(109	)		(296	)		—			(666	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(113	)		(64	)		(92	)		1			(268	)
Depreciation and amortization expense		(109	)		(40	)		(31	)		(6	)		(186	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above		(23	)		—			(387	)		—			(410	)
General and administrative expense		—			—			—			(83	)		(83	)
Operating income (loss)	$	115		$	(250	)	$	(425	)	$	(89	)	$	(649	)
Earnings from unconsolidated investments		—			20			—			—			20
Other items, net		2			2			—			3			7
Interest expense														(196	)

Loss from continuing operations before income taxes														(818	)
Income tax benefit														138

Loss from continuing operations														(680	)
Income from discontinued operations, net of taxes														7

Net loss														(673	)
Less: Net loss attributable to the noncontrolling interests														(3	)

Net loss attributable to Dynegy Holdings Inc.													$	(670	)

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

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total

Revenues	$	230		$	306		$	329		$	—		$	865
Cost of sales		(261	)		(286	)		(368	)		8			(907	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(93	)		(62	)		(97	)		16			(236	)
Depreciation and amortization expense		(105	)		(47	)		(27	)		(5	)		(184	)
Gain on sale of assets		—			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		—			4			6			24			34
Interest expense														(217	)

Loss from continuing operations before income taxes														(699	)
Income tax benefit														275

Net loss														(424	)
Less: Net loss attributable to the noncontrolling interests														(2	)

Net loss attributable to Dynegy Holdings Inc.													$	(422	)

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The following table provides summary segmented operating statistics for the six months ended June 30, 2009 and 2008, respectively:

	Six Months Ended June 30,
	2009			2008
GEN-MW
Million Megawatt Hours Generated		12.5			11.4
In Market Availability for Coal Fired Facilities (1)		88	%		86	%
Average Capacity Factor for Combined Cycle Facilities (2)		29	%		11	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	37		$	72
Commonwealth Edison (NI Hub)	$	36		$	71
PJM West	$	48		$	89
Average Market Spark Spreads ($/MWh) (4):
PJM West	$	12		$	11

GEN-WE
Million Megawatt Hours Generated (5) (6)		2.8			4.7
Average Capacity Factor for Combined Cycle Facilities (2)		23	%		38	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)	$	36		$	89
Palo Verde	$	32		$	81
Average Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)	$	5		$	18
Palo Verde	$	6		$	12

GEN-NE
Million Megawatt Hours Generated		5.3			3.6
In Market Availability for Coal Fired Facilities (1)		95	%		91	%
Average Capacity Factor for Combined Cycle Facilities (2)		44	%		23	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	53		$	110
New York—Zone A	$	39		$	71
Mass Hub	$	49		$	102
Average Market Spark Spreads ($/MWh) (4):
New York—Zone A	$	6		$	(3	)
Mass Hub	$	11		$	24
Fuel Oil	$	(31	)	$	(38	)

Average natural gas price—Henry Hub ($/MMBtu) (7)	$	4.13		$	9.95

_______

(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 us.

(4)

(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, 2009 and 2008, respectively.

(6)

Excludes less than 0.1 million MWh generated by our Calcasieu power generation facility for the six months ended June 30, 2008; we sold the facility on March 31, 2008.

(7)

Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

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The following table summarizes significant items on a pre-tax basis, with the exception of the tax items, affecting net loss for the period presented:

	Six Months Ended June 30, 2009
	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Impairments	$	(99	)	$	(260	)	$	(484	)	$	—		$	(843	)
Sandy Creek mark-to-market gains (1)		—			25			—			—			25
Discontinued operations (2)		—			11			—			—			11
Taxes		—			—			—			(15	)		(15	)

Total—DHI		(99	)		(224	)		(484	)		(15	)		(822	)
Taxes		—			—			—			(6	)		(6	)

Total—Dynegy	$	(99	)	$	(224	)	$	(484	)	$	(21	)	$	(828	)

____________

(1)

These mark-to-market gains represent our 50 percent share.

(2)

Discontinued operations includes a gain of $10 million on the sale of the Heard County power generation facility.

	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

Operating Loss

Operating loss for Dynegy was $647 million for the six months ended June 30, 2009, compared to operating loss of $514 million for the six months ended June 30, 2008. Operating loss for DHI was $649 million for the six months ended June 30, 2009, compared to operating loss of $514 million for the six months ended June 30, 2008.

Our operating loss for the six months ended June 30, 2009 was driven, in large part, by a $433 million impairment of goodwill and by $410 million of asset impairments. Please read Note 9—Goodwill for further discussion of the goodwill impairment and Note 6—Impairment Charges for further discussion of the asset impairments.

The impairments of goodwill and assets were partly offset by mark-to-market gains on forward sales of power associated with our generating assets which are included in Revenues in the unaudited condensed consolidated statements of operations. Such gains, which totaled $66 million for the six months ended June 30, 2009, were a result of a decrease in forward market power prices or forward spark spreads during the first half of 2009. These gains compared to $765 million of mark-to-market losses for the six months ended June 30, 2008, when forward market power prices increased during the period.

We do not designate our commodity derivative instruments as cash flow hedges for accounting purposes. Please read 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 a result, 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. Except for those positions that settled in the six months ended June 30, 2009, the expected cash impact of the settlement of these positions will be recognized over time largely 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.

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Power Generation—Midwest Segment. Operating income for GEN-MW was $115 million for the six months ended June 30, 2009, compared to an operating loss of $229 million for the six months ended June 30, 2008.

Revenues for the six months ended June 30, 2009 increased by $467 million compared to the six months ended June 30, 2008, cost of sales remained the same and operating and maintenance expense increased by $20 million, resulting in a net increase of $447 million. The increase was primarily driven by the following:

Mark-to-market gains – GEN-MW’s results for the six months ended June 30, 2009 included mark-to-market gains of $40 million related to forward sales, compared to $479 million of mark-to-market losses for the six months ended June 30, 2008. Of the $40 million in 2009 mark-to-market gains, $39 million related to positions that settled or will settle in 2009, and the remaining $1 million related to positions that will settle in 2010 and beyond;

Additional capacity sales of approximately $14 million, as a result of improved capacity prices for 2009 compared with 2008; and

Increased volumes – Generated volumes increased by 10 percent, from 11.4 million MWh for the six months ended June 30, 2008, to 12.5 million MWh for the six months ended June 30, 2009. The increase in volumes was primarily driven by lower natural gas prices and higher market heat rates at our Kendall and Ontelaunee facilities partially offset by outages at our coal fired facilities.

These items were partly offset by the following:

Decreased market prices – The average actual on-peak prices in the Cin Hub pricing region decreased from $72 per MWh for the six months ended June 30, 2008 to $37 per MWh for the six months ended June 30, 2009. Although the impact of lower market prices was partly offset by hedging, results were affected by lower realized prices;

Increased operating expense – operating expense increased from $93 million for the six months ended June 30, 2008 to $113 million for the six months ended June 30, 2009, primarily as a result of planned outages at our coal-fired generating facilities; and

Results from sales of emissions credits were $5 million for the six months ended June 30, 2009, compared with $11 million in the same period 2008.

Depreciation expense increased from $105 million for the six months ended June 30, 2008 to $109 million for the six months ended June 30, 2009.

Operating income for the six months ended June 30, 2009 included a pre-tax charge of approximately $76 million for the impairment of goodwill, reflected in Goodwill impairment in our unaudited condensed consolidated statements of operations. Please read Note 9—Goodwill for further discussion.

In addition, we recorded a $23 million impairment of our Bluegrass power generating facility and related assets, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations. Please read Note 6—Impairment Charges for further discussion.

Power Generation—West Segment. Operating loss for GEN-WE was $250 million for six months ended June 30, 2009, compared to a loss of $78 million for the six months ended June 30, 2008. Such amounts do not include results from our Heard County power generating facility, which have been classified as discontinued operations for all periods presented.

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Revenues for the six months ended June 30, 2009 decreased by $83 million compared to the six months ended June 30, 2008, cost of sales decreased by $177 million and operating and maintenance expense increased by $2 million, resulting in a net increase of $92 million. The increase was primarily driven by the following:

Reduced mark-to-market losses – GEN-WE’s results for the six months ended June 30, 2009 included mark to-market losses of $11 million, compared to $102 million of mark-to-market losses for the six months ended June 30, 2008. Of the $11 million in 2009 mark-to-market losses, $9 million related to positions that settled or will settle in 2009, and the remaining $2 million related to positions that will settle in 2010 and beyond; and

Increased tolling revenues of $9 million.

These increases were partly offset by decreased volumes. Generated volumes were 2.8 million MWh for the six months ended June 30, 2009, down from 4.7 million MWh for the six months ended June 30, 2008. The volume decrease was driven in large part by decreased market spark spreads and reduced dispatch opportunities.

Depreciation expense decreased from $47 million for the six months ended June 30, 2008 to $40 million for the six months ended June 30, 2009, largely as a result of an increase in the estimated useful life of one of our generation facilities.

Operating loss for the six months ended June 30, 2009 included a pre-tax charge of approximately $260 million for the impairment of goodwill, reflected in Goodwill impairment in our unaudited condensed consolidated statements of operations. Please read Note 9—Goodwill for further discussion.

Power Generation—Northeast Segment. Operating loss for GEN-NE was $425 million for the six months ended June 30, 2009, compared to an operating loss of $163 million for the six months ended June 30, 2008.

Revenues for the six months ended June 30, 2009 increased by $149 million compared to the six months ended June 30, 2008, cost of sales decreased by $72 million and operating and maintenance expense decreased by $5 million, resulting in a net increase of $226 million. The increase was primarily driven by the following:

Mark-to-market gains – GEN-NE’s results for the six months ended June 30, 2009 included mark-to-market gains of $37 million related to forward sales, compared to losses of $184 million for the six months ended June 30, 2008. Of the $37 million in 2009 mark-to-market gains, $38 million related to positions that settled or will settle in 2009, partly offset by $1 million of losses related to positions that will settle in 2010 and beyond;

Increased volumes – Although on-peak market prices in New York Zone G, New York Zone A and Mass Hub decreased by 52 percent, 46 percent and 52 percent, respectively, spark spreads improved as a result of lower fuel prices resulting in higher volumes at each of our non-coal fired facilities; and

Results were favorably impacted in 2009 by $11 million sale of emission credits. Similar sales of $2 million occurred in 2008.

These items were partly offset by a coal inventory write-down of approximately $10 million recorded during the six months ended 2009.

Depreciation expense increased from $27 million for the six months ended June 30, 2008 to $31 million for the six months ended June 30, 2009.

Operating loss for the six months ended June 30, 2009 included a pre-tax charge of approximately $97 million for the impairment of goodwill, reflected in Goodwill impairment in our unaudited condensed consolidated statements of operations. Please read Note 9—Goodwill for further discussion.

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In addition, we recorded a $179 million impairment of our Bridgeport power generating facility and related assets, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations. We also recorded a $208 million impairment of our Roseton and Danskammer power generation facilities and related assets. Please read Note 6—Impairment Charges for further discussion.

Other. Dynegy’s other operating loss for the six months ended June 30, 2009 was $87 million, compared to an operating loss of $44 million for the six months ended June 30, 2008. DHI’s other operating loss for the six months ended June 30, 2009 was $89 million, compared to an operating loss of $44 million for the six months ended June 30, 2008. Operating losses in both periods were comprised primarily of general and administrative expenses.

Cost of sales for the six months ended June 30, 2008 included a benefit from the release of a $9 million liability associated with an assignment of a natural gas transportation contract. Operating and maintenance expense for the six months ended June 30, 2008 included a benefit from the release of $16 million of sales and use tax liability. Gain on sale of assets for the three months ended June 30, 2008 included an approximate $15 million gain related to our sale of our remaining NYMEX shares and both membership seats for approximately $15 million.

Consolidated general and administrative expenses increased from $78 million from the six months ended June 30, 2008 to $83 million for the six months ended June 30, 2009, as result of higher professional and legal fees.

Earnings (Losses) from Unconsolidated Investments

Dynegy’s earnings from unconsolidated investments were $21 million for the six months ended June 30, 2009 of which $20 related to the GEN-WE investment in Sandy Creek. The $20 million consisted of $25 million mark-to-market gains primarily related to interest rate swap contracts offset by $5 million of financing costs. 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 8—Variable Interest Entities—Sandy Creek for further discussion. The remaining $10 million loss related to its investment in DLS Power Development, included in Other.

DHI’s earnings from unconsolidated investments of $20 million for the six months ended June 30, 2009 related to the GEN-WE investment in Sandy Creek. The $20 million consisted of $25 million mark-to-market gains primarily related to interest rate swap contracts offset by $5 million of financing costs. Losses from unconsolidated investments for the six months ended June 30, 2008 were $2 million. 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 8—Variable Interest Entities—Sandy Creek for further discussion.

Other Items, Net

Dynegy’s and DHI’s other items, net, totaled $8 million and $7 million, respectively, of income for the six months ended June 30, 2009, compared to $35 million and $34 million, respectively, of income for the six months ended June 30, 2008. The decrease is primarily associated with lower interest income due to lower LIBOR rates in 2009. 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.

Interest Expense

Dynegy’s and DHI’s interest expense totaled $196 million for the six months ended June 30, 2009, compared to $217 million for the six months ended June 30, 2008. The decrease was primarily attributable to lower LIBOR rates on our variable-rate debt in 2009.

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Income Tax Benefit

Dynegy reported an income tax benefit from continuing operations of $124 million for the six months ended June 30, 2009, compared to an income tax benefit from continuing operations of $282 million for the six months ended June 30, 2008. The 2009 effective tax rate was 15 percent, compared to 40 percent in 2008.

DHI reported an income tax benefit from continuing operations of $138 million for the six months ended June 30, 2009, compared to an income tax benefit of $275 million from continuing operations for the six months ended June 30, 2008. The 2009 effective tax rate was 17 percent, compared to 39 percent in 2008.

The primary difference between the effective rates of 15 and 17 percent for Dynegy and DHI, respectively, for the six months ended June 30, 2009 and the statutory rate of 35 percent resulted from the effect of the nondeductible goodwill impairment charge. Additionally, for the six months ended June 30, 2009, Dynegy and DHI recorded $21 million and $15 million, respectively, of income tax expense related to a change in California state tax law. As a result of the LS Power transaction, we revised our assumptions around the ability to utilize certain state deferred tax assets, and therefore Dynegy and DHI recorded valuation allowances resulting in additional state tax expense of $10 million and $7 million, respectively for the six months ended June 30, 2009. For the period ended June 30, 2008, the difference between the effective rates of 40 and 39 percent for Dynegy and DHI, respectively and the statutory rate of 35 percent resulted primarily from the effect of state income taxes in the taxing jurisdictions in which our assets operate.

Discontinued Operations

Income (Loss) From Discontinued Operations Before Taxes

During the six months ended June 30, 2009, our pre-tax income from discontinued operations was $11 million, primarily related to the sale of the Heard County power generation facility. During the six months ended June 30, 2008, our pre-tax loss from discontinued operations was $1 million, related to a loss on the sale of the Calcasieu power generation facility.

Income Tax (Expense) Benefit From Discontinued Operations

We recorded an income tax expense from discontinued operations of $4 million during the six months ended June 30, 2009, compared to an income tax benefit of $1 million during the six months ended June 30, 2008. These amounts reflect effective rates of 36 percent and 100 percent, respectively. The detailed methodology of allocating income taxes between continuing and discontinued operations often results in an effective rate for discontinued operations significantly different from the statutory rate of 35 percent.

Outlook

On August 9, 2009, we entered into a purchase and sale agreement with LS Power in which we agreed: (i) to sell our ownership interests in 4,788 MW of peaking and combined-cycle power generation assets, as well as our remaining noncontrolling interests in the Sandy Creek Project under construction in Texas and (ii) to issue $235 million principal amount of DHI 7.50 percent senior unsecured notes due 2015. We will receive $1.025 billion in cash (consisting, in part, of $175 million of restricted cash on our unaudited condensed consolidated balance sheets to be released to Dynegy from the Sandy Creek restricted account) and 245 million of Dynegy’s Class B shares from LS Power.

Upon closing of the transaction, which is expected to occur during the second half of 2009 subject to receipt of required regulatory approvals, the remaining 95 million shares of Dynegy’s Class B common stock held by LS Power will be converted into an equivalent number of shares of Dynegy’s Class A common stock, representing approximately 15 percent of Dynegy’s outstanding Class A common stock. Concurrent with the execution of the purchase and sale agreement, LS Power and Dynegy entered into a new Shareholder Agreement, which, upon closing of the transaction, generally will restrict LS Power from increasing their future ownership above 15 percent for a specified period and eliminate special approval, board representation and certain other rights associated with the former Class B common shares. Please see Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further information.

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This agreement is intended to accomplish a number of objectives. We have agreed to receive a substantial block of our stock at an attractive value, eliminating the dual class stock structure and associated rights and restrictions. In addition, the proposed transaction will enhance our liquidity and position us to significantly reduce upcoming debt maturities, all while maintaining a large and diverse asset portfolio with leverage to both prices and demand as power markets recover. Further, we believe this transaction gives us the strategic and financial flexibility to capitalize on opportunities to further enhance stockholder value.

We will maintain a strategic core portfolio of operating assets that is diverse in terms of fuel, geography and dispatch. Through these baseload and natural gas combined-cycle assets, we believe the fleet continues to be positioned to offer upside potential as power markets recover. The generation assets being sold to LS Power include five peaking facilities (Riverside and Bluegrass in Kentucky, Rocky Road and Tilton in Illinois, and Renaissance in Michigan) as well as three combined-cycle facilities (Arlington and Griffith in Arizona, and Bridgeport in Connecticut). Following the transaction, we will continue to benefit from a low-cost, well-operated and diversified asset portfolio that consists of almost 13,000 MW of generating capacity in seven U.S. states, with 34 percent being natural gas-fired combined-cycle capacity, 25 percent natural gas-fired peaking capacity and 31 percent baseload coal/fuel oil and 10 percent dual fuel. We will also maintain significant scale in key markets, with 43 percent of the company’s portfolio located in the Midwest, 32 percent in the West and 25 percent in the Northeast.

In commercializing our assets, we seek to achieve a balance between providing greater cash flow predictability in the near/intermediate term, while maintaining the ability to capture value longer term as markets tighten. We expect that a majority of our revenues will be achieved by selling energy and capacity through a combination of spot market sales and near-term contracts over a rolling 12–36 month time frame in time periods that we describe as Current, Current +1, and Current +2. At any given point in time, we will seek to balance predictability of earnings and cash flow with achieving the highest level of earnings and cash flow possible over the Current, Current +1 and Current +2 periods. In these periods, we understand that short-term market volatility can negatively impact our profitability, and we will seek to reduce those negative impacts through the disciplined use of near- and intermediate-term forward sales. As a result, our fleet-wide forward sales profile is fluid and subject to change. We expect to make fewer forward sales beyond the Current+2 period in order to realize the anticipated benefit of improved market prices over time as the supply and demand balance tightens.

We expect that our future financial results will continue to be sensitive to fuel and commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and IMA. Our commercial team actively manages commodity price risk associated with our unsold power production by trading in the forward markets 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.

Currently, substantially all of our expected generation for 2009 is contracted. As we look forward to 2010 and beyond, we are actively hedging and expect to enter 2010 with approximately 95 percent of the expected output of our fleet contracted for that year. Our largely uncontracted position for the periods beyond 2010 will provide for greater value capture opportunities when energy pricing and demand is expected to recover. Based on specific market conditions, at any point in time we may enter into transactions that will increase or decrease the portion of our expected output that has been contracted, since we actively manage our near-term market positions of less than three years.

To the extent that we choose not to enter into forward transactions, 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 the outlook of each of our three regions.

GEN-MW. Our Midwest Consent Decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. We have achieved all emission reductions scheduled to date under the Midwest Consent Decree and are in the process of installing additional emission control equipment to meet future Midwest 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 $430 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. If the costs of these capital expenditures become great enough to render the operation of the affected facility or facilities uneconomical, we could, at our option, cease to operate the facility or facilities and forego these capital expenditures without incurring any further obligations under the Midwest Consent Decree.

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Our Midwest coal and transportation requirements are 100 percent contracted through 2010. For 2009, the prices associated with these contracts are fixed. For 2010, approximately 25 percent of our coal requirements are unpriced and will be negotiated in the third quarter 2009, becoming effective January 1, 2010. We expect that any price changes will be consistent with the generally decreasing price trends as coal markets retreat from their historical highs of mid 2008.

More wind generation has come online in the Midwest, resulting in a increase in minimum generation events. During these events, baseload generation may shut down or run at minimum loads. As additional wind generation enters the grid, these events will occur more frequently. As we are substantially hedged for 2009 and 2010, minimum generation events are not expected to significantly impact our financial results over the next 12 months.

We were successful in capturing up to 1,150 MWs of load in FirstEnergy Ohio Utilities’ Competitive Auction for power supply for their Standard Service Offer customers for a two year period beginning in June 2009. The auction clearing price was $61.50/MWh. The volumes we ultimately sell under this program will be dependent on the load requirements of the SSO customers participating in the program. We have participated, and expect to continue to participate in PJM’s future forward capacity auctions when they occur.

GEN-WE. Approximately two-thirds of Dynegy’s power plant capacity in the West is contracted under a variety of tolling agreements with load-serving entities and RMR agreements with the Cal ISO. A significant portion of the remaining capacity is sold as a Resource Adequacy product in the California market, and much of the expected production associated with our plants without tolls or RMR agreements has been financially hedged.

Our South Bay power generation facility is operating under an RMR agreement with the Cal ISO through December 31, 2009. The ISO is currently evaluating future RMR needs, and we expect to learn early in the fourth quarter 2009 whether the facility will receive RMR designation for 2010.

GEN-NE. We continue to maintain sufficient coal and fuel oil inventories to manage our operations effectively. We have contracted 100 percent and approximately 65 percent of our expected coal supply and freight requirements for 2009 and 2010, respectively, for our Danskammer power generation facility, primarily from South American suppliers. Multiple sourcing options are available and under evaluation for the remainder of our 2010 supply needs. Coal prices in both the international and domestic markets have retreated from their historic highs reached in the middle of 2008. We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable fuel supplies and to mitigate further supply risks for near and long-term coal supplies.

The volatility in fuel oil and natural gas commodity pricing and changes to spark spreads may provide us opportunities to capture additive short-term market value through strategic purchases of fuel oil and sales of power in the spot or forward markets. We believe lower commodity prices of fuel oil and natural gas compared to historic highs we experienced in 2008 will position our Roseton facility, which is capable of burning natural gas and fuel oil, to capture these market opportunities to the extent they occur.

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 ICAP 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 will gradually rise to $4.10/KW-month through September 1, 2010, when the forward capacity market will be fully effective. Capacity auctions for the 2010/2011 and 2011/2012 were held in 2008 and resulted in capacity payments of $4.50 KW/month and $3.60 KW/month respectively for our assets in ISO-NE.

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Environmental Matters

Climate Change and Greenhouse Gases. For the last several years, there has been an ongoing public debate about climate change and the need to and potential for addressing the climate change issue by reducing emissions of GHGs, primarily CO2 and methane. Our position is that since climate change is a global issue, any regulation of GHG emission sources in the United States should be undertaken by the federal government in coordination with developed and developing countries around the world. We believe that the focus of any federal program addressing climate change should include three critical, interrelated elements: the environment, the economy and energy security.

Several regulatory initiatives and actions are being developed or implemented that address GHG emissions. On March 10, 2009, the Administrator of the U.S. EPA issued a proposed rule to require mandatory reporting of GHG emissions from all sectors of the economy. The rule would require that sources above certain threshold levels monitor and report GHG emissions. Our electric generating facilities will be subject to these new requirements if the reporting rule becomes final. On April 17, 2009, the Administrator of the U.S. EPA issued a proposed finding that GHG emissions from mobile sources cause or contribute to air pollution that endangers the public health and welfare. The endangerment finding was proposed under Section 202(a) of the CAA in response to the U.S. Supreme Court’s ruling in Massachusetts v. EPA, 549 U.S. 497 (2007) that GHGs are pollutants as defined in the CAA. If the proposal becomes final, the U.S. EPA will be required to promulgate GHG emission standards under the CAA for GHGs emitted by mobile sources. On June 30, 2009, the Administrator of U.S. EPA granted California’s request for a waiver to allow the state to enforce its motor vehicle GHG emission regulations. The California motor vehicle GHG emission regulations establish manufacturer fleet average emission standards for passenger cars and light trucks, and for heavier trucks phased in from 2009 through 2016. In granting the waiver, the Administrator declined to address whether her action renders GHGs “subject to regulation” under the CAA. If GHGs become “subject to regulation” under the CAA as a result of either the endangerment finding or the California waiver, they may become subject to other sections of the CAA including the best available control technology requirements under the prevention of significant deterioration provisions.

The federal government, and many states where we have generation facilities, are considering or are in some stage of implementing regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change issues. Beginning in 2009, certain of our generating facilities were required to obtain CO2 allowances, through purchases from the states where they operate, in sufficient quantity to cover CO2 emissions. We do not know yet the extent to which the costs of obtaining CO2 allowances and of meeting mandated emission reductions may be borne by power generators or the ultimate users of electricity. The imposition of limits on emissions of CO2, and equivalents from the power generation sector, whether implemented by the federal or state governments, could have the effect of altering the manner in which generating facilities are dispatched.

On June 26, 2009 the U.S. House of Representatives passed the American Clean Energy and Security Act of 2009(“ACES”). Title III of ACES would add a new Title VII to the CAA creating a Global Warming Pollution Reduction Program. ACES would create a national cap-and-trade program aimed at reducing CO2 emissions to 3 percent below 2005 levels by 2012, 17 percent below 2005 levels by 2020, 42 percent below 2005 levels by 2030 and 83 percent below 2005 levels by 2050. President Obama supports the cap-and-trade program and the U.S. Senate is expected to consider a similar legislative proposal in the autumn of 2009. ACES represents a comprehensive effort to restructure the energy market in the United States. Such significant mandatory reductions of GHG emissions from the electric generating sector aimed at addressing climate change, the nature of which cannot be predicted with confidence at this time, could have a material adverse effect on our financial condition, results and cash flows.

GEN-WE. Our assets in California will be subject to various additional state environmental initiatives. As previously disclosed, our California facilities continue to be subject to the California Global Warming Solutions Act, effective January 1, 2007, which requires development of a GHG control program that will reduce the state’s GHG emissions to their 1990 levels by 2020. Regulations to achieve required emission reductions are to be adopted by January 2011.

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GEN-NE. Effective January 1, 2009, our GEN-NE segment facilities in New York, Connecticut and Maine became subject to compliance requirements under the RGGI program. The participating RGGI states have implemented a rule regulating GHG emissions using a cap-and-trade program to reduce CO2 emissions by at least 10 percent of base-year emission levels by the year 2018. Compliance with the allowance requirement under the RGGI cap-and-trade program can be achieved by reducing emissions, purchasing or trading allowances or securing offset allowances from an approved offset project.

On June 17, 2009, RGGI held its fourth auction, in which approximately 31 million allowances for allocation year 2009, and over two million allowances for allocation year 2012, were sold at clearing prices of $3.23 per allowance and $2.06 per allowance, respectively. We have participated in each of the quarterly RGGI auctions (or in secondary markets, as appropriate) to secure allowances based on our actual or forecast needs for our affected assets. Auctions are expected to be held quarterly, with the fifth auction scheduled for September 2009.

We project that 2009 CO2 emissions from our generating facilities in New York, Maine and Connecticut will be approximately 5.5 million tons. Therefore, based on the average cost of allowances sold to date for the 2009 allocation year, our estimated cost of allowances necessary to operate these facilities in 2009 would be approximately $19 million.

Coal Combustion Ash. The combustion of coal to generate electric power creates large quantities of ash which is managed at power generation facilities in dry form in landfills and in liquid or slurry form in surface impoundments. Each of our coal-fired plants has at least one CCA management unit. At present, CCA management is regulated by the states as solid waste. The U.S. EPA has considered whether CCA should be regulated as a hazardous waste on two separate occasions and each time has declined to do so. In 1993, the agency determined that CCA that is managed separately from other wastes should not be regulated as a hazardous waste. In 2000, the agency determined that CCA that is co-managed with certain low-volume non-combustion wastes also should not be regulated as a hazardous waste. The December 2008 failure of a CCA surface impoundment dike at the Tennessee Valley Authority’s Kingston Plant in Tennessee, accompanied by a very large release of ash slurry, has resulted in renewed scrutiny of CCA management. The U.S. EPA has initiated an investigation of the structural integrity of certain CCA surface impoundment dams and has announced plans to develop regulations by the end of 2009 to address the management of CCA. Certain environmental non-government organizations have advocated designation of CCA as a hazardous waste. The regulations being developed by the U.S. EPA could lead to new requirements related to CCA management units, the nature of which cannot be predicted with confidence at this time, but which could have a material adverse effect on our financial condition, results of operations and cash flows.

Regulatory Matters

GEN-MW. Our market-based rate authority is predicated on a finding by FERC that our entities with market-based rates do not have market power, and a market power analysis is generally conducted every three years for each region on a rolling basis (“triennial market power review”). The triennial market power review for our MISO assets was filed with FERC in June 2009. On December 24, 2008, we filed the triennial market power review for our assets in FERC’s Southeast Region. In August 2009, FERC issued a letter order accepting our filing and stating that our Submittal satisfies its requirements for market-based rates regarding horizontal and vertical market power in this region.

In the electricity markets run by MISO, RSG charges are incurred when real-time energy demand exceeds prescheduled energy (in the day ahead market) and MISO is required to dispatch generation to make up the difference. The generators committed to serve this excess real-time energy demand are compensated for start-up and energy production costs via RSG make whole payments. RSG make whole payments are collected and funded by MISO primarily though RSG charges assessed against certain market participants.

During the past quarter, there were two active FERC proceedings addressing RSG cost allocation methodology and MISO’s application of that methodology. FERC issued two orders that effectively reversed or clarified prior decisions requiring MISO to engage in large-scale market resettlement charges. However, certain market participants may seek to appeal one or both of the orders.

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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, 2009
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at January 1, 2009	$	(30	)
Risk-management gains recognized through the income statement in the period, net		262
Cash received related to risk-management contracts settled in the period, net		(188	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		122

Fair value of portfolio at June 30, 2009	$	166

__________________

(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 asset of $166 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.

Risk-Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of June 30, 2009, based on our valuation methodology:

Net Fair Value of Risk-Management Portfolio

	Total		2009		2010		2011			2012			2013			Thereafter
	(in millions)
Market quotations (1)	$	123	$	182	$	14	$	(17	)	$	(9	)	$	(6	)	$	(41	)
Prices based on models		43		35		22		(18	)		1			1			2

Total (2)	$	166	$	217	$	36	$	(35	)	$	(8	)	$	(5	)	$	(39	)

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(1)

Prices obtained from actively traded, liquid markets for commodities.

(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 5—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 and expectations regarding the transaction with LS Power and its associated benefits and future asset impairments and charges related to such transaction;

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beliefs regarding savings expectations and cost reductions in capital expenditures, operations and maintenance and corporate general and administrative expenditures;

beliefs about commodity pricing and generation volumes;

beliefs and assumptions relating to liquidity, available borrowing capacity and capital resources generally;

expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential legislation and regulations, including those relating to climate change and GHGs;

sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation;

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

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

beliefs and assumptions about weather and general economic conditions;

beliefs regarding the current economic downturn, its trajectory and its impacts;

beliefs and expectations associated with minimum generation events in the Midwest;

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

beliefs and assumptions regarding our liquidity needs and the credit markets and our access thereto;

beliefs and expectations regarding financing, development and timing of the Sandy Creek and Plum Point projects;

expectations regarding our revolver capacity, collateral demands, 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 capital and maintenance expenditures, including the Midwest Consent Decree and its 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 and Item 1A-Risk Factors of our Form 10-K.

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” in our Form 10-K for a complete description of our critical accounting policies, with respect to which there have been no material changes since the filing of such Form 10-K.

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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 our 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, 2009.

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. The increase in the June 30, 2009 VaR was primarily due to increased forward sales as compared to December 31, 2008. Please read “Value at Risk” in our Form 10-K for a complete description of our valuation methodology.

Daily and Average VaR for Risk-Management Portfolios

	June 30, 2009		December 31, 2008
	(in millions)
One day VaR—95 percent confidence level	$	27	$	21
One day VaR—99 percent confidence level	$	38	$	29
Average VaR for the year-to-date period—95 percent confidence level	$	31	$	42

Credit Risk. The following table represents our credit exposure at June 30, 2009 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary

	Investment Grade Quality		Non-Investment Grade Quality		Total
	(in millions)
Type of Business:
Financial institutions	$	138	$	—	$	138
Utility and power generators		19		7		26
Commercial, industrial and end users		2		4		6
Other		2		5		7

Total	$	161	$	16	$	177

Of the $16 million in credit exposure to non-investment grade counterparties, none is collateralized or subject to other credit exposure protection.

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of June 30, 2009, our fixed rate debt instruments, as a percentage of total debt instruments, were approximately 74 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 portfolio as of June 30, 2009, 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, 2010 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, 2009 and December 31, 2008, respectively:

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Absolute Notional Contract Amounts

	June 30, 2009		December 31, 2008
Cash flow hedge interest rate swaps (in millions of U.S. dollars)	$	511	$	471
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 on swaps (percent)		5.35		5.35
Interest rate risk-management contract (in millions of U.S. dollars)	$	206	$	206
Fixed interest rate received on swaps (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 Dynegy’s and DHI’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended). This evaluation included consideration of the various processes carried out under the direction of Dynegy’s and DHI’s disclosure committee. This evaluation also considered the work completed 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 Dynegy’s and DHI’s disclosure controls and procedures were effective as of June 30, 2009.

Changes in Internal Controls Over Financial Reporting

There were no changes in Dynegy’s and DHI’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect Dynegy’s and DHI’s internal control over financial reporting during the quarter ended June 30, 2009.

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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 13—Commitments and Contingencies—Legal Proceedings to the accompanying unaudited condensed consolidated financial statements for a discussion of the legal proceedings that we believe could be material to us.

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

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

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

Upon vesting of restricted stock awarded by 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 1-30		98,089	$	1.59		—		N/A
May 1-31		—	$	—		—		N/A
June 1-30		—	$	—		—		N/A

Total		98,089	$	1.59		—		N/A

These were the only purchases of equity securities made by us during the three months ended June 30, 2009. Dynegy does not have a stock repurchase program.

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

Dynegy’s 2009 annual meeting of stockholders was held on May 22, 2009. The purpose of the annual meeting was to consider and vote upon the following proposals:

To elect eight Class A common stock directors and three Class B common stock directors to serve until the 2010 annual meeting of stockholders;

To act upon a proposal to ratify the appointment of Ernst & Young LLP as Dynegy’s independent registered public accountants for the fiscal year ending December 31, 2009; and

To act upon a stockholder proposal regarding greenhouse gas emissions.

Dynegy’s 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 Dynegy’s 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:

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Class A Directors

		FOR		WITHHELD
1.	David W. Biegler		386,949,283		36,279,440
2.	Thomas D. Clark, Jr.		404.128,553		19,100,170
3.	Victor J. Grijalva		388,438,779		34,789,944
4.	Patricia A. Hammick		404,639,347		18,589,377
5.	George L. Mazanec		386,929,357		36,299,366
6.	Howard B. Sheppard		386,886,955		36,341,769
7.	William L. Trubeck		387,556,553		35,672,170
8.	Bruce A. Williamson		402,029,590		21,199,134

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 Dynegy’s independent registered public accountants for the fiscal year ending December 31, 2009, which passed. There were no broker non-votes.

	FOR		AGAINST		ABSTAIN
	758,895,465		3,279,386		1,004,985

The following votes were cast with respect to the stockholder proposal regarding greenhouse gas emissions, which failed to pass. There were 106,104,803 broker non-votes.

	FOR		AGAINST		ABSTAIN
	106,237,047		510,689,821		40,197,053

Table of Contents

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

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

Exhibit Number		Description
2.1		—Plan of Merger, Contribution and Sale Agreement, dated September 14, 2006 by and among Dynegy Inc., LSP Gen Investors, LP, LS Power Partners, LP, LS Power Equity Partners PIE I, L.P., LS Power Equity Partners, L.P., LS Power Associates, L.P., Falcon Merger Sub Co. and Dynegy Acquisition, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).
2.2		—Limited Liability Company Membership Interests and Stock Purchase Agreement, dated as of September 14, 2006, among LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P., LS Power Partners, L.P. and Kendall Power LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).
2.3		—Dissolution Agreement by and between Dynegy Inc. and LS Power Associates, L.P., effective January 1, 2009.
3.1		—Amended and Restated Certificate of Incorporation of Dynegy Inc. (formerly named Dynegy Acquisitions, Inc.) (incorporated by reference to Exhibit 4.1 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-141810).
3.2		—Amended and Restated Bylaws of Dynegy Inc. (formerly named Dynegy Acquisitions, Inc.) (incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-8 of Dynegy Inc. filed on April 2, 2007, File No. 333-141810).
3.3		—Restated Certificate of Incorporation of Dynegy Holdings Inc. (incorporated by reference to Exhibit 3.1 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Holdings Inc., File No. 000-29311).
3.4		—Amended and Restated Bylaws of Dynegy Holdings Inc. (incorporated by reference to Exhibit 3.2 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Holdings Inc., File No. 000-29311).
4.1		—Subordinated Debenture Indenture between NGC Corporation and The First National Bank of Chicago, as Debenture Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).
4.2		—Amended and Restated Declaration of Trust among NGC Corporation, Wilmington Trust Company, as Property Trustee and Delaware Trustee, and the Administrative Trustees named therein, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).
4.3		—Series A Capital Securities Guarantee Agreement executed by NGC Corporation and The First National Bank of Chicago, as Guarantee Trustee, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).
4.4		—Common Securities Guarantee Agreement of NGC Corporation, dated as of May 28, 1997 (incorporated by reference to Exhibit 4.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).

Table of Contents

Exhibit Number		Description
4.5		—Registration Rights Agreement, dated as of May 28, 1997, among NGC Corporation, NGC Corporation Capital Trust I, Lehman Brothers, Salomon Brothers Inc. and Smith Barney Inc. (incorporated by reference to Exhibit 4.11 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 1997 of NGC Corporation, File No. 1-11156).
4.6		—Indenture, dated as of September 26, 1996, restated as of March 23, 1998, and amended and restated as of March 14, 2001, between Dynegy Holdings Inc. and Bank One Trust Company, National Association, as Trustee (incorporated by reference to Exhibit 4.17 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2000 of Dynegy Holdings Inc., File No. 000-29311).
4.7		—First Supplemental Indenture, dated July 25, 2003 to that certain Indenture, dated as of September 26, 1996, between Dynegy Holdings Inc. and Wilmington Trust Company, as trustee (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on July 28, 2003, File No. 1-15659).
4.8		—Second Supplemental Indenture, dated as of April 12, 2006, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 12, 2006, File No. 1-15659).
4.9		—Third Supplemental Indenture, dated as of May 24, 2007, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003, and that certain Second Supplemental Indenture, dated as of April 12, 2006 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311).
4.10		—Fourth Supplemental Indenture, dated as of May 24, 2007, to that certain Indenture, originally dated as of September 26, 1996, as amended and restated as of March 23, 1998 and again as of March 14, 2001, by and between Dynegy Holdings Inc. and Wilmington Trust Company (as successor to JPMorgan Chase Bank, N.A.), as trustee, as supplemented by that certain First Supplemental Indenture, dated as of July 25, 2003, that certain Second Supplemental Indenture, dated as of April 12, 2006, and that certain Third Supplemental Indenture, dated as of May 24, 2007 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311).
4.11		—Registration Rights Agreement, effective as of July 21, 2006, by and among Dynegy Holdings Inc. RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659).
4.12		—Registration Rights Agreement, dated as of May 24, 2007, by and among Dynegy Holdings Inc. and the several initial purchasers party thereto (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311).

Table of Contents

Exhibit Number		Description
4.13		—Trust Indenture, dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.22 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659).
4.14		—First Supplemental Indenture, dated as of January 1, 1993, to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and IBJ Schroder Bank & Trust Company, as Trustee (incorporated by reference to Exhibit 4.23 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659).
4.15		—Second Supplemental Indenture, dated as of October 23, 2001, to the Trust Indenture dated as of January 1, 1993, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and The Bank of New York, as Trustee (incorporated by reference to Exhibit 4.24 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2004 of Dynegy Inc, File No. 1-15659).
4.16		—Global Note representing the 9.00 percent Secured Bonds due 2013 of Sithe/Independence Power Partners, L.P. (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2005 of Dynegy Inc., File No. 1-15659).
4.17		—Shareholder Agreement, dated as of September 14, 2006, among Dynegy Acquisition, Inc. and LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).
4.18		—Registration Rights Agreement, dated as of September 14, 2006, among Dynegy Acquisition, Inc., LS Power Partners, L.P., LS Power Associates, L.P., LS Power Equity Partners, L.P., LS Power Equity Partners PIE I, L.P. and LSP Gen Investors, L.P. (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).
4.19		—Lock-Up Agreement, dated as of September 14, 2006, by and among LSP Gen Investors, LP, LS Power Partners, LP, LS Power Associates, L.P., LS Power Equity Partners PIE I, LP, LS Power Equity Partners, L.P. and Chevron U.S.A. Inc. (incorporated by reference to Exhibit 4.5 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).
4.20		—Trust Indenture, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Regions Bank, as trustee (incorporated by reference to Exhibit 10.13 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311).
4.21		—First Supplemental Trust Indenture dated as of April 24, 2007, by and between the City of Osceola, Arkansas and Regions Bank, as trustee (incorporated by reference to Exhibit 10.28 to the Annual Report on Form 10-K of Dynegy Holdings Inc. filed on February 28, 2008, File No. 000-29311).
4.22		—Purchase Agreement, dated August 1, 2003, among Dynegy Inc., Dynegy Holdings Inc. and the initial purchasers named therein (incorporated by reference to Exhibit 10.9 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).
4.23		—Purchase Agreement, dated August 1, 2003, among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 10.10 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended June 30, 2003 of Dynegy Inc., File No. 1-15659).

Table of Contents

Exhibit Number		Description
4.24		—Purchase Agreement, dated September 30, 2003, among Dynegy Holdings Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 15, 2003, File No. 1-15659).
4.25		—Purchase Agreement, dated as of March 29, 2006, for the sale of $750,000,000 aggregate principal amount of the 8.375 percent Senior Unsecured Notes due 2016 of Dynegy Holdings Inc. among Dynegy Holdings Inc. and the several initial purchasers named therein (incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2006 of Dynegy Inc., File No. 1-15659).
4.26		—Purchase Agreement, dated as of May 17, 2007, by and between Dynegy Holdings Inc. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for Quarterly Period Ended June 30, 2007 of Dynegy Holdings Inc., File No. 000-29311).
4.27		—Exchange Agreement, dated as of July 21, 2006, by and among Dynegy Holdings Inc., RCP Debt, LLC and RCMF Debt, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on July 24, 2006, File No. 1-15659).
10.1		—Corporate Opportunity Agreement, dated as of September 14, 2006, between Dynegy Acquisition, Inc. and LS Power Development, LLC (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on September 19, 2006, File No. 1-15659).
**10.2		—Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. (formerly named Dynegy Acquisition, Inc.) and Dynegy Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto.
10.3		—Amendment No. 1, dated as of May 24, 2007, to the Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. and Dynegy Illinois Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on May 25, 2007, File No. 000-29311).
10.4		—Amendment No. 2, dated as of September 30, 2008, to the Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. and Dynegy Illinois Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q of Dynegy Holdings Inc. filed on November 6, 2008, File No. 000-29311).
10.5		—Amendment No. 3, dated as of February 13, 2009, to the Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc. and Dynegy Illinois Inc., as parent guarantors, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2009, filed on February 26, 2009, File No. 001-33443).
10.6		—Amendment No. 4, dated as of August 5, 2009, to the Fifth Amended and Restated Credit Agreement, dated as of April 2, 2007, by and among Dynegy Holdings Inc., as borrower, Dynegy Inc., as parent guarantor, the other guarantors party thereto, the lenders party thereto and various other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 10, 2009, File No. 000-29311).

Table of Contents

Exhibit Number		Description
10.7		—Second Amended and Restated Security Agreement, dated April 2, 2007, by and among Dynegy Holdings Inc., as Borrower, the initial grantors party thereto, Wilmington Trust Company, as corporate trustee, and John M. Beeson, Jr., as individual trustee (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311).
**10.8		—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.
**10.9		—Credit Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, and the lenders and other parties thereto.
10.10		—First Amendment to Credit Agreement by and among Plum Point Energy Associates, LLC, as borrower, and the lenders and other parties thereto, effective December 13, 2007 (incorporated by reference to Exhibit 10.2 to the Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 26, 2009, File No. 001-33443).
**10.11		—Collateral Agency and Intercreditor Agreement, dated as of March 29, 2007, by and among Plum Point Energy Associates, LLC, as borrower, PPEA Holding Company, LLC, as Pledgor, The Bank of New York, as collateral agent, The Royal Bank of Scotland, as Administrative Agent, AMBAC Assurance Corporation, as Loan Insurer, and the other parties thereto.
10.12		—Loan Agreement, dated as of April 1, 2006, by and between the City of Osceola, Arkansas and Plum Point Energy Associates, LLC (incorporated by reference to Exhibit 10.12 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311).
10.13		—Dynegy Inc. Executive Severance Pay Plan, as amended and restated effective as of January 1, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443). ††
10.14		—Dynegy Inc. Executive Change in Control Severance Pay Plan effective April 3, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 8, 1008, File No. 001-33443). ††
10.15		—Dynegy Inc. Excise Tax Reimbursement Policy, effective January 1, 2008 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443). ††
10.16		—Dynegy Inc. Restoration 401(k) Savings Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008, File No. 001-33443).
10.17		—First Amendment to the Dynegy Inc. Restoration 401(k) Savings Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008, File No. 001-33443). ††
10.18		—Dynegy Inc. Restoration Pension Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008, File No. 001-33443). ††
10.19		—First Amendment to the Dynegy Inc. Restoration Pension Plan, effective June 1, 2008 (incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Dynegy Inc. filed on August 7, 2008, File No. 001-33443). ††
10.20		—Form of Non-Qualified Stock Option Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson (incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2009 of Dynegy Inc. filed on May 7, 2009, File No. 001-33443). ††

Table of Contents

Exhibit Number		Description
10.21		—Form of Non-Qualified Stock Option Award Agreement (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q for the Quarterly Period Ended March 31, 2009 of Dynegy Inc. filed on May 7, 2009, File No. 001-33443). ††
10.22		—Form of Phantom Stock Unit Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443). ††
10.23		—Form of Phantom Stock Unit Award Agreement (Managing Directors and Above) (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443). ††
10.24		—Form of Performance Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443). ††
10.25		—Form of Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443). ††
10.26		—Dynegy Inc. 2009 Phantom Stock Plan (incorporated by reference to Exhibit 10.3 to the Current Report onForm8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443)
10.27		—Dynegy Inc. Deferred Compensation Plan, amended and restated, effective January 1, 2002(incorporated by reference to Exhibit 4.6 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††
10.28		—Amendment to the Dynegy Inc. Deferred Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.38 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). ††
10.29		—Dynegy Inc. Deferred Compensation Plan for Certain Directors, as amended and restated, effective January 1, 2008 (incorporated by reference to Exhibit 10.55 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2009, filed on February 26, 2009, File No. 001-33443). ††
10.30		—Trust under Dynegy Inc. Deferred Compensation Plan for Certain Directors, effective January 1, 2009 (incorporated by reference to Exhibit 10.56 to the Annual Report on Form 10-K for the Fiscal Year ended December 31, 2009, filed on February 26, 2009, File No. 001-33443). ††
10.31		—Dynegy Inc. Incentive Compensation Plan, as amended and restated effective January 1, 2006 (incorporated by reference to Exhibit 10.36 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2005 of Dynegy Inc. File No. 1-15659). ††
10.32		—First Amendment to the Dynegy Inc. Incentive Compensation Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.32 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). ††
10.33		—Dynegy Inc. 1999 Long Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). ††
10.34		—First Amendment to the Dynegy Inc. 1999 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.33 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). ††
10.35		—Dynegy Inc. 2000 Long Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 1999 of Dynegy Inc., File No. 1-11156). ††

Table of Contents

Exhibit Number		Description
10.36		—Amendment to the Dynegy Inc. 2000 Long Term Incentive Plan effective January 1, 2006 (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659). ††
10.37		—Second Amendment to the Dynegy Inc. 2000 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.34 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). ††
10.38		—Dynegy Inc. 2002 Long Term Incentive Plan (incorporated by reference to Appendix A to the Definitive Proxy Statement on Schedule 14A of Dynegy Inc., File No. 1-15659, filed with the SEC on April 9, 2002). ††
10.39		—Amendment to the Dynegy Inc. 2002 Long Term Incentive Plan, effective January 1, 2006 (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on March 17, 2006, File No. 1-15659). ††
10.40		—Second Amendment to the Dynegy Inc. 2002 Long Term Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.36 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). ††
10.41		—Dynegy Inc. 2001 Non-Executive Stock Incentive Plan (incorporated by reference to Exhibit 4.5 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080).
10.42		—First Amendment to the Dynegy Inc. 2001 Non-Executive Stock Incentive Plan, dated as of April 2, 2007 (incorporated by reference to Exhibit 10.35 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311).
10.43		—Dynegy Inc. Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 4.7 to the Registration Statement on Form S-8 of Dynegy Inc., Registration No. 333-76080). ††
10.44		—Amendment to Dynegy Inc. Deferred Compensation Plan Trust Agreement (Vanguard), dated as of April 2, 2007 (incorporated by reference to Exhibit 10.54 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on April 6, 2007, File No. 000-29311). ††
10.45		—Purchase Agreement, dated as of May 17, 2007, by and between Dynegy Holdings Inc. and J.P. Morgan Securities Inc. (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q for Quarterly Period Ended June 30, 2007 of Dynegy Holdings Inc., File No. 000-29311).
10.46		—Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Dynegy Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on September 5, 2007, File No. 000-29311).
10.47		—Equity Commitment Agreement among Sandy Creek Energy Associates, L.P., Sandy Creek Holdings, LLC and Credit Suisse dated August 29, 2007 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Holdings Inc. filed on September 5, 2007, File No. 000-29311).
10.48		—Baldwin Consent Decree, approved May 27, 2005 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. filed on May 31, 2005, File No. 1-15659).
14.1		—Dynegy Inc. Code of Ethics for Senior Financial Professionals (incorporated by reference to Exhibit 14.1 to the Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003 of Dynegy Inc., File No. 1- 15659).
**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.1(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.

Table of Contents

Exhibit Number		Description
**31.2		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.2(a)		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
†32.1		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.1(a)		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.2(a)		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Filed herewith.

†

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

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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 10, 2009	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 10, 2009	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)