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 September 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, 505,561,433 shares outstanding as of October 29, 2009; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of October 29, 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.:
September 30, 2009 and December 31, 2008		4
Condensed Consolidated Statements of Operations—Dynegy Inc.:
For the three and nine months ended September 30, 2009 and 2008		5
Condensed Consolidated Statements of Cash Flows—Dynegy Inc.:
For the nine months ended September 30, 2009 and 2008		6
Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Inc.:
For the three and nine months ended September 30, 2009 and 2008		7
Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.:
September 30, 2009 and December 31, 2008		8
Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.:
For the three and nine months ended September 30, 2009 and 2008		9
Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.:
For the nine months ended September 30, 2009 and 2008		10
Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Holdings Inc.:
For the three and nine months ended September 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.	54
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.	87
Item 4.	CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.	89

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	90
Item 1A.	RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	90
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS—DYNEGY INC.	90
Item 6.	EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	90

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 nine-month period ended September 30, 2009 and constituting nearly 100 percent of Dynegy’s total consolidated asset base as of September 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

CAA

Clean Air Act

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.

EPA

Environmental Protection Agency

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

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

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

PSD

Prevention of significant deterioration

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

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)

	September 30, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	703		$	693
Restricted cash and investments		115			87
Short-term investments		2			25
Accounts receivable, net of allowance for doubtful accounts of $22 and $22, respectively		253			340
Accounts receivable, affiliates		1			1
Inventory		157			184
Assets from risk-management activities		927			1,263
Deferred income taxes		4			6
Prepayments and other current assets		339			204
Assets held for sale		1,273			—
Total Current Assets		3,774			2,803
Property, Plant and Equipment		8,895			10,869
Accumulated depreciation		(1,880	)		(1,935	)
Property, Plant and Equipment, Net		7,015			8,934
Other Assets
Unconsolidated investments		—			15
Restricted cash and investments		1,164			1,158
Assets from risk-management activities		295			114
Goodwill		—			433
Intangible assets		399			437
Accounts receivable, affiliates		8			4
Other long-term assets		369			315
Total Assets	$	13,024		$	14,213

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	231		$	303
Accrued interest		124			56
Accrued liabilities and other current liabilities		149			160
Liabilities from risk-management activities		834			1,119
Notes payable and current portion of long-term debt		65			64
Deferred income taxes		8			—
Liabilities associated with assets held for sale		31			—
Total Current Liabilities		1,442			1,702
Long-term debt		5,928			5,872
Long-term debt, affiliates		200			200
Long-Term Debt		6,128			6,072
Other Liabilities
Liabilities from risk-management activities		313			288
Deferred income taxes		945			1,166
Other long-term liabilities		451			500
Total Liabilities	$	9,279		$	9,728
Commitments and Contingencies (Note 13)
Stockholders’ Equity
Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at September 30, 2009 and December 31, 2008; 508,175,228 and 505,821,277 shares issued and outstanding at September 30, 2009 and December 31, 2008, respectively		5			5
Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at September 30, 2009 and December 31, 2008; 340,000,000 shares issued and outstanding at September 30, 2009 and December 31, 2008		3			3
Additional paid-in capital		6,494			6,485
Subscriptions receivable		(2	)		(2	)
Accumulated other comprehensive loss, net of tax		(179	)		(215	)
Accumulated deficit		(2,582	)		(1,690	)
Treasury stock, at cost, 2,777,376 and 2,568,286 shares at September 30, 2009 and December 31, 2008, respectively		(71	)		(71	)
Total Dynegy Inc. Stockholders’ Equity		3,668			4,515
Noncontrolling interests		77			(30	)
Total Stockholders’ Equity		3,745			4,485
Total Liabilities and Stockholders’ Equity	$	13,024		$	14,213

See the notes to condensed consolidated financial statements.

Table of Contents

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Revenues	$	673		$	1,759		$	2,027		$	2,550
Cost of sales		(286	)		(498	)		(927	)		(1,326	)
Operating and maintenance expense, exclusive of depreciation shown separately below		(121	)		(122	)		(373	)		(344	)
Depreciation and amortization expense		(83	)		(85	)		(258	)		(258	)
Gain on sale of assets		—			57			—			83
Goodwill impairments		—			—			(433	)		—
Impairment and other charges, exclusive of goodwill impairments shown separately above		(148	)		—			(535	)		—
General and administrative expenses		(42	)		(48	)		(125	)		(126	)

Operating income (loss)		(7	)		1,063			(624	)		579
Earnings (losses) from unconsolidated investments		(8	)		(5	)		13			(17	)
Interest expense		(115	)		(105	)		(311	)		(322	)
Other income and expense, net		2			11			10			46

Income (loss) from continuing operations before income taxes		(128	)		964			(912	)		286
Income tax benefit (expense) (Note 15)		34			(392	)		147			(121	)

Income (loss) from continuing operations		(94	)		572			(765	)		165
Income (loss) from discontinued operations, net of tax (expense) benefit of $84, $(22), $91 and $(10), respectively (Note 2)		(129	)		32			(141	)		13

Net income (loss)		(223	)		604			(906	)		178
Less: Net loss attributable to the noncontrolling interests		(11	)		(1	)		(14	)		(3	)
Net income (loss) attributable to Dynegy Inc.	$	(212	)	$	605		$	(892	)	$	181

Earnings (Loss) Per Share (Note 12):
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders:
Earnings (loss) from continuing operations	$	(0.10	)	$	0.68		$	(0.89	)	$	0.20
Income (loss) from discontinued operations		(0.15	)		0.04			(0.17	)		0.02

Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	(0.25	)	$	0.72		$	(1.06	)	$	0.22

Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders:
Earnings (loss) from continuing operations	$	(0.10	)	$	0.68		$	(0.89	)	$	0.20
Income (loss) from discontinued operations.		(0.15	)		0.04			(0.17	)		0.02

Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	(0.25	)	$	0.72		$	(1.06	)	$	0.22

Basic shares outstanding		843			840			842			840
Diluted shares outstanding		846			842			845			842

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Nine Months Ended September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(906	)	$	178
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization		279			281
Goodwill impairments		433			—
Impairment and other charges, exclusive of goodwill impairments shown separately above		793			—
(Earnings) losses from unconsolidated investments, net of cash distributions		(13	)		17
Risk-management activities		73			(127	)
Gain on sale of assets		(10	)		(83	)
Deferred income taxes		(246	)		116
Legal and settlement charges		—			7
Other		66			37
Changes in working capital:
Accounts receivable		(4	)		43
Inventory		(7	)		27
Prepayments and other assets		(134	)		(75	)
Accounts payable and accrued liabilities		81			75
Changes in non-current assets		(91	)		(84	)
Changes in non-current liabilities		(10	)		(15	)

Net cash provided by operating activities		304			397

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(429	)		(460	)
Unconsolidated investments		1			(1	)
Proceeds from asset sales, net		105			452
Decrease (increase) in short-term investments		14			(127	)
(Increase) decrease in restricted cash and restricted investments		(35	)		17
Other investing		3			11

Net cash used in investing activities		(341	)		(108	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		75			153
Repayments of long-term borrowings, net		(28	)		(21	)
Proceeds from issuance of capital stock		—			2
Other financing, net		—			(1	)

Net cash provided by financing activities		47			133

Net increase in cash and cash equivalents		10			422
Cash and cash equivalents, beginning of period		693			328

Cash and cash equivalents, end of period	$	703		$	750

Other non-cash investing activity:
Non-cash capital expenditures	$	19		$	3

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended September 30,
	2009			2008

Net income (loss)	$	(223	)	$	604
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		45			(21	)
Reclassification of mark-to-market losses to earnings, net		1			3
Deferred gains (losses) on cash flow hedges, net		(2	)		2

Changes in cash flow hedging activities, net (net of tax (expense) benefit of $(11) and $4, respectively)		44			(16	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax benefit of $2 and zero)		(1	)		—
Unconsolidated investments other comprehensive loss, net (net of tax benefit of $3 and $3)		(3	)		(4	)

Other comprehensive income (loss), net of tax		40			(20	)

Comprehensive income (loss)		(183	)		584
Less: Comprehensive income (loss) attributable to the noncontrolling interests		25			(11	)

Comprehensive income (loss) attributable to Dynegy Inc.	$	(208	)	$	595

	Nine Months Ended September 30,
	2009			2008

Net income (loss)	$	(906	)	$	178
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		160			(27	)
Reclassification of mark-to-market losses to earnings, net		1			10
Deferred losses on cash flow hedges, net		(8	)		—

Changes in cash flow hedging activities, net (net of tax (expense) benefit of $(26) and 4, respectively)		153			(17	)
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $3 and zero)		1			1
Net unrealized losses, (net of tax benefit of zero and $8, respectively)		—			(12	)
Unconsolidated investments other comprehensive income (loss), net (net of tax (expense) benefit of $(2) and $7)		3			(11	)

Other comprehensive income (loss), net of tax		157			(39	)

Comprehensive income (loss)		(749	)		139
Less: Comprehensive income (loss) attributable to the noncontrolling interests		107			(15	)

Comprehensive income (loss) attributable to Dynegy Inc.	$	(856	)	$	154

See the notes to condensed consolidated financial statements.

Table of Contents

DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEET

(unaudited) (in millions)

	September 30, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	519		$	670
Restricted cash and investments		115			87
Short-term investments		2			24
Accounts receivable, net of allowance for doubtful accounts of $20 and $20, respectively		255			343
Accounts receivable, affiliates		1			1
Inventory		157			184
Assets from risk-management activities		927			1,263
Deferred income taxes		4			4
Prepayments and other current assets		340			204
Assets held for sale		1,273			—
Total Current Assets		3,593			2,780
Property, Plant and Equipment		8,895			10,869
Accumulated depreciation		(1,880	)		(1,935	)
Property, Plant and Equipment, Net		7,015			8,934
Other Assets
Restricted cash and investments		1,164			1,158
Assets from risk-management activities		295			114
Goodwill		—			433
Intangible assets		399			437
Accounts receivable, affiliates		8			4
Other long-term assets		368			314
Total Assets	$	12,842		$	14,174

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	231		$	284
Accrued interest		124			56
Accrued liabilities and other current liabilities		147			157
Liabilities from risk-management activities		834			1,119
Notes payable and current portion of long-term debt		65			64
Deferred income taxes		10			1
Liabilities associated with assets held for sale		31			—
Total Current Liabilities		1,442			1,681
Long-term debt		5,928			5,872
Long-term debt, affiliates		200			200
Long-Term Debt		6,128			6,072
Other Liabilities
Liabilities from risk-management activities		313			288
Deferred income taxes		808			1,052
Other long-term liabilities		451			498
Total Liabilities		9,142			9,591
Commitments and Contingencies (Note 13)
Stockholders’ Equity
Capital Stock, $1 par value, 1,000 shares authorized at September 30, 2009 and December 31, 2008		—			—
Additional paid-in capital		5,545			5,684
Affiliate receivable		(823	)		(827	)
Accumulated other comprehensive loss, net of tax		(179	)		(215	)
Accumulated deficit		(920	)		(29	)
Total Dynegy Holdings Inc. Stockholder’s Equity		3,623			4,613
Noncontrolling interests		77			(30	)
Total Stockholders’ Equity		3,700			4,583
Total Liabilities and Stockholders’ Equity	$	12,842		$	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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
Revenues	$	673		$	1,759		$	2,027		$	2,550
Cost of sales		(286	)		(498	)		(927	)		(1,326	)
Operating and maintenance expense, exclusive of depreciation shown separately below		(121	)		(122	)		(375	)		(344	)
Depreciation and amortization expense		(83	)		(85	)		(258	)		(258	)
Gain on sale of assets		—			57			—			83
Goodwill impairments		—			—			(433	)		—
Impairment and other charges, exclusive of goodwill impairments shown separately above		(148	)		—			(535	)		—
General and administrative expenses		(42	)		(48	)		(125	)		(126	)

Operating income (loss)		(7	)		1,063			(626	)		579
Earnings (losses) from unconsolidated investments		(8	)		(5	)		12			(7	)
Interest expense		(115	)		(105	)		(311	)		(322	)
Other income and expense, net		2			11			9			45

Income (loss) from continuing operations before income taxes		(128	)		964			(916	)		295
Income tax benefit (expense) (Note 15)		35			(391	)		152			(127	)

Income (loss) from continuing operations		(93	)		573			(764	)		168
Income (loss) from discontinued operations, net of tax (expense) benefit of $74, $(22), $91 and $(10), respectively (Note 2)		(139	)		32			(141	)		13

Net income (loss)		(232	)		605			(905	)		181
Less: Net loss attributable to the noncontrolling interests		(11	)		(1	)		(14	)		(3	)
Net income (loss) attributable to Dynegy Holdings Inc.	$	(221	)	$	606		$	(891	)	$	184

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Nine Months Ended September 30,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(905	)	$	181
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization		279			281
Goodwill impairments		433			—
Impairment and other charges, exclusive of goodwill impairments shown separately above		793			—
(Earnings) losses from unconsolidated investments, net of cash distributions		(12	)		7
Risk-management activities		73			(127	)
Gain on sale of assets, net		(10	)		(83	)
Deferred income taxes		(248	)		123
Legal and settlement charges		—			7
Other		64			33
Changes in working capital:
Accounts receivable		(4	)		43
Inventory		(7	)		27
Prepayments and other assets		(134	)		(75	)
Accounts payable and accrued liabilities		100			76
Changes in non-current assets		(91	)		(84	)
Changes in non-current liabilities		(9	)		(16	)

Net cash provided by operating activities		322			393

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(429	)		(460	)
Unconsolidated investments		—			10
Proceeds from asset sales, net		105			452
Decrease (increase) in short-term investments		13			(120	)
(Increase) decrease in restricted cash and restricted investments		(35	)		17
Affiliate transactions		(2	)		2
Other investing		3			7

Net cash used in investing activities		(345	)		(92	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		75			153
Repayments to long-term borrowings		(28	)		(21	)
Dividend to affiliate		(175	)		—
Other financing, net		—			(1	)

Net cash provided by (used in) financing activities		(128	)		131

Net increase (decrease) in cash and cash equivalents		(151	)		432
Cash and cash equivalents, beginning of period		670			292

Cash and cash equivalents, end of period	$	519		$	724

Other non-cash investing activity:
Non-cash capital expenditures	$	19		$	3

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended September 30,
	2009			2008

Net income (loss)	$	(232	)	$	605
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		45			(21	)
Reclassification of mark-to-market losses to earnings, net		1			3
Deferred gains (losses) on cash flow hedges, net		(2	)		2

Changes in cash flow hedging activities, net (net of tax (expense) benefit of $(11) and $4, respectively)		44			(16	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $2 and zero)		(1	)		—
Unconsolidated investments other comprehensive loss, net (net of tax benefit of $3 and $3)		(3	)		(4	)

Other comprehensive income (loss), net of tax		40			(20	)

Comprehensive income (loss)		(192	)		585
Less: Comprehensive income (loss) attributable to the noncontrolling interests		25			(11	)

Comprehensive income (loss) attributable to Dynegy Holdings Inc.	$	(217	)	$	596

	Nine Months Ended September 30,
	2009			2008

Net income (loss)	$	(905	)	$	181
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		160			(27	)
Reclassification of mark-to-market losses to earnings, net		1			10
Deferred losses on cash flow hedges, net		(8	)		—

Changes in cash flow hedging activities, net (net of tax (expense) benefit of $(26) and $4, respectively)		153			(17	)
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $3 and zero)		1			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 $(2) and $7)		3			(11	)

Other comprehensive income (loss), net of tax		157			(39	)

Comprehensive income (loss)		(748	)		142
Less: Comprehensive income (loss) attributable to the noncontrolling interests		107			(15	)

Comprehensive income (loss) attributable to Dynegy Holdings Inc.	$	(855	)	$	157

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 September 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 authoritative guidance for noncontrolling interests 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, as supplemented by our Current Report on Form 8-K dated September 28, 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

Business Combinations. On January 1, 2009, we adopted authoritative guidance issued by the Financial Accounting Standards Board (“FASB”) on business combinations. The guidance 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.

Fair Value Measurements. On January 1, 2009, we adopted authoritative guidance issued by the for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). Please read Note 5—Fair Value Measurements for further discussion.

Noncontrolling Interests. On January 1, 2009, we adopted authoritative guidance issued by the FASB for noncontrolling interests. 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 September 30, 2009 and 2008

Disclosures about Derivative Instruments and Hedging Activities. On January 1, 2009, we adopted authoritative guidance issued by the FASB for the disclosure of derivative instruments and hedging activities. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

Subsequent Events. On June 30, 2009, we adopted authoritative guidance issued by the FASB which provides guidance on management’s assessment of subsequent events. We have evaluated subsequent events through November 5, 2009, the date our financial statements were issued and up to the time of the filing of our financial statements with the SEC.

Accounting Standards Codification. Effective July 1, 2009, we adopted authoritative guidance issued by the FASB which superseded all then-existing non-SEC accounting and reporting standards. All other non-grandfathered non-SEC accounting literature not included in the Codification is no longer considered authoritative. The adoption of this adopted authoritative had no impact on our financial condition, results of operations or cash flows.

Third Party Credit Enhancement. On January 1, 2009, we adopted authoritative guidance issued by the FASB 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. Please read Note 5—Fair Value Measurements for further discussion.

Fair Value of Financial Instruments. On June 30, 2009, we adopted authoritative guidance issued by the FASB which requires the disclosure of the estimated fair value of financial instruments. Please read Note 5—Fair Value Measurements for further discussion.

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. On June 30, 2009, we adopted authoritative guidance issued by the FASB 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 this authoritative guidance had no impact on our financial statements. Please read Note 5—Fair Value Measurements for further discussion.

Accounting Principles Not Yet Adopted

Employers’ Disclosures about Pensions and Other Postretirement Benefits. On January 1, 2009, the FASB issued authoritative guidance 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 authoritative guidance are to be provided for fiscal years ending after December 15, 2009. We are currently evaluating the disclosure implications of this standard; however, this authoritative guidance will have no impact on our financial condition, results of operations or cash flows.

Variable Interest Entities. On June 12, 2009, the FASB issued authoritative guidance which amends the consolidation guidance that applies to variable interest entities. The FASB’s objective in issuing this authoritative guidance is to improve financial reporting by enterprises involved with variable interest entities. This authoritative guidance is effective for fiscal years beginning after November 15, 2009. We are currently evaluating the impact of this standard on our consolidated financial statements.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 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 Adio Bond, LLC, an affiliate of 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 at closing (i) approximately $1.025 billion in cash (consisting, in part, of the release of $175 million of restricted cash on our unaudited condensed consolidated balance sheets that was used to support our funding commitment to Sandy Creek and approximately $200 million for the unsecured notes), subject to working capital adjustments, 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 converted at closing to the same 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 the 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 Class A common stock to be held by LS Power. This shareholder agreement provides that following closing we cannot 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 or (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 sale is expected to close in the fourth quarter 2009 assuming all necessary closing conditions are satisfied or waived.

In connection with the signing of the purchase and sale agreement with LS Power on August 9, 2009, our Arizona power generation assets, as defined below, and our Bluegrass power generation facility met the requirements for classification as discontinued operations. Accordingly, the results of operations for these facilities have been reclassified as discontinued operations for all periods presented (see Discontinued Operations discussed below). The Renaissance, Tilton, Riverside/Foothills, Rocky Road and Bridgeport power generation facilities did not meet the requirements for classification as discontinued operations, based on our continuing presence in the markets where these assets are located; however, these assets are reported as held for sale. The major classes of current and long-term assets and liabilities at September 30, 2009 classified as assets held for sale or liabilities associated with assets held for sale and included in the LS Power transaction are as follows (in millions):

Current Assets:
Accounts receivable	$	39
Inventory		18
Assets from risk management activities		5
Prepayments and other current assets		11

Total Current Assets	$	73

Long-Term Assets:
Property, plant and equipment	$	1,163
Assets from risk management activities		4
Other		33

Total Long-Term Assets	$	1,200

Current Liabilities:
Accounts payable	$	17
Current liabilities and accrued liabilities		8

Total Current Liabilities	$	25

Long-Term Liabilities:
Other	$	6

Total Long-Term Liabilities	$	6

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

We recorded pre-tax impairment charges of $147 million and $326 million, inclusive of costs to sell, related to the assets included in the LS Power transaction that did not meet the criteria for classification as discontinued operations in the three and nine month periods ended September 30, 2009, respectively, which is included in Impairment and other charges in our unaudited condensed consolidated statements of operations. Please read Note 6—Impairment Charges for further discussion of these impairments.

We discontinued depreciation and amortization of property, plant and equipment included in the LS Power transaction that did not meet the criteria for classification as discontinued operations during the third quarter 2009. Depreciation and amortization expense related to these assets totaled $3 million and $24 million in the three and nine month periods ended September 30, 2009, respectively, compared to $8 million and $23 million in the three and nine months ended September 30, 2008, respectively.

Rolling Hills. On July 31, 2008, we completed the sale of the Rolling Hills power generation facility (“Rolling Hills”) to an affiliate of Tenaska Capital Management, LLC for approximately $368 million, net of transaction costs. We recorded a $57 million gain in the third quarter 2008 related to the sale, which is included in Gain on sale of assets in our unaudited condensed consolidated statements of operations. The gain includes the impact of allocating approximately $5 million of goodwill associated with the GEN-MW reporting unit to Rolling Hills. The amount of goodwill allocated to Rolling Hills was based on the relative fair values of Rolling Hills and the portion of the GEN-MW reporting unit being retained.

The sale of Rolling Hills represented the sale of a significant portion of a reporting unit. As such, we assessed the goodwill of the GEN-MW reporting unit for impairment during the third quarter 2008. No impairment was indicated as a result of this assessment.

We discontinued depreciation and amortization of Rolling Hills’ property, plant and equipment during the second quarter 2008. Depreciation and amortization expense related to Rolling Hills totaled zero and approximately $3 million in the three and nine month periods ended September 30, 2008, respectively.

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

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.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

Discontinued Operations

Arlington Valley, Griffith and Bluegrass. On August 9, 2009, we entered into a purchase and sale agreement to sell our interests in, among others, the Arlington Valley, Griffith and Bluegrass power generation facilities as part of the LS Power transaction, as discussed above.

The Arlington Valley and Griffith facilities (collectively, the “Arizona power generation facilities”), as well as our Bluegrass facility, met the criteria of held for sale during the third quarter 2009 and are classified as such on our unaudited condensed consolidated balance sheet. At that time, we discontinued depreciation and amortization of Arlington Valley’s, Griffith’s and Bluegrass’ property, plant and equipment. Depreciation and amortization expense related to the Arizona power generation facilities totaled approximately $4 and $14 million in the three and nine months ended September 30, 2009, respectively, compared to approximately $5 million and $15 million in the three and nine months ended September 30, 2008, respectively. Depreciation and amortization expense related to Bluegrass totaled approximately zero and $1 million in the three and nine months ended September 30, 2009, respectively, compared to approximately zero and $1 million in the three and nine months ended September 30, 2008, respectively. We recorded an impairment charge of $235 million related to the Arizona power generation facilities during the third quarter 2009. We previously recorded impairment charges of $5 million and $18 million related to the Bluegrass facility during the first and second quarters of 2009, respectively. Please read Note 6—Impairment Charges for further discussion. We are reporting the results of operations for the Arizona power generation facilities and the Bluegrass power generation facility in discontinued operations for all periods presented.

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 nine months ended September 30, 2009, respectively, compared to approximately $1 million and $3 million in the three and nine months ended September 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 nine months ended September 30, 2008. We are reporting the results of Calcasieu’s operations in discontinued operations for the three months 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 September 30, 2009 and 2008

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

	GEN-MW			GEN-WE			Total
				(in millions)
Three Months Ended September 30, 2009
Revenues	$	1		$	54		$	55
Loss from operations before taxes		—			(213	)(2)		(213	)
Loss from operations after taxes		—			(129	)		(129	)

Three Months Ended September 30, 2008
Revenues	$	1		$	126		$	127
Income from operations before taxes		—			53			53
Income from operations after taxes		—			32			32
Gain on sale before taxes		—			1			1
Gain on sale after taxes		—			—			—

Nine Months Ended September 30, 2009
Revenues	$	4		$	96		$	100
Loss from operations before taxes		(23	)(1)		(219	)(2)		(242	)
Loss from operations after taxes		(14	)		(133	)		(147	)
Gain on sale before taxes		—			10			10
Gain on sale after taxes		—			6			6

Nine Months Ended September 30, 2008
Revenues	$	2		$	202		$	204
Income (loss) from operations before taxes		(1	)		24			23
Income (loss) from operations after taxes		(1	)		14			13

____________________________

(1)

Includes $23 million of impairment charges related to our Bluegrass power generation facility.

(2)

Includes $235 million of impairment charges related to our Arizona power generation facilities.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

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

	GEN-MW			GEN-WE			Total
				(in millions)
Three Months Ended September 30, 2009
Revenues	$	1		$	54		$	55
Loss from operations before taxes		—			(213	)(2)		(213	)
Loss from operations after taxes		—			(139	)		(139	)

Three Months Ended September 30, 2008
Revenues	$	1		$	126		$	127
Income from operations before taxes		—			53			53
Income from operations after taxes		—			32			32
Gain on sale before taxes		—			1			1
Gain on sale after taxes		—			—			—

Nine Months Ended September 30, 2009
Revenues	$	4		$	96		$	100
Loss from operations before taxes		(23	)(1)		(219	)(2)		(242	)
Loss from operations after taxes		(14	)		(139	)		(153	)
Gain on sale before taxes		—			10			10
Gain on sale after taxes		—			12			12

Nine Months Ended September 30, 2008
Revenues	$	2		$	202		$	204
Income (loss) from operations before taxes		(1	)		24			23
Income (loss) from operations after taxes		(1	)		14			13

____________________________

(1)

Includes $23 million of impairment charges related to our Bluegrass power generation facility.

(2)

Includes $235 million of impairment charges related to our Arizona power generation facilities.

Note 3—Noncontrolling Interests

On January 1, 2009, we adopted authoritative guidance 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 income (loss) attributable to Dynegy’s and DHI’s stockholders:

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

	Dynegy Inc.					Dynegy Holdings Inc.
	Three Months Ended September 30,					Three Months Ended September 30,
	2009			2008		2009			2008
	(in millions)
Income (loss) from continuing operations	$	(83	)	$	573	$	(82	)	$	574
Income (loss) from discontinued operations, net of tax benefit (expense) of $84, ($22), $74 and ($22), respectively		(129	)		32		(139	)		32

Net income (loss)	$	(212	)	$	605	$	(221	)	$	606

	Dynegy Inc.					Dynegy Holdings Inc.
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008
	(in millions)
Income (loss) from continuing operations	$	(751	)	$	168	$	(750	)	$	171
Income (loss) from discontinued operations, net of tax benefit (expense) of $91, ($10), $91 and ($10), respectively		(141	)		13		(141	)		13

Net income (loss)	$	(892	)	$	181	$	(891	)	$	184

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 nine months ended September 30, 2009:

	Controlling Interest			Noncontrolling Interests			Total
				(in millions)
December 31, 2008	$	4,515		$	(30	)	$	4,485
Net loss		(892	)		(14	)		(906	)
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market gains arising during period		33			127			160
Reclassification of mark-to-market (gains) losses to earnings		(1	)		2			1
Deferred losses on cash flow hedges		—			(8	)		(8	)
Amortization of unrecognized prior service cost and actuarial gain		1			—			1
Unconsolidated investments other comprehensive income		3			—			3
Total other comprehensive income, net of tax		36			121			157
Other equity activity:
Options exercised		(1	)		—			(1	)
Options and restricted stock granted		7			—			7
401(k) plan and profit sharing stock		5			—			5
Board of directors stock compensation		(2	)		—			(2	)

September 30, 2009	$	3,668		$	77		$	3,745

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

	Controlling Interest			Noncontrolling Interests			Total
				(in millions)
December 31, 2007	$	4,506		$	23		$	4,529
Net income (loss)		181			(3	)		178
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market losses arising during period		(18	)		(9	)		(27	)
Reclassification of mark-to-market (gains) losses to earnings		11			(1	)		10
Deferred gains (losses) on cash flow hedges		2			(2	)		—
Amortization of unrecognized prior service cost and actuarial gain		1			—			1
Unconsolidated investments other comprehensive loss		(11	)		—			(11	)
Net unrealized loss on securities		(12	)		—			(12	)
Total other comprehensive loss, net of tax		(27	)		(12	)		(39	)
Other equity activity:
Subscriptions receivable		2			—			2
Options exercised		1			—			1
401(k) plan and profit sharing stock		4			—			4
Options and restricted stock granted		12			—			12

September 30, 2008	$	4,679		$	8		$	4,687

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 nine months ended September 30, 2009:

	Controlling Interest			Noncontrolling Interests			Total
				(in millions)
December 31, 2008	$	4,613		$	(30	)	$	4,583
Net loss		(891	)		(14	)		(905	)
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market gains arising during period		33			127			160
Reclassification of mark-to-market (gains) losses to earnings		(1	)		2			1
Deferred losses on cash flow hedges		—			(8	)		(8	)
Amortization of unrecognized prior service cost and actuarial gain		1			—			1
Unconsolidated investments other comprehensive income		3			—			3
Total other comprehensive income, net of tax		36			121			157
Other equity activity:
Dividend to Dynegy		(175	)		—			(175	)
Contribution from Dynegy		36			—			36
Affiliate activity		4			—			4

September 30, 2009	$	3,623		$	77		$	3,700

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

	Controlling Interest			Noncontrolling Interests			Total
				(in millions)
December 31, 2007	$	4,597		$	23		$	4,620
Net income (loss)		184			(3	)		181
Other comprehensive income (loss), net of tax:
Unrealized mark-to-market losses arising during period		(18	)		(9	)		(27	)
Reclassification of mark-to-market (gains) losses to earnings		11			(1	)		10
Deferred gains (losses) on cash flow hedges		2			(2	)		—
Amortization of unrecognized prior service cost and actuarial gain		1			—			1
Unconsolidated investments other comprehensive loss		(11	)		—			(11	)
Net unrealized loss on securities		(12	)		—			(12	)
Total other comprehensive loss, net of tax		(27	)		(12	)		(39	)
Other equity activity:
Affiliate activity		14			—			14

September 30, 2008	$	4,768		$	8		$	4,776

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 authoritative guidance 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.

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 September 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 September 30, 2009, we had net long/(short) commodity derivative contracts outstanding and notional interest rate swaps outstanding in the following quantities:

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

Contract Type	Hedge Designation	Quantity			Unit of Measure	Net Fair Value
		(in millions)				(in millions)
Commodity derivative contracts:
Electric energy (1)(3)	Not designated		(93	)	MW	$	135
Natural gas (1)	Not designated		99		MMBtu	$	(22	)
Electricity/natural gas spread options (3)	Not designated		(9)/46		MW/MMBtu	$	28
Other (2)	Not designated		2		Misc.	$	2

Interest rate contracts:
Interest rate swaps	Fair value hedge		(25	)	Dollars	$	2
Interest rate swaps	Not designated		532		Dollars	$	(59	)
Interest rate swaps	Not designated		231		Dollars	$	(20	)
Interest rate swaps	Not designated		(206	)	Dollars	$	18

____________________________

(1)

Mainly comprised of swaps, options and physical forwards.

(2)

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

(3)

Includes $9 million of net commodity derivative contracts classified as held for sale as of September 30, 2009, comprised of electric energy of (0.22) MW and electricity/natural gas spread options of (1.0) MW/11 MMBtu, respectively, with a net fair value of $2 million and $7 million, respectively.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

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 September 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.

Contract Type	Balance Sheet Location	September 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		—			(238	)

Total derivatives designated as hedging instruments, net			2			(235	)

Derivatives not designated as hedging instruments:
Derivative Assets:
Commodity contracts (1)	Assets from risk management activities		1,211			1,355
Interest rate contracts	Assets from risk management activities		18			19
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities		(1,068	)		(1,147	)
Interest rate contracts	Liabilities from risk management activities		(79	)		(22	)

Total derivatives not designated as hedging instruments, net			82			205

Total derivatives, net		$	84		$	(30	)

_____________

(1)	Includes $9 million of risk management assets classified as held for sale as of September 30, 2009.

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 nine months ended September 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 $184 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 September 30, 2009 was approximately $532 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 (and prior to July 28, 2009, as further discussed below) 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.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

The PPEA interest rate swap agreements are unconditionally and irrevocably guaranteed by Ambac Assurance Corporation (“Ambac”). On July 28, 2009, Ambac’s credit rating was downgraded. As a result of the Ambac downgrade, on October 16, 2009, PPEA’s credit rating was also downgraded. Based on PPEA’s downgrade, the interest rate swap agreements can now be terminated at Ambac’s discretion, which would result in an obligation by PPEA to pay the termination value. Ambac has the ability to control the termination of these swaps at its sole discretion under the applicable agreements; therefore, the associated risk management liability has been classified as current at September 30, 2009. However, Ambac has given no indication that it intends to cause the swaps to be terminated. In fact, if it were to do so, it would trigger its own obligation as insurer to pay the termination value to the swap counterparties, as PPEA does not have the resources to do so. In addition, Ambac can also consent to a request by any of the counterparties to terminate the interest rate swaps, which would result in a payment obligation by PPEA for the termination value. However, should PPEA fail to pay the termination value, Ambac would only be required to pay the scheduled quarterly settlements. Failure to pay the termination value could result in the potential acceleration of PPEA’s debt. Please read Note 6—Impairment Charges—Other for further discussion of our obligations to PPEA.

Based on the events described above, as of July 28, 2009, we believe the interest rate swap agreements no longer qualify for cash flow hedge accounting because the hedged forecasted transaction (that is, the future interest payments arising from the Plum Point Credit Agreement Facility) is no longer probable of occurring. We performed a final effectiveness test as of July 28, 2009 and no ineffectiveness was recorded. The amounts previously deferred in Accumulated other comprehensive income (loss) were not reclassified into earnings because, although the likelihood of the forecasted transaction is not high enough to be considered probable of occurring at September 30, 2009, it is also not low enough that we would consider it probable that the future interest payments associated with the underlying debt will not occur. The change in value of the interest rate swap agreements from July 28, 2009 through September 30, 2009 was a loss of approximately $9 million, and is included in Interest expense on our unaudited condensed consolidated statement of operations. As a result of discontinuing hedge accounting for the interest rate swaps, all prospective changes in the fair value and associated settlements of these interest rate swaps will impact earnings. Please read Note 10—Debt—Plum Point Credit Agreement Facility for further discussion.

For the three and nine months ended September 30, 2008, we recorded $1 million and $3 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 any of the periods. During the three and nine months ended September 30, 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 September 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 derivative settlements prior to the dedesignation discussed above are 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 (as defined below) 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 the probability of the forecasted transactions not occurring. For example, if there were an event of default under the PPEA Credit Agreement Facility, it would be probable that the forecasted transactions (that is, the underlying interest payments) would not occur and the balance in Accumulated other comprehensive income (loss) would be immediately reclassified to earnings.

The PPEA interest rate swap agreements contain provisions that require PPEA’s debt to maintain an investment grade credit rating from a major credit rating agency. As PPEA’s debt has fallen below investment grade, the counterparties to two of the three interest rate swap agreements could request immediate payment or demand collateralization on instruments in net liability positions if Ambac, as guarantor, were to declare bankruptcy. However, absent an Ambac bankruptcy, PPEA is under no obligation to post collateral or terminate the swaps. A default on PPEA’s obligations pursuant to the interest rate swap agreements would cause PPEA to also be in default of the terms of its project debt. Our obligations related to our investment in PPEA are limited to our $15 million letter of credit issued under our Credit Facility to support our contingent equity contribution to the Plum Point Project. Please read Note 10— Debt—Plum Point Credit Agreement Facility 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 September 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 September 30, 2009 and 2008 is presented below:

Derivatives in Cash Flow Hedging	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) For the Three Months Ended September 30,					Location of Loss Reclassified from Accumulated OCI into Income	Amount of Loss Reclassified from Accumulated OCI into Income (Effective Portion) For the Three Months Ended September 30,
Relationships	2009		2008			(Effective Portion)	2009			2008
	(in millions)						(in millions)
Interest rate contracts	$	45	$	(21	)	Interest expense	$	(1	)	$	—
Commodity contracts (1)		—		—		Revenues		—			(10	)

Total	$	45	$	(21	)		$	(1	)	$	(10	)

________________________

(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.

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 nine months ended September 30, 2009 and 2008 is presented below:

Derivatives in Cash Flow Hedging	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion) For the Nine Months Ended September 30,					Location of Loss Reclassified from Accumulated OCI into Income	Amount of Loss Reclassified from Accumulated OCI into Income (Effective Portion) For the Nine Months Ended September 30,
Relationships	2009		2008			(Effective Portion)	2009		2008
	(in millions)						(in millions)
Interest rate contracts	$	160	$	(27	)	Interest expense	$	—	$	—
Commodity contracts (1)		—		—		Revenues		—		(22	)

Total	$	160	$	(27	)		$	—	$	(22	)

________________________

(1)

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 nine months ended September 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 nine months ended September 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.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

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 nine months ended September 30, 2009 and 2008 was immaterial.

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 account for changes in the fair value of these derivatives within the unaudited condensed consolidated statements of operations (herein referred to as “mark-to-market accounting treatment”). 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 months ended September 30, 2009, our revenues included approximately $123 million of mark-to-market losses related to this activity compared to $863 million of mark-to-market gains in the same period in the prior year. For the nine months ended September 30, 2009, our revenues included approximately $67 million of mark-to-market losses related to this activity compared to $125 million of mark-to-market gains 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 September 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 September 30,
Instruments	Derivatives	2009			2008
		(in millions)
Commodity contracts	Revenues	$	59		$	811
Interest rate contracts	Interest expense		(14	)		(1	)

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the nine months ended September 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 Nine Months Ended September 30,
Instruments	Derivatives	2009			2008
		(in millions)
Commodity contracts	Revenues	$	345		$	49
Interest rate contracts	Interest expense		(14	)		(1	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 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 September 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 September 30, 2009
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities (1)	$	—	$	1,126		$	85		$	1,211
Assets from interest rate swaps		—		20			—			20
Other (2)		—		11			—			11

Total	$	—	$	1,157		$	85		$	1,242

Liabilities:
Liabilities from commodity risk management activities	$	—	$	(1,012	)	$	(56	)	$	(1,068	)
Liabilities from interest rate swaps		—		(20	)		(59	)		(79	)

Total	$	—	$	(1,032	)	$	(115	)	$	(1,147	)

______________

(1)

Includes $2 million and $7 million in Levels 2 and 3, respectively, that is classified as Assets held for sale on our unaudited condensed consolidated balance sheet as of September 30, 2009.

(2)

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 September 30, 2009
	(in millions)
Balance at June 30, 2009	$	43
Realized and unrealized gains, net		3
Purchases, issuances and settlements		(26	)
Transfer to Level 3		(50	)

Balance at September 30, 2009	$	(30	)

Unrealized gains relating to instruments still held as of September 30, 2009	$	(4	)

	Nine Months Ended September 30, 2009
	(in millions)
Balance at December 31, 2008	$	59
Realized and unrealized gains, net		26
Purchases, issuances and settlements		(65	)
Transfer to Level 3		(50	)

Balance at September 30, 2009	$	(30	)

Unrealized gains relating to instruments still held as of September 30, 2009	$	(9	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 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. As of September 30, 2009, PPEA held interest rate swaps with a contractual net liability of approximately $135 million. The fair value of these liabilities is estimated to be approximately $59 million as it reflects a valuation adjustment for the recent deterioration of PPEA’s credit worthiness pursuant to fair value accounting standards. As a result of the significance of the credit valuation adjustment, these interest rate swaps are now reflected in Level 3

On January 1, 2009, we adopted authoritative guidance, 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 is that a third-party credit enhancement does not relieve the issuer of its ultimate obligation under the liability. We had approximately $190 million of cash collateral postings as of September 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 $886 million of letters of credit issued as of September 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, 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 September 30, 2009, our adoption of this authoritative guidance did not result in a material effect on our unaudited condensed consolidated financial statements for the three or nine months ended September 30, 2009.

On January 1, 2009, we adopted authoritative guidance for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis, which had been deferred under existing authoritative guidance. 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 September 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 September 30, 2009
	Level 1		Level 2		Level 3		Total		Total Losses
	(in millions)
Assets/Liabilities:
Goodwill	$	—	$	—	$	—	$	—	$	(433	)
Assets held for sale and liabilities associated with assets held for sale		—		—		1,258		1,258		(584	)
Assets held and used		—		—		—		—		(209	)

Total	$	—	$	—	$	1,258	$	1,258	$	(1,226	)

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.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

During the nine months ended September 30, 2009, long-lived assets held and used were written down to their fair value of zero, resulting in an impairment charge of $209 million, which is included in Impairment and other charges on our unaudited condensed consolidated statements of operations. In addition, during the nine months ended September 30, 2009, net assets/liabilities held for sale were written down to their fair value of $1,258 million, less costs to sell of $25 million, resulting in an impairment charge of $584 million. Of this amount, $326 million is included in Impairment and other charges and $258 million is included in Income (loss) on discontinued operations on our unaudited condensed consolidated statements of operations. Please read Note 6—Impairment Charges for further discussion.

On June 30, 2009, we adopted authoritative guidance 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 this authoritative guidance had no impact on our financial statements.

Fair Value of Financial Instruments. On June 30, 2009, we adopted authoritative guidance, 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.

	September 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)	$	—		$	—		$	(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)		(61	)		(61	)		(2	)		(2	)
Commodity-based derivative contracts not designated as accounting hedges (1)(3)		143			143			207			207
Other (2)		11			11			25			25

Total	$	95		$	95		$	(5	)	$	(5	)

____________

(1)

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

(2)

Other represents short-term and long-term investments.

(3)

Includes $9 million of net commodity derivative contracts not designated as accounting hedges classified as held for sale as of September 30, 2009.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

Note 6—Impairment Charges

The following summarizes pre-tax impairment charges recorded during 2009 which are included in Impairment and other charges in our unaudited condensed consolidated statements of operations:

	GEN-MW			GEN-WE		GEN-NE			Total
	(in millions)
Three months ended June 30, 2009:
Assets included in proposed sale to LS Power	$	—		$	—	$	(179	)	$	(179	)
Roseton and Danskammer		—			—		(208	)		(208	)
Total 2nd Quarter Impairment Charges		—			—		(387	)		(387	)

Three months ended September 30, 2009:
Assets included in proposed sale to LS Power (1)		(147	)		—		—			(147	)
Roseton and Danskammer		—			—		(1	)		(1	)
Total 3rd Quarter Impairment Charges		(147	)		—		(1	)		(148	)

Impairment Charges for the Nine Months Ended September 30, 2009	$	(147	)	$	—	$	(388	)	$	(535	)

____________

(1)

Upon classification of these assets as held for sale at August 9, 2009, we recognized impairment charges of $196 million and $19 million in our GEN-MW and GEN-NE segments, respectively. At September 30, 2009, based on an increase in the fair value of the consideration to be received, we recovered $49 million and $19 million of the impairment charges in our GEN-MW and GEN-NE segments, respectively.

The following summarizes pre-tax impairment charges recorded during 2009 which are included in Income (loss) from discontinued operations in our unaudited condensed consolidated statements of operations:

	GEN-MW			GEN-WE			GEN-NE		Total
	(in millions)
Three months ended March 31, 2009:
Bluegrass (included in the proposed sale to LS Power)	$	(5	)	$	—		$	—	$	(5	)
Total 1st Quarter Impairment Charges		(5	)		—			—		(5	)

Three months ended June 30, 2009:
Assets included in proposed sale to LS Power		(18	)		—			—		(18	)
Total 2nd Quarter Impairment Charges		(18	)		—			—		(18	)

Three months ended September 30, 2009:
Assets included in proposed sale to LS Power (1)		—			(235	)		—		(235	)
Total 3rd Quarter Impairment Charges		—			(235	)		—		(235	)

Impairment Charges for the Nine Months Ended September 30, 2009	$	(23	)	$	(235	)	$	—	$	(258	)

____________

(1)

Upon classification of these assets as held for sale at August 9, 2009, we recognized an impairment charge of $292 million and $4 million in our GEN-WE and GEN-MW segments, respectively. At September 30, 2009, based on an increase in the fair value of the consideration to be received, we recovered $57 million and $4 million of the impairment charges in our GEN-WE and GEN-MW segments, respectively.

Goodwill Impairment. 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 Income (loss) on discontinued operations 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. Please read Note 2—Dispositions and Discontinued Operations—Discontinued Operations—Arlington Valley, Griffith and Bluegrass 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 September 30, 2009 and 2008

Assets Included in Sale to LS Power. 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 included in Impairment and other charges in our unaudited condensed consolidated statements of operations 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 included in Income (loss) from discontinued operations in our unaudited condensed consolidated statements of operations 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. 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 transaction with LS Power.

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. Upon reaching the agreement with LS Power discussed further in Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction, the assets qualified as held for sale, and additional impairment charges were recorded, as discussed below.

On August 9, 2009, we entered into a purchase and sale agreement with LS Power. At that time, the operating assets included in that agreement met the criteria of held for sale. Accordingly, we updated our impairment analysis reflecting the estimated fair value for the consideration to be received from LS Power inclusive of costs to sell. As a result, we recognized pre–tax impairment charges of $147 million and $235 million in our GEN-MW and GEN-WE segments, respectively, for the three month period ended September 30, 2009. The $147 million charge is included in Impairment and other charges in our unaudited condensed consolidated statements of operations. The $235 million charge is included in Income (loss) on discontinued operations in our unaudited condensed consolidated statements of operations.

At September 30, 2009, the fair value of the consideration was based partially upon the closing stock price of Dynegy’s Class A common stock of $2.55 per share. We expect to record additional gains or losses on the sale of these assets upon close of the transaction anticipated to occur in the fourth quarter 2009, based on changes subsequent to September 30, 2009 in the fair value of the shares to be received as part of the consideration for this transaction, changes in the fair value of debt to be issued, or changes in working capital items not reimbursed by the purchaser. In addition, we expect to record a loss of approximately $85 million on the sale of our Sandy Creek investment included in this transaction, based on the value of our investment in Sandy Creek at September 30, 2009. This estimate could change materially based on changes in the value of our investment between September 30, 2009 and the close of the transaction.

Roseton and Danskammer. 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. Based on a continuation of expected cash flow losses for these assets in 2009, we recorded additional impairment charges of $1 million ($1 million after tax) for the three months ended September 30, 2009.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

Other. At September 30, 2009, we assessed the carrying amount of our Plum Point assets for impairment because we believed it was more likely than not that we would sell our interest in PPEA before the end of its useful life. In performing this analysis, we used a 50 percent likelihood of a sales transaction occurring in the fourth quarter 2009, and a 50 percent likelihood on our continuing to own the asset while seeking a buyer, and we concluded that an impairment is not indicated. We have no further obligation to provide any financial or other support to PPEA beyond the $15 million letter of credit we have posted to support our contingent equity contribution (as distinct from financial or other support provided by the holders of the remaining interests in PPEA Holding). As a result, we would not be obligated to either (i) sell the assets at a price below an amount that would settle the liabilities associated with Plum Point after considering the equity commitments of PPEA’s owners, or (ii) own and operate it at a loss that would require us to contribute more than $15 million. However, if we do complete a sale of our interest in PPEA during the fourth quarter, we would expect to recognize a loss on the sale, as we would recognize through the statement of operations losses associated with PPEA’s interest rate swaps that were previously recorded in Accumulated other comprehensive loss.

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 and anticipated timing of the sale of certain assets to LS Power. 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 and 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:

	September 30, 2009			December 31, 2008
	(in millions)
Cash flow hedging activities, net	$	(93	)	$	(125	)
Unrecognized prior service cost and actuarial loss		(65	)		(66	)
Accumulated other comprehensive loss—unconsolidated investments		(21	)		(24	)

Accumulated other comprehensive loss, net of tax	$	(179	)	$	(215	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 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 nine months ended September 30, 2009. During October 2009, we entered into an agreement to sell two of these facilities to a third party. As we do not consolidate these entities, we will not record a gain or loss upon completion of the transaction. We expect to close the transaction during the fourth quarter 2009, pending the receipt of required regulatory approvals. 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 September 30, 2009 (which amount does not include investments by the holders of the remaining interests in PPEA Holding) was a liability of approximately $64 million. Our unaudited condensed consolidated balance sheet included $570 million of plant construction in progress at September 30, 2009 that is collateral for the Plum Point Project debt, which is nonrecourse to us. As of September 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:

	September 30, 2009			December 31, 2008
	(in millions)
As of:
Current assets	$	2		$	1
Property, plant and equipment, net		573			507
Intangible asset		193			193
Other non-current asset		31			29
Total assets		799			730
Current liabilities		80			19
Long-term debt		705			615
Non-current liabilities		6			244
Noncontrolling interest		77			(30	)
Accumulated other comprehensive loss		(157	)		(215	)
For the period ending:
Operating loss		—			(1	)
Net loss		(7	)		(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 September 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 September 30, 2009, we had $8 million included in non-current Accounts receivable, affiliate and $63 million included in Other long-term liabilities on our unaudited condensed consolidated balance sheets. We believe that our maximum exposure to economic loss from these VIEs is limited to $283 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 $85 million based on the fair value of these investments, compared to the book value of our investment at September 30, 2009. 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 September 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 nine 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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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

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 September 30, 2009	$	—		$	—		$	—		$	—

Note 10—Debt

	September 30, 2009				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Term Loan B, due 2013	$	69	$	66	$	69	$	52
Term Facility, floating rate due 2013		850		814		850		639
Senior Notes and Debentures:
6.875 percent due 2011		502		506		502		427
8.75 percent due 2012		501		509		501		426
7.5 percent due 2015		550		505		550		388
8.375 percent due 2016		1,047		964		1,047		742
7.125 percent due 2018		172		132		173		110
7.75 percent due 2019		1,100		936		1,100		762
7.625 percent due 2026		171		116		172		93
Subordinated Debentures payable to affiliates, 8.316 percent, due 2027		200		110		200		83
Sithe Senior Notes, 9.0 percent due 2013		316		318		344		328
Plum Point Credit Agreement Facility, floating rate due 2010 (1)		605		277		515		365
Plum Point Tax Exempt Bonds, floating rate due 2036		100		100		100		100
		6,183				6,123
Unamortized premium on debt, net		10				13
		6,193				6,136
Less: Amounts due within one year, including non-cash amortization of basis adjustments		65				64
Total Long-Term Debt	$	6,128			$	6,072

_______

(1)

Upon completion of the construction of the Plum Point Project, the $700 million construction loan will terminate and the debt will be replaced by a $700 million term loan commitment. The term loan commitment 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.

From July 1, 2009 through September 30, 2009, DHI’s ability to draw upon its available capacity under the Credit Facility was reduced temporarily as a result of borrowing limitations under the covenant regarding the ratio of secured debt to EBITDA. As of October 1, 2009, the capacity was restored.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

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:

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: 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: 1.75:1 (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: 6.00:1 (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 net 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 would be increased to either 2.375 percent or 2.75 percent per annum for Revolving Facility 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. The margin for Term Loan borrowing was amended to provide that the applicable margin would be increased to either 2.75 percent per annum for base rate loans or 3.75 percent per annum for Eurodollar loans.

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 are BB+ or Ba1 or higher, respectively, and the higher commitment fee being payable if such ratings are both less than BB+ and Ba1.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

We are currently in compliance with our covenants.

PPEA Credit Agreement Facility. On October 16, 2009, Standard & Poor’s downgraded PPEA’s credit rating from “BBB-” to “CC”. If Ambac, as the insurer of PPEA’s interest rate swaps, enters bankruptcy, the counterparties to these swaps could demand collateralization or immediate termination payments on the swaps, which are in contractual net liability positions of $135 million as of September 30, 2009. The fair value of these derivative liabilities as reflected in our unaudited condensed consolidated balance sheets is $59 million as it reflects a valuation adjustment for the deterioration of PPEA’s creditworthiness pursuant to the fair value accounting standards. PPEA does not have the liquidity to collateralize the swaps or pay the estimated interest rate swap termination obligations. Failure to pay the interest rate swap obligations would likely result in an Event of Default under the Credit Agreement Facility and a potential acceleration of debt. The PPEA Credit Agreement Facility is a non-recourse facility and our liability (as distinct from the obligations of the holders of the remaining interests in PPEA Holding) would be limited to our $15 million letter of credit supporting our equity commitment. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments—Cash Flow Hedges for further discussion.

Note 11—Related Party Transactions

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.

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. Upon completion of the agreement with LS Power discussed above, assets related to repowering or expansion opportunities at the Bridgeport, Arlington Valley, and Griffith facilities will be transferred to LS Power in connection with the sale of those facilities. Please read Note 8—Variable Interest Entities—DLS Power Holdings and DLS Power Development for further information.

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

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

Note 12—Dynegy’s Earnings (loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy’s common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy’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 earnings (loss) per share from continuing operations to diluted earnings (loss) per share from continuing operations is shown in the following table:

	Three Months Ended September 30,						Nine months Ended September 30,
	2009			2008			2009			2008
	(in millions, except per share amounts)
Income (loss) from continuing operations	$	(94	)	$	572		$	(765	)	$	165
Less: Net loss attributable to the noncontrolling interests		(11	)		(1	)		(14	)		(3	)
Income (loss) from continuing operations attributable to Dynegy Inc. for basic and diluted income (loss) per share	$	(83	)	$	573		$	(751	)	$	168

Basic weighted-average shares		843			840			842			840
Effect of dilutive securities:
Stock options and restricted stock		3			2			3			2
Diluted weighted-average shares		846			842			845			842

Earnings (loss) per share from continuing operations attributable to Dynegy Inc.:

Basic	$	(0.10	)	$	0.68		$	(0.89	)	$	0.20

Diluted (1)	$	(0.10	)	$	0.68		$	(0.89	)	$	0.20

____________________________

(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 Inc. has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2009.

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 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.

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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 power generation 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 power generation 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 power generation 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 the Moss Landing power generation facility 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 California Supreme Court, which was granted in March 2008. The California Supreme Court deferred further action 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, the U.S. Supreme Court issued its decision on April 1, 2009. On September 9, 2009, the California Supreme Court directed the parties to brief all issues raised by the pleadings. The petitioner’s brief is due on December 8, 2009 and our response is due on January 7, 2010. We believe that petitioner’s claims lack merit and we plan to continue opposing those claims vigorously.

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.

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On June 30, 2009, the California State Water Resources Control Board issued its draft Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (the “policy”). 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’s 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. A public hearing was held on the policy on September 15, 2009 and public comments were taken through September 30, 2009. We filed substantial comments on the draft policy on September 29, 2009.

Given the numerous variables and factors involved in calculating the potential costs associated with closed cycle cooling, 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. Oral argument is scheduled in November 2009.

In February 2008, the U.S. 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, but only upon final resolution of all pending claims against all other defendants.

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 was 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 fourth quarter 2009.

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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 based on the court’s lack of subject matter jurisdiction over plaintiffs’ federal claim for common law nuisance. In particular, defendants argued that under the political question doctrine, the court lacks jurisdiction to consider the merits of plaintiffs’ nuisance claim because its resolution would require the court to make policy determinations which are inherently political. In October 2009, the court granted defendants’ motions and dismissed all of plaintiffs’ claims. The decision is subject to appeal.

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 September 30, 2009.

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.

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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. We entered into indemnifications regarding environmental, tax, employee and other representations when completing asset sales such as, but not limited to the Rolling Hills, Calcasieu, CoGen Lyondell and Heard County power generating facilities. As of September 30, 2009, no claims have been made against these indemnities. There is no limitation on our liability under these indemnities. However, management is unaware of any existing claims.

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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 September 30,
	2009			2008			2009		2008
	(in millions)
Service cost benefits earned during period	$	3		$	3		$	1	$	1
Interest cost on projected benefit obligation		3			3			1		1
Expected return on plan assets		(3	)		(3	)		—		—
Recognized net actuarial loss		1			—			—		—

Net periodic benefit cost	$	4		$	3		$	2	$	2

	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2009			2008			2009		2008
	(in millions)
Service cost benefits earned during period	$	9		$	8		$	2	$	2
Interest cost on projected benefit obligation		9			9			3		3
Expected return on plan assets		(10	)		(10	)		—		—
Recognized net actuarial loss		3			1			—		—

Net periodic benefit cost	$	11		$	8		$	5	$	5

Contributions. During the nine months ended September 30, 2009, we made $24 million in contributions to our pension plans and other postretirement benefit plans. We made $29 million in contributions to our pension plans and other postretirement benefit plans during the nine months ended September 30, 2008. We made an additional $3 million of contributions to our pension and other postretirement benefit plans in October 2009.

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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 September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in millions, except rates)
Income tax benefit (expense)	$	34		$	(392	)	$	147		$	(121	)

Effective tax rate		27	%		41	%		16	%		42	%

For the nine months ended September 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 $19 million. As a result of the proposed sale of assets to LS Power, 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 nine months ended September 30, 2009. The third quarter provision also considers the impact of $39 million of disallowed losses associated with the proposed sale of assets to LS Power. For the three and nine months ended September 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.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2009			2008			2009			2008
	(in millions, except rates)
Income tax benefit (expense)	$	35		$	(391	)	$	152		$	(127	)

Effective tax rate		27	%		41	%		17	%		43	%

For the nine months ended September 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 $14 million. As a result of the proposed sale of assets to LS Power, 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 nine months ended September 30, 2009. The third quarter provision also considers the impact of $39 million of disallowed losses associated with the proposed sale of assets to LS Power. For the three and nine months ended September 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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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 nine months ended September 30, 2009 and 2008 is presented below:

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

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	391		$	110		$	174		$	(2	)	$	673

Total revenues	$	391		$	110		$	174		$	(2	)	$	673

Depreciation and amortization	$	(57	)	$	(15	)	$	(8	)	$	(3	)	$	(83	)
Impairment and other charges		(147	)		—			(1	)		—			(148	)

Operating income (loss)	$	5		$	34		$	1		$	(47	)	$	(7	)

Losses from unconsolidated investments		—			(8	)		—			—			(8	)
Other items, net		—			1			—			1			2
Interest expense														(115	)

Loss from continuing operations before income taxes														(128	)
Income tax benefit														34

Loss from continuing operations														(94	)
Loss from discontinued operations, net of taxes														(129	)

Net loss														(223	)
Less: Net loss attributable to the noncontrolling interests														(11	)

Net loss attributable to Dynegy Inc.													$	(212	)

Identifiable assets:
Domestic	$	6,703		$	2,636		$	2,027		$	1,663		$	13,029
Other		—			—			—			(5	)		(5	)

Total	$	6,703		$	2,636		$	2,027		$	1,658		$	13,024

Capital expenditures	$	(120	)	$	(2	)	$	(2	)	$	(2	)	$	(126	)

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For the Interim Periods Ended September 30, 2009 and 2008

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

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	997		$	323		$	426		$	(4	)	$	1,742
Other		—			—			17			—			17

Total revenues	$	997		$	323		$	443		$	(4	)	$	1,759

Depreciation and amortization	$	(49	)	$	(20	)	$	(14	)	$	(2	)	$	(85	)

Operating income (loss)	$	757		$	153		$	204		$	(51	)	$	1,063

Losses from unconsolidated investments		—			(5	)		—			—			(5	)
Other items, net		—			1			(1	)		11			11
Interest expense														(105	)

Income from continuing operations before income taxes														964
Income tax expense														(392	)

Income from continuing operations														572
Income from discontinued operations, net of taxes														32

Net income														604
Less: Net loss attributable to the noncontrolling interests														(1	)
Net income attributable to Dynegy Inc.													$	605

Identifiable assets:
Domestic	$	6,637		$	3,406		$	2,458		$	1,677		$	14,178
Other		—			—			16			8			24

Total	$	6,637		$	3,406		$	2,474		$	1,685		$	14,202

Unconsolidated investments	$	—		$	—		$	—		$	62		$	62

Capital expenditures and investments in unconsolidated affiliates	$	(145	)	$	(5	)	$	(7	)	$	(4	)	$	(161	)

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For the Interim Periods Ended September 30, 2009 and 2008

Dynegy’s Segment Data as of and for the Nine Months Ended September 30, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	1,085		$	293		$	652		$	(3	)	$	2,027

Total revenues	$	1,085		$	293		$	652		$	(3	)	$	2,027

Depreciation and amortization	$	(165	)	$	(45	)	$	(39	)	$	(9	)	$	(258	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges		(147	)		—			(388	)		—			(535	)

Operating income (loss)	$	143		$	(209	)	$	(424	)	$	(134	)	$	(624	)

Earnings from unconsolidated investments		—			12			—			1			13
Other items, net		2			3			—			5			10
Interest expense														(311	)

Loss from continuing operations before income taxes														(912	)
Income tax benefit														147

Loss from continuing operations														(765	)
Loss from discontinued operations, net of taxes														(141	)

Net loss														(906	)
Less: Net loss attributable to the noncontrolling interests														(14	)

Net loss attributable to Dynegy Inc.													$	(892	)

Identifiable assets:
Domestic	$	6,703		$	2,636		$	2,027		$	1,663		$	13,029
Other		—			—			—			(5	)		(5	)

Total	$	6,703		$	2,636		$	2,027		$	1,658		$	13,024

Capital expenditures	$	(394	)	$	(10	)	$	(20	)	$	(5	)	$	(429	)

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For the Interim Periods Ended September 30, 2009 and 2008

Dynegy’s Segment Data as of and for the Nine Months Ended September 30, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	1,226		$	556		$	661		$	(4	)	$	2,439
Other		—			—			111			—			111

Total revenues	$	1,226		$	556		$	772		$	(4	)	$	2,550

Depreciation and amortization	$	(153	)	$	(57	)	$	(41	)	$	(7	)	$	(258	)

Operating income (loss)	$	529		$	104		$	41		$	(95	)	$	579

Losses from unconsolidated investments		—			(7	)		—			(10	)		(17	)
Other items, net		—			5			5			36			46
Interest expense														(322	)

Income from continuing operations before income taxes														286
Income tax expense														(121	)

Income from continuing operations														165
Income from discontinued operations, net of taxes														13

Net income														178
Less: Net loss attributable to the noncontrolling interests														(3	)

Net income attributable to Dynegy Inc.													$	181

Identifiable assets:
Domestic	$	6,637		$	3,406		$	2,458		$	1,677		$	14,178
Other		—			—			16			8			24

Total	$	6,637		$	3,406		$	2,474		$	1,685		$	14,202

Unconsolidated investments	$	—		$	—		$	—		$	62		$	62
Capital expenditures and investments in unconsolidated affiliates	$	(394	)	$	(26	)	$	(29	)	$	(22	)	$	(471	)

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For the Interim Periods Ended September 30, 2009 and 2008

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

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

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	391		$	110		$	174		$	(2	)	$	673

Total revenues	$	391		$	110		$	174		$	(2	)	$	673

Depreciation and amortization	$	(57	)	$	(15	)	$	(8	)	$	(3	)	$	(83	)
Impairment and other charges		(147	)		—			(1	)		—			(148	)

Operating income (loss)	$	5		$	34		$	1		$	(47	)	$	(7	)

Losses from unconsolidated investments		—			(8	)		—			—			(8	)
Other items, net		—			1			—			1			2
Interest expense														(115	)

Loss from continuing operations before income taxes														(128	)
Income tax benefit														35

Loss from continuing operations														(93	)
Loss from discontinued operations, net of taxes														(139	)

Net loss														(232	)
Less: Net loss attributable to the noncontrolling interests														(11	)

Net loss attributable to Dynegy Holdings Inc.													$	(221	)

Identifiable assets:
Domestic	$	6,703		$	2,636		$	2,027		$	1,481		$	12,847
Other		—			—			—			(5	)		(5	)

Total	$	6,703		$	2,636		$	2,027		$	1,476		$	12,842

Capital expenditures	$	(120	)	$	(2	)	$	(2	)	$	(2	)	$	(126	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

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

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	997		$	323		$	426		$	(4	)	$	1,742
Other		—			—			17			—			17

Total revenues	$	997		$	323		$	443		$	(4	)	$	1,759

Depreciation and amortization	$	(49	)	$	(20	)	$	(14	)	$	(2	)	$	(85	)

Operating income (loss)	$	757		$	153		$	204		$	(51	)	$	1,063

Losses from unconsolidated investments		—			(5	)		—			—			(5	)
Other items, net		—			1			(1	)		11			11
Interest expense														(105	)

Income from continuing operations before income taxes														964
Income tax expense														(391	)

Income from continuing operations														573
Income from discontinued operations, net of taxes														32

Net income														605
Less: Net loss attributable to the noncontrolling interests														(1	)

Net income attributable to Dynegy Holdings Inc.													$	606

Identifiable assets:
Domestic	$	6,637		$	3,406		$	2,458		$	1,575		$	14,076
Other		—			—			16			8			24

Total	$	6,637		$	3,406		$	2,474		$	1,583		$	14,100


Capital expenditures	$	(145	)	$	(5	)	$	(7	)	$	(4	)	$	(161	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

DHI’s Segment Data as of and for the Nine Months Ended September 30, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	1,085		$	293		$	652		$	(3	)	$	2,027

Total revenues	$	1,085		$	293		$	652		$	(3	)	$	2,027

Depreciation and amortization	$	(165	)	$	(45	)	$	(39	)	$	(9	)	$	(258	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges		(147	)		—			(388	)		—			(535	)

Operating income (loss)	$	143		$	(209	)	$	(424	)	$	(136	)	$	(626	)

Earnings from unconsolidated investments		—			12			—			—			12
Other items, net		2			3			—			4			9
Interest expense														(311	)

Loss from continuing operations before income taxes														(916	)
Income tax benefit														152

Loss from continuing operations														(764	)
Loss from discontinued operations, net of taxes														(141	)

Net loss														(905	)
Less: Net loss attributable to the noncontrolling interests														(14	)

Net loss attributable to Dynegy Holdings Inc.													$	(891	)

Identifiable assets:
Domestic	$	6,703		$	2,636		$	2,027		$	1,481		$	12,847
Other		—			—			—			(5	)		(5	)

Total	$	6,703		$	2,636		$	2,027		$	1,476		$	12,842

Capital expenditures	$	(394	)	$	(10	)	$	(20	)	$	(5	)	$	(429	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2009 and 2008

DHI’s Segment Data as of and for the Nine Months Ended September 30, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	1,226		$	556		$	661		$	(4	)	$	2,439
Other		—			—			111			—			111

Total revenues	$	1,226		$	556		$	772		$	(4	)	$	2,550

Depreciation and amortization	$	(153	)	$	(57	)	$	(41	)	$	(7	)	$	(258	)

Operating income (loss)	$	529		$	104		$	41		$	(95	)	$	579

Losses from unconsolidated investments		—			(7	)		—			—			(7	)
Other items, net		—			5			5			35			45
Interest expense														(322	)

Income from continuing operations before income taxes														295
Income tax expense														(127	)

Income from continuing operations														168
Income from discontinued operations, net of taxes														13

Net income														181
Less: Net loss attributable to the noncontrolling interests														(3	)

Net income attributable to Dynegy Holdings Inc.													$	184

Identifiable assets:
Domestic	$	6,637		$	3,406		$	2,458		$	1,575		$	14,076
Other		—			—			16			8			24

Total	$	6,637		$	3,406		$	2,474		$	1,583		$	14,100

Capital expenditures	$	(394	)	$	(26	)	$	(29	)	$	(11	)	$	(460	)

Note 17—Subsequent Events

We have evaluated subsequent events through November 5, 2009, the date our financial statements were issued and up to the time of the filing of our financial statements with the SEC.

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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 September 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, as supplemented by our Current Report on Form 8-K dated September 28, 2009, which we refer to as each registrant’s “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 McLennan County, Texas, which is included in GEN-WE. On August 9, 2009, we entered into an agreement with LS Power to sell our interests in various power generation facilities, including the Sandy Creek Project together with certain other assets. 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 pursuant to 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 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 to Adio Bond, LLC, an affiliate of LS Power. We will receive at closing approximately $1.025 billion in cash (consisting, in part, of the release of $175 million of restricted cash on our unaudited condensed consolidated balance sheets that was used to support our funding commitment to Sandy Creek and approximately $200 million for the unsecured notes), subject to working capital adjustments, and 245 million of Dynegy’s Class B shares from LS Power.

Upon closing of the transaction, the remaining 95 million shares of Dynegy’s Class B common stock held by LS Power will be converted into the same 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 for a specified period and eliminate special approval, board representation and certain other rights associated with the former Class B common shares. We expect to close the LS Power transaction in the fourth quarter 2009 assuming all necessary closing conditions are satisfied. Please read Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further information.

Based on the fair value at September 30, 2009 of the consideration to be received from LS Power, we recorded further pre-tax impairment charges of approximately $382 million in the third quarter 2009 upon the asset groups meeting the criteria of held for sale. Of the $382 million, approximately $235 million is included in Income (loss) from discontinued operations in our unaudited condensed consolidated statements of operations in the GEN-WE segment. The impairment charges recorded in the third quarter were based on our estimate of the fair value of the proceeds to be received from LS Power and its affiliates which reflects Dynegy’s stock price at September 30, 2009 of $2.55 per share. We will record additional gains or losses on the sale based on changes between September 30, 2009 and the closing of the transaction in the fair value of consideration received. Any such gains or losses could be material. Additionally, we expect to record a fourth quarter net loss on the sale of assets of approximately $85 million, related to the sale of our Sandy Creek investment. However, this estimate could change materially based on changes in the value of our investment in Sandy Creek from September 30, 2009 through the time the transaction is closed. 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 (i) modified the financial covenants relating to the ratios of Secured Debt to EBITDA and of EBITDA to Consolidated Interest Expense; (ii) further modified 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; (iii) increased the amount of assets eligible for disposition outside the asset sale, reinvestment and prepayment provisions of the Credit Facility; (iv) expanded our ability to prepay additional debt of DHI under certain conditions; and (v) increased 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.

Multi-Year Cost Savings Initiative. Separate from the LS Power transaction, on August 10, 2009, we announced an extensive, multi-year program to eliminate certain costs throughout the company. Cumulative savings, relative to our original plan, are expected to be $400 million to $450 million over a four-year period beginning in 2010. Annual savings are expected to be generated through reduced capital expenditures, operational expenditures and general and administrative expenditures.

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 and 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 proceeds from asset sales 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 October 29, 2009, September 30, 2009 and December 31, 2008:

	October 29, 2009			September 30, 2009			December 31, 2008
	(in millions)
Revolver capacity (1) (2)	$	1,080		$	903		$	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 (3)		377			377			377
Outstanding letters of credit		(894	)		(886	)		(1,135	)

Unused capacity		1,388			1,219			1,147

Cash—DHI		486			519			670

Total available liquidity—DHI		1,874			1,738			1,817
Cash—Dynegy		183			184			23

Total available liquidity—Dynegy	$	2,057		$	1,922		$	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 $165 million. We have not experienced, nor do we currently anticipate, any difficulties in obtaining funding from any of the current 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)

From July 1, 2009 to September 30, 2009, DHI’s ability to draw on its 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. As of October 1, 2009, the capacity was restored.

(3)

Includes $275 million of capacity related to our investment in Sandy Creek. Under the terms of our purchase and sale agreement with LS Power, this capacity will be eliminated, and $175 million of the $275 million of restricted cash supporting this letter of credit facility will be released to us upon completion of the sale of Sandy Creek to LS Power. See Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further discussion.

Cash on Hand. At October 29, 2009 and September 30, 2009, Dynegy had cash on hand of $669 million and $703 million, respectively, as compared to $693 million at December 31, 2008.

At October 29, 2009 and September 30, 2009, DHI had cash on hand of $486 million and $519 million, respectively, as compared to $670 million at December 31, 2008. The decrease in cash on hand through October 29, 2009 and September 30, 2009 as compared to the end of 2008 is primarily attributable to a dividend of $175 million paid to Dynegy in January 2009.

Operating Activities

Historical Operating Cash Flows. Dynegy’s cash flow provided by operations totaled $304 million for the nine months ended September 30, 2009. DHI’s cash flow provided by operations totaled $322 million for the nine months ended September 30, 2009. During the period, our power generation business provided positive cash flow from operations of $683 million from the operation of our power generation facilities. Cash provided by the operations of our power generation facilities was partly offset by a $160 million increase in collateral postings, excluding 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 $379 million and $361 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 $397 million for the nine months ended September 30, 2008. DHI’s cash flow provided by operations totaled $393 million for the nine months ended September 30, 2008. During the period, our power generation business provided positive cash flow from operations of $757 million. Cash provided by the operations of our power generation facilities was partly offset by a $79 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 $360 million and $364 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, the run time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements and our ability to capture value associated with commodity price volatility. Additionally, the increased costs associated with the Credit Facility amendment and decreased cash outflows related to our cost savings initiative 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 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 October 29, 2009, September 30, 2009 and December 31, 2008:

	October 29, 2009		September 30, 2009		December 31, 2008
	(in millions)
By Business:
Generation	$	1,003	$	975	$	1,064
Other		188		189		189

Total	$	1,191	$	1,164	$	1,253
By Type:
Cash (1)	$	297	$	278	$	118
Letters of Credit		894		886		1,135

Total	$	1,191	$	1,164	$	1,253

__________________

(1)

Cash collateral, including initial margin 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 September 30, 2009 and to October 29, 2009 are primarily related to a increase (decrease) in letters of credit related to certain hedge positions partially offset by increases in initial margin requirements associated with the volume of forward commodity 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.

Investing Activities

Capital Expenditures. We continue to tightly manage our operating costs and capital expenditures. We had approximately $429 million and $460 million in capital expenditures during the nine months ended September 30, 2009 and 2008. Our capital spending by reportable segment was as follows:

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	For the Nine Months Ended September 30,
	2009		2008
	(in millions)

GEN-MW	$	394	$	394
GEN-WE		10		26
GEN-NE		20		29
Other		5		11

Total	$	429	$	460

Capital spending in our GEN-MW segment primarily consisted of environmental and maintenance capital projects, as well as approximately $66 million and $165 million spent on development capital related to the Plum Point Project during the nine months ended September 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 fourth quarter 2009 to be approximately $40 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—Dispositions and Discontinued Operations—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 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 that was used to support our funding commitment to Sandy Creek and approximately $200 million for the unsecured notes), subject to working capital adjustments, and 245 million of Dynegy’s Class B shares held by LS Power. The $175 million of Sandy Creek restricted cash currently appears on our unaudited condensed consolidated balance sheet as part of Restricted cash and investments. Please see Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further information.

Proceeds from asset sales, net of transaction costs, during the nine months ended September 30, 2008 totaled $452 million and primarily related to the sale of our Rolling Hills power generation facility, our Calcasieu power generating facility, the NYMEX shares and seats, and the beneficial interest in Oyster Creek. Please read Note 2—Dispositions and Discontinued Operations—Discontinued Operations.

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 nine months ended September 30, 2009 totaled $14 million and $13 million for Dynegy and DHI, respectively, reflecting a distribution from our short-term investments. There was a $35 million cash outflow during the nine months ended September 30, 2009 for both Dynegy and DHI, related to changes in restricted cash balances. Other included $3 million of insurance proceeds.

Dynegy made $11 million in contributions to DLS Power Holdings during the nine months ended September 30, 2008. We received a distribution of approximately $7 million and repayment of approximately $3 million of an affiliate receivable upon the sale of a partial interest in Sandy Creek during the nine months ended September 30, 2008. Please see Note 8—Variable Interest Entities—Sandy Creek for further discussion.

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Cash outflows related to short-term investments increased by $127 million and $120 million for the nine months ended September 30, 2008 for Dynegy and DHI, respectively, as a result of a reclassification from cash equivalents to short-term investments. Additionally, there was a $17 million cash inflow during the nine months ended September 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. Dynegy received $4 million of proceeds from the liquidation of an investment during the nine months ended September 30, 2008.

Financing Activities

Historical Cash Flow from Financing Activities. Dynegy’s net cash provided by financing activities during the nine months ended September 30, 2009 totaled $47 million, primarily related to $91 million of proceeds from long-term borrowings under the Plum Point Credit Agreement Facility, partly offset by a $28 million principal payment on our 9.00 percent secured bonds due 2013 and $14 million of financing fees related to the Credit Facility Amendment No. 4. DHI’s net cash used in financing activities during the nine months ended September 30, 2009 totaled $128 million. This included a one-time dividend payment from DHI to Dynegy of $175 million, a $28 million principal payment on our 9.00 percent secured bonds due 2013 and $14 million of financing fees related to the Credit Facility Amendment No. 4 offset by $91 million of proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.

Dynegy’s cash provided by financing activities during the nine months ended September 30, 2008 totaled $133 million, which primarily related to proceeds of $158 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 nine months ended September 30, 2008 totaled $131 million, which primarily related to proceeds of $158 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 Dynegy or DHI credit ratings or Dynegy’s 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.

On October 16, 2009, Standard & Poor’s downgraded PPEA’s credit rating. Because of this downgrade, certain interest rate swaps to which Plum Point is a party may be terminated by the counterparties if there is also a default by the insurer, Ambac, which has provided credit insurance for the swaps. The termination value of the Plum Point interest rate swaps at September 30, 2009 was approximately $135 million. Termination of the interest rate swaps, if not paid by PPEA, could result in the acceleration of the PPEA debt. Our obligations related to our investment in PPEA, excluding the noncontrolling interest holders’ obligation, are limited to our $15 million letter of credit issued under our Credit Facility to support our contingent equity contribution to the Plum Point Project. Please read Note 10—Debt—Plum Point Credit Agreement Facility for further discussion.

Capital-Structuring Transactions. Following the completion of 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 the pursuit of one or more financing transactions in the near-term designed to reduce existing debt or other obligations. 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.

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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 is limited by the shareholder agreement with LS Power entered into on August 9, 2009. This agreement provides that we will not 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. Our ability to issue debt securities is limited by our financing agreements, including our Credit Facility, and the note purchase agreement with Adio Bond, LLC, an affiliate of LS Power, for a period of five business days following the closing of the LS Power transaction and for a period of five business days following Adio Bond's request for support in connection with an underwritten resale.

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 third quarter 2009, and does not expect to pay a dividend on 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 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”. On August 12, 2009, Fitch Ratings downgraded our issuer default ratings to “B-” from “B”; downgraded our senior secured to “BB-” from “BB”; downgraded our senior unsecured to “B” from “B+”, based on projected lower power prices affecting credit metrics. On August 18, 2009, Standard and Poor’s issued a rating action revising their outlook to negative from stable. The ratings were affirmed at corporate family rating at “B”; senior secured rating at “BB-”; and senior unsecured rating at “B”. The downgrades did not trigger any obligations under 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 September 30, 2009, there were no material changes to our contractual obligations and contingent financial commitments since December 31, 2008.

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

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

Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three and nine month periods ended September 30, 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 September 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 September 30, 2009 and 2008, respectively:

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

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

Revenues	$	391		$	110		$	174		$	(2	)	$	673
Cost of sales		(129	)		(36	)		(121	)		—			(286	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(53	)		(25	)		(43	)		—			(121	)
Depreciation and amortization expense		(57	)		(15	)		(8	)		(3	)		(83	)
Impairment and other charges		(147	)		—			(1	)		—			(148	)
General and administrative expense		—			—			—			(42	)		(42	)
Operating income (loss)	$	5		$	34		$	1		$	(47	)	$	(7	)
Losses from unconsolidated investments		—			(8	)		—			—			(8	)
Other items, net		—			1			—			1			2
Interest expense														(115	)

Loss from continuing operations before income taxes														(128	)
Income tax benefit														34

Loss from continuing operations														(94	)
Loss from discontinued operations, net of taxes														(129	)
Net loss														(223	)

Less: Net loss attributable to the noncontrolling interests														(11	)

Net loss attributable to Dynegy Inc.													$	(212	)

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

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

Revenues	$	997		$	323		$	443		$	(4	)	$	1,759
Cost of sales		(194	)		(127	)		(179	)		2			(498	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(54	)		(23	)		(46	)		1			(122	)
Depreciation and amortization expense		(49	)		(20	)		(14	)		(2	)		(85	)
Gain on sale of assets, net		57			—			—			—			57
General and administrative expense		—			—			—			(48	)		(48	)
Operating income (loss)	$	757		$	153		$	204		$	(51	)	$	1,063
Losses from unconsolidated investments		—			(5	)		—			—			(5	)
Other items, net		—			1			(1	)		11			11
Interest expense														(105	)

Income from continuing operations before income taxes														964
Income tax expense														(392	)

Income from continuing operations														572
Income from discontinued operations, net of taxes.														32
Net income														604
Less: Net loss attributable to the noncontrolling interests														(1	)

Net income attributable to Dynegy Inc.													$	605

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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 September 30, 2009 and 2008, respectively:

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

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

Revenues	$	391		$	110		$	174		$	(2	)	$	673
Cost of sales		(129	)		(36	)		(121	)		—			(286	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(53	)		(25	)		(43	)		—			(121	)
Depreciation and amortization expense		(57	)		(15	)		(8	)		(3	)		(83	)
Impairment and other charges		(147	)		—			(1	)		—			(148	)
General and administrative expense		—			—			—			(42	)		(42	)
Operating income (loss)	$	5		$	34		$	1		$	(47	)	$	(7	)
Losses from unconsolidated investments		—			(8	)		—			—			(8	)
Other items, net		—			1			—			1			2
Interest expense														(115	)

Loss from continuing operations before income taxes														(128	)
Income tax benefit														35

Loss from continuing operations														(93	)
Loss from discontinued operations, net of taxes														(139	)

Net loss														(232	)
Less: Net loss attributable to the noncontrolling interests														(11	)

Net loss attributable to Dynegy Holdings Inc.													$	(221	)

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

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

Revenues	$	997		$	323		$	443		$	(4	)	$	1,759
Cost of sales		(194	)		(127	)		(179	)		2			(498	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(54	)		(23	)		(46	)		1			(122	)
Depreciation and amortization expense		(49	)		(20	)		(14	)		(2	)		(85	)
Gain on sale of assets, net		57			—			—			—			57
General and administrative expense		—			—			—			(48	)		(48	)
Operating income (loss)	$	757		$	153		$	204		$	(51	)	$	1,063
Losses from unconsolidated investments		—			(5	)		—			—			(5	)
Other items, net		—			1			(1	)		11			11
Interest expense														(105	)

Income from continuing operations before income taxes														964
Income tax expense														(391	)

Income from continuing operations														573
Income from discontinued operations, net of taxes.														32
Net income														605
Less: Net loss attributable to the noncontrolling interests														(1	)

Net income attributable to Dynegy Holdings Inc.													$	606

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

	Three Months Ended September 30,
	2009			2008
GEN-MW
Million Megawatt Hours Generated (1)		6.6			7.1
In Market Availability for Coal Fired Facilities (2)		92	%		95	%
Average Capacity Factor for Combined Cycle Facilities (3)		38	%		28	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Cinergy (Cin Hub)	$	31		$	74
Commonwealth Edison (NI Hub)	$	31		$	73
PJM West	$	40		$	95
Average Market Spark Spreads ($/MWh) (5):
PJM West	$	16		$	27

GEN-WE
Million Megawatt Hours Generated (6) (7)		2.4			2.6
Average Capacity Factor for Combined Cycle Facilities (3)		56	%		72	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
North Path 15 (NP 15)	$	38		$	86
Average Market Spark Spreads ($/MWh) (5):
North Path 15 (NP 15)	$	12		$	25

GEN-NE
Million Megawatt Hours Generated		2.6			2.2
In Market Availability for Coal Fired Facilities (2)		95	%		93	%
Average Capacity Factor for Combined Cycle Facilities (3)		44	%		29	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
New York—Zone G	$	44		$	113
New York—Zone A	$	29		$	76
Mass Hub	$	37		$	95
Average Market Spark Spreads ($/MWh) (5):
New York—Zone A	$	4		$	10
Mass Hub	$	13		$	28
Fuel Oil	$	(72	)	$	(60	)

Average natural gas price—Henry Hub ($/MMBtu) (8)	$	3.15		$	9.10

__________________

(1)

Excludes less than 0.1 million MWh generated by our Bluegrass power generation facility, which is classified in discontinued operations, for each of the periods.

(2)

Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.

(3)

Reflects actual production as a percentage of available capacity. Excludes the Arlington Valley and Griffith power generation facilities which are reported as discontinued operations with respect to the GEN-WE segment.

(4)

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

(5)

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.

(6)

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 September 30, 2009 and 2008, respectively.

(7)

Excludes approximately 0.1 MWh generated by the Heard County power generation facility, which we sold in April 2009, for the three months ended September 30, 2008. Excludes 0.5 MWh and 0.5 MWh generated by our Arlington Valley power generation facility and 1.1 MWh and 1.0 MWh generated by our Griffith power generation facility, which are collectively classified in discontinued operations, for the three months ended September 30, 2009 and 2008 respectively.

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(8)

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

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

	Three Months Ended September 30, 2009
	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other		Total
	(in millions)

Impairments (1)	$	(147	)	$	(235	)	$	(1	)	$	—	$	(383	)

Total	$	(147	)	$	(235	)	$	(1	)	$	—	$	(383	)

(1)

Includes $235 million of impairment charges related to our Arizona power generation facilities which are included in discontinued operations.

	Three Months Ended September 30, 2008
	Power Generation
	GEN-MW		GEN-WE		GEN-NE		Other		Total
	(in millions)
Gain on sale of Rolling Hills	$	57	$	—	$	—	$	—	$	57

Total	$	57	$	—	$	—	$	—	$	57

Operating Income (Loss)

Dynegy’s and DHI’s operating loss was $7 million for the three months ended September 30, 2009, compared to an operating income of $1,063 million for the three months ended September 30, 2008.

Our operating loss for the three months ended September 30, 2009 was driven, in large part, by $148 million of asset impairments. Please read Note 6—Impairment Charges for further discussion.

Mark-to-market losses on forward sales of power associated with our generating assets are included in Revenues in the unaudited condensed consolidated statements of operations. Such losses, which totaled $122 million for the three months ended September 30, 2009, were a result of the expiration of certain risk management positions during the third quarter 2009, for which earnings were recognized in prior periods. These losses compared to $865 million of mark-to-market gains for the three months ended September 30, 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 September 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 $5 million for the three months ended September 30, 2009, compared to income of $757 million for the three months ended September 30, 2008. Such amounts do not include results from our Bluegrass power generating facility, which has been reclassified as a discontinued operation for all periods presented.

Revenues for the three months ended September 30, 2009 decreased by $606 million compared to the three months ended September 30, 2008, cost of sales decreased by $65 million and operating and maintenance expense decreased by $1 million, resulting in a net decrease of $540 million. The decrease was primarily driven by the following:

Mark-to-market losses – GEN-MW’s results for the three months ended September 30, 2009 included mark-to-market losses of $44 million related to forward sales, compared to $568 million of mark-to-market gains for the three months ended September 30, 2008. Of the $44 million in 2009 mark-to-market losses, $92 million of losses related to positions that settled or will settle in 2009, partly offset by $48 million of gains related to positions that will settle in 2010 and beyond;

Decreased volumes —Generated volumes decreased by 7 percent, from 7.1 million MWh for the three months ended September 30, 2008, to 6.6 million MWh for the three months ended September 30, 2009; and

Results were favorably impacted in 2008 by $7 million from the sale of emission credits.

These items were partly offset by the following:

A $50 million payment received to assign our rights to a third party pursuant to a power sales agreement. This agreement would have been in effect through 2011; and

Benefit of economic hedging activity – The average actual on-peak prices in the Cin Hub pricing region decreased from $74 per MWh for the three months ended September 30, 2008 to $31 per MWh for the three months ended September 30, 2009. However, the impact of lower market prices was mitigated by economic hedging, resulting in realized prices that were higher in the three months ended September 30, 2009 than in the three months ended September 30, 2008.

Depreciation expense increased from $49 million for the third quarter 2008 to $57 million for the third quarter 2009 as a result of capital projects placed into service during 2009. These capital projects were primarily related to the Midwest Consent Decree.

In addition, in 2009, we recorded a $147 million impairment of our Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities 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.

Operating income for the three months ended September 30, 2008 included a $57 million gain from the sale of our Rolling Hills power generating facility, reflected in Gain on sale of assets in our unaudited condensed consolidated statements of operations.

Power Generation—West Segment. Operating income for GEN-WE was $34 million for three months ended September 30, 2009, compared to income of $153 million for the three months ended September 30, 2008. Such amounts do not include results from our Arizona and Heard County power generating facilities, which have been reclassified as discontinued operations for all periods presented.

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Revenues for the three months ended September 30, 2009 decreased by $213 million compared to the three months ended September 30, 2008, cost of sales decreased by $91 million and operating and maintenance expense increased by $2 million, resulting in a net decrease of $124 million. The decrease was primarily driven by the following:

Mark-to-market losses – GEN-WE’s results for the three months ended September 30, 2009 included mark-to-market losses of $33 million, compared to $122 million of mark-to-market gains for the three months ended September 30, 2008. Of the $33 million in 2009 mark-to-market losses, $3 million related to positions that settled or will settle in 2009, and the remaining $30 million related to positions that will settle in 2010 and beyond; and

Decreased volumes - Generated volumes were 2.4 million MWh for the three months ended September 30, 2009, down from 2.6 million MWh for the three months ended September 30, 2008. The volume decrease was driven in large part by decreased market spark spreads and reduced dispatch opportunities.

These items were partly offset by increased tolling and capacity revenues of $30 million.

Depreciation expense decreased from $20 million for the third quarter 2008 to $15 million for the third 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 income for GEN-NE was $1 million for the three months ended September 30, 2009, compared to income of $204 million for the three months ended September 30, 2008.

Revenues for the three months ended September 30, 2009 decreased by $269 million compared to the three months ended September 30, 2008, cost of sales decreased by $58 million and operating and maintenance expense decreased by $3 million, resulting in a net decrease of $208 million. The decrease was primarily driven by the following:

Mark-to-market losses – GEN-NE’s results for the three months ended September 30, 2009 included mark-to-market losses of $45 million related to forward sales, compared to gains of $175 million for the three months ended September 30, 2008. Of the $45 million in 2009 mark-to-market losses, $31 million related to positions that settled or will settle in 2009, and the remaining $14 million related to positions that will settle in 2010 and beyond; and

Decreased prices – On-peak market prices in New York Zone G, New York Zone A and Mass Hub decreased by 61 percent, 62 percent and 61 percent, respectively, resulting in compressed spreads. The decrease in New York Zone G prices led to a decrease in generated volumes at our Danskammer power generation facility.

These items were partly offset by increased volumes from our natural gas-fired facilities. Volumes produced by our natural gas-fired combined cycle fleet increased despite compressed market spark spreads as a result of reduced congestion and improved dispatch opportunities at our Independence power generation facility, as well as a reduction in transmission outages at our Casco Bay power generation facility.

Depreciation expense decreased from $14 million for the third quarter 2008 to $8 million for the third quarter 2009, primarily as a result of the impairment of our Roseton and Danskammer power generation facilities at June 30, 2009 and September 30, 2009.

Other. Dynegy’s and DHI’s other operating loss for the three months ended September 30, 2009 was $47 million, compared to an operating loss of $51 million for the three months ended September 30, 2008. Operating losses in both periods were comprised primarily of general and administrative expenses.

Consolidated general and administrative expenses were $42 million and $48 million for the three months ended September 30, 2009 and 2008, respectively. General and administrative expenses included legal and settlement charges of $7 million for the three months ended September 30, 2008.

Losses from Unconsolidated Investments

Dynegy’s and DHI’s losses from unconsolidated investments were $8 million for the three months ended September 30, 2009, related to the GEN-WE investment in Sandy Creek. The $8 million consisted of $5 million of mark-to-market losses primarily related to interest rate swap contracts and $3 million of financing costs. Losses from unconsolidated investments were $5 million for the three months ended September 30, 2008, related to the GEN-WE investment in the Sandy Creek Project. Please see Note 8—Variable Interest Entities—Sandy Creek for further discussion.

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Other Items, Net

Dynegy’s and DHI’s other items, net, totaled $2 million of income for the three months ended September 30, 2009, compared to $11 million of income for the three months ended September 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 $115 million for the three months ended September 30, 2009, compared to $105 million for the three months ended September 30, 2008. The increase was primarily attributable to $14 million of expense related to the change in value and settlement of interest rate swaps associated with our PPEA Credit Agreement Facility in 2009, partly offset by lower LIBOR rates on our variable-rate debt in 2009.

Income Tax Benefit (Expense)

Dynegy reported an income tax benefit from continuing operations of $34 million for the three months ended September 30, 2009, compared to an income tax expense from continuing operations of $392 million for the three months ended September 30, 2008. The 2009 effective tax rate was 27 percent, compared to 41 percent in 2008.

DHI reported an income tax benefit from continuing operations of $35 million for the three months ended September 30, 2009, compared to an income tax expense of $391 million from continuing operations for the three months ended September 30, 2008. The 2009 effective tax rate was 27 percent, compared to 41 percent in 2008.

As a result of the planned LS Power transaction, the 2009 income tax benefit was partly offset by the impact of disallowed losses associated with the planned transaction with LS Power. For the period ended September 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 (Loss) From Discontinued Operations Before Taxes

For the three months ended September 30, 2009, our pre-tax loss from discontinued operations was $213 million, related to our Arizona and Bluegrass power generation facilities. This loss included a pre-tax impairment charge of $235 million related to our Arizona power generation facilities, as these facilities met the criteria for classification as held for sale at August 9, 2009. For the three months ended September 30, 2008, our pre-tax income from discontinued operations was $54 million, related to the operations of the Calcasieu, Heard County, Bluegrass and Arizona power generation facilities.

Income Tax (Expense) Benefit From Discontinued Operations

Dynegy recorded an income tax benefit from discontinued operations of $84 million during the three months ended September 30, 2009, compared to an income tax expense of $22 million during the three months ended September 30, 2008. These amounts reflect effective rates of 39 percent and 41 percent, respectively. DHI recorded an income tax benefit from discontinued operations of $74 million during the three months ended September 30, 2009, compared to an income tax expense of $22 million during the three months ended September 30, 2008. These amounts reflect effective rates of 35 percent and 41 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.

Noncontrolling Interest

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We recorded $11 million of noncontrolling interest expense for the three months ended September 30, 2009, compared with $1 million of noncontrolling interest expense for the three months ended September 30, 2008 related to the Plum Point Project. The change in noncontrolling interest expense is primarily related to the mark-to-market losses related to the interest rate swap agreements associated with the Plum Point Credit Agreement Facility. Effective July 28, 2009, the interest rate swap agreements were no longer accounted for as cash flow hedges; therefore, the change in value is reflected in the unaudited condensed consolidated statement of operations and is no longer reflected in accumulated other comprehensive loss.

Nine Months Ended September 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 nine months ended September 30, 2009 and 2008, respectively:

Dynegy’s Results of Operations for the Nine Months Ended September 30, 2009

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

Revenues	$	1,085		$	293		$	652		$	(3	)	$	2,027
Cost of sales		(389	)		(121	)		(417	)		—			(927	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(165	)		(76	)		(135	)		3			(373	)
Depreciation and amortization expense		(165	)		(45	)		(39	)		(9	)		(258	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above		(147	)		—			(388	)		—			(535	)
General and administrative expense		—			—			—			(125	)		(125	)
Operating income (loss)	$	143		$	(209	)	$	(424	)	$	(134	)	$	(624	)
Earnings from unconsolidated investments		—			12			—			1			13
Other items, net		2			3			—			5			10
Interest expense														(311	)

Loss from continuing operations before income taxes														(912	)
Income tax benefit														147

Loss from continuing operations														(765	)
Loss from discontinued operations, net of taxes														(141	)
Net loss														(906	)

Less: Net loss attributable to the noncontrolling interests														(14	)

Net loss attributable to Dynegy Inc.													$	(892	)

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Dynegy’s Results of Operations for the Nine Months Ended September 30, 2008

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

Revenues	$	1,226		$	556		$	772		$	(4	)	$	2,550
Cost of sales		(455	)		(334	)		(547	)		10			(1,326	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(146	)		(72	)		(143	)		17			(344	)
Depreciation and amortization expense		(153	)		(57	)		(41	)		(7	)		(258	)
Gain on sale of assets, net		57			11			—			15			83
General and administrative expense		—			—			—			(126	)		(126	)
Operating income (loss)	$	529		$	104		$	41		$	(95	)	$	579
Losses from unconsolidated investments		—			(7	)		—			(10	)		(17	)
Other items, net		—			5			5			36			46
Interest expense														(322	)

Income from continuing operations before income taxes														286
Income tax expense														(121	)

Income from continuing operations														165
Income from discontinued operations, net of tax														13
Net income														178
Less: Net loss attributable to the noncontrolling interests														(3	)

Net income attributable to Dynegy Inc.													$	181

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The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the nine month periods ended September 30, 2009 and 2008, respectively:

DHI’s Results of Operations for the Nine Months Ended September 30, 2009

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

Revenues	$	1,085		$	293		$	652		$	(3	)	$	2,027
Cost of sales		(389	)		(121	)		(417	)		—			(927	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(165	)		(76	)		(135	)		1			(375	)
Depreciation and amortization expense		(165	)		(45	)		(39	)		(9	)		(258	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above		(147	)		—			(388	)		—			(535	)
General and administrative expense		—			—			—			(125	)		(125	)
Operating income (loss)	$	143		$	(209	)	$	(424	)	$	(136	)	$	(626	)
Earnings from unconsolidated investments		—			12			—			—			12
Other items, net		2			3			—			4			9
Interest expense														(311	)

Loss from continuing operations before income taxes														(916	)
Income tax benefit														152

Loss from continuing operations														(764	)
Loss from discontinued operations, net of taxes														(141	)

Net loss														(905	)
Less: Net loss attributable to the noncontrolling interests														(14	)

Net loss attributable to Dynegy Holdings Inc.													$	(891	)

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DHI’s Results of Operations for the Nine Months Ended September 30, 2008

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

Revenues	$	1,226		$	556		$	772		$	(4	)	$	2,550
Cost of sales		(455	)		(334	)		(547	)		10			(1,326	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(146	)		(72	)		(143	)		17			(344	)
Depreciation and amortization expense		(153	)		(57	)		(41	)		(7	)		(258	)
Gain on sale of assets		57			11			—			15			83
General and administrative expense		—			—			—			(126	)		(126	)
Operating income (loss)	$	529		$	104		$	41		$	(95	)	$	579
Losses from unconsolidated investments		—			(7	)		—			—			(7	)
Other items, net		—			5			5			35			45
Interest expense														(322	)

Income from continuing operations before income taxes														295
Income tax expense														(127	)

Income from continuing operations														168
Income from discontinued operations, net of tax														13
Net income														181
Less: Net loss attributable to the noncontrolling interests														(3	)

Net income attributable to Dynegy Holdings Inc.													$	184

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

	Nine Months Ended September 30,
	2009			2008
GEN-MW
Million Megawatt Hours Generated (1)		19.1			18.5
In Market Availability for Coal Fired Facilities (2)		89	%		89	%
Average Capacity Factor for Combined Cycle Facilities (3)		32	%		17	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Cinergy (Cin Hub)	$	35		$	73
Commonwealth Edison (NI Hub)	$	34		$	72
PJM West	$	45		$	91
Average Market Spark Spreads ($/MWh) (5):
PJM West	$	13		$	17

GEN-WE
Million Megawatt Hours Generated (6) (7)		4.7			6.5
Average Capacity Factor for Combined Cycle Facilities (3)		44	%		65	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
North Path 15 (NP 15)	$	36		$	88
Average Market Spark Spreads ($/MWh) (5):
North Path 15 (NP 15)	$	8		$	20

GEN-NE
Million Megawatt Hours Generated		7.8			5.7
In Market Availability for Coal Fired Facilities (2)		94	%		92	%
Average Capacity Factor for Combined Cycle Facilities (3)		44	%		25	%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
New York—Zone G	$	50		$	111
New York—Zone A	$	36		$	73
Mass Hub	$	45		$	100
Average Market Spark Spreads ($/MWh) (5):
New York—Zone A	$	5		$	2
Mass Hub	$	11		$	25
Fuel Oil	$	(45	)	$	(45	)

Average natural gas price—Henry Hub ($/MMBtu) (8)	$	3.80		$	9.67

_______

(1)

Excludes approximately 0.1 million MWh and less than 0.1 million MWh generated by our Bluegrass power generation facility, which is classified in discontinued operations, for the nine months ended September 30, 2009 and 2008, respectively.

(2)

Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.

(3)

Reflects actual production as a percentage of available capacity. Excludes Arlington Valley and Griffith power generation facilities which are reported as discontinued operations with respect to the GEN-WE segment.

(4)

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

(5)

(6)

Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the nine months ended September 30, 2009 and 2008, respectively.

(7)

Excludes less than 0.1 MWh generated by the Heard County power generation facility, which we sold in April 2009, for the nine months ended September, 30, 2009 and 2008, respectively. Excludes approximately 0.7 MWh and 0.8 MWh generated by our Arlington Valley power generation facility and 1.4 MWh and 1.6 MWh generated by our Griffith power generation facility, which are collectively classified in discontinued operations, for the nine months ended September 30, 2009 and 2008 respectively.

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(8)

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

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

	Nine Months Ended September 30, 2009
	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Impairments (1)	$	(246	)	$	(495	)	$	(485	)	$	—		$	(1,226	)
Sandy Creek mark-to-market gains (2)		—			20			—			—			20
Gain on sale of Heard County (3)		—			10			—			—			10
Taxes (4)		—			—			—			(22	)		(22	)

Total—DHI		(246	)		(465	)		(485	)		(22	)		(1,218	)
Taxes		—			—			—			(9	)		(9	)

Total—Dynegy	$	(246	)	$	(465	)	$	(485	)	$	(31	)	$	(1,227	)

____________

(1)

Includes $258 million of impairment charges related to our Arizona and Bluegrass power generation facilities which are included in discontinued operations.

(2)

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

(3)

Presented in discontinued operations.

(4)

Includes charges of $21 million for Dynegy and $15 million for DHI related to a change in a California state tax law. Also includes $10 million for Dynegy and $7 million for DHI due to revised assumptions around the ability to utilize certain state deferred tax assets.

	Nine Months Ended September 30, 2008
	Power Generation
	GEN-MW		GEN-WE		GEN-NE		Other		Total
	(in millions)
Gain on sale of Rolling Hills	$	57	$	—	$	—	$	—	$	57
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	$	57	$	24	$	—	$	31	$	112

Operating Income (Loss)

Operating loss for Dynegy was $624 million for the nine months ended September 30, 2009, compared to operating income of $579 million for the nine months ended September 30, 2008. Operating loss for DHI was $626 million for the nine months ended September 30, 2009, compared to operating income of $579 million for the nine months ended September 30, 2008.

Our operating loss for the nine months ended September 30, 2009 was driven, in large part, by a $433 million impairment of goodwill and by $535 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.

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Mark-to-market losses on forward sales of power associated with our generating assets are included in Revenues in the unaudited condensed consolidated statements of operations. Such losses, which totaled $64 million for the nine months ended September 30, 2009, were a result of the expiration of certain risk management positions during the first nine months of 2009. These losses compared to $122 million of mark-to-market gains for the nine months ended September 30, 2008, when forward market power prices decreased 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 nine months ended September 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 income for GEN-MW was $143 million for the nine months ended September 30, 2009, compared to income of $529 million for the nine months ended September 30, 2008. Such amounts do not include results from our Bluegrass power generating facility, which has been reclassified as a discontinued operation for all periods presented.

Revenues for the nine months ended September 30, 2009 decreased by $141 million compared to the nine months ended September 30, 2008, cost of sales decreased by $66 million and operating and maintenance expense increased by $19 million, resulting in a net decrease of $94 million. The decrease was primarily driven by the following:

Mark-to-market losses – GEN-MW’s results for the nine months ended September 30, 2009 included mark-to-market losses of $4 million related to forward sales, compared to $89 million of mark-to-market gains for the nine months ended September 30, 2008. Of the $4 million in 2009 mark-to-market losses, $53 million of losses related to positions that settled or will settle in 2009, partly offset by $49 million of gains related to positions that will settle in 2010 and beyond;

Decreased toll revenues - Tolling and capacity revenues decreased by $12 million as a result of expiring contracts at our Kendall and Rocky Road power generation facilities;

Increased operating expense – operating expense increased from $146 million for the nine months ended September 30, 2008 to $165 million for the nine months ended September 30, 2009, primarily as a result of planned outages at our coal-fired power generating facilities; and

Lower revenues of $13 million from sales of emissions credits.

These items were partly offset by the following:

A $50 million payment received to assign our rights to a third party pursuant to a power sales agreement. This contract would have been in effect through 2011;

Increased volumes – Generated volumes increased by 3 percent, from 18.5 million MWh for the nine months ended September 30, 2008, to 19.1 million MWh for the nine months ended September 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;

Additional capacity sales of approximately $37 million, as a result of improved capacity prices for 2009 compared with 2008; and

Benefit of hedging activity – The average actual on-peak prices in the Cin Hub pricing region decreased from $73 per MWh for the nine months ended September 30, 2008 to $35 per MWh for the nine months ended September 30, 2009. However, the impact of lower market prices was mitigated by economic hedging, resulting in higher realized prices that were higher in the nine months ended September 30, 2009 than in the nine months ended September 30, 2008;

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Depreciation expense increased from $153 million for the nine months ended September 30, 2008 to $165 million for the nine months ended September 30, 2009, primarily as a result of projects associated with the Midwest Consent Decree being placed into service.

Operating income for the nine months ended September 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, during 2009, we recorded a $147 million impairment of our Renaissance, Riverside/Foothills, Rocky Road and Tilton power generating facilities 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.

Operating income for the nine months ended September 30, 2008 included a $57 million gain from the sale of our Rolling Hills power generation facility, reflected in Gain on sale of assets in our unaudited condensed consolidated statements of operations.

Power Generation—West Segment. Operating loss for GEN-WE was $209 million for nine months ended September 30, 2009, compared to operating income of $104 million for the nine months ended September 30, 2008. Such amounts do not include results from our Arizona and Heard County power generating facilities, which have been classified as discontinued operations for all periods presented.

Revenues for the nine months ended September 30, 2009 decreased by $263 million compared to the nine months ended September 30, 2008, cost of sales decreased by $213 million and operating and maintenance expense increased by $4 million, resulting in a net decrease of $54 million. The decrease was primarily driven by the following:

Mark-to-market losses – GEN-WE’s results for the nine months ended September 30, 2009 included mark to-market losses of $52 million, compared to $42 million of mark-to-market gains for the nine months ended September 30, 2008. Of the $52 million in 2009 mark-to-market losses, $18 million related to positions that settled or will settle in 2009, and the remaining $34 million related to positions that will settle in 2010 and beyond; and

Decreased volumes – Generated volumes were 4.7 million MWh for the nine months ended September 30, 2009, down from 6.5 million MWh for the nine months ended September 30, 2008. The volume decrease was driven in large part by decreased market spark spreads and reduced dispatch opportunities.

These decreases were partly offset by increased tolling and capacity revenues of $40 million.

Depreciation expense decreased from $57 million for the nine months ended September 30, 2008 to $45 million for the nine months ended September 30, 2009, largely as a result of an increase in the estimated useful life of one of our generation facilities.

Operating loss for the nine months ended September 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.

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.

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Power Generation—Northeast Segment. Operating loss for GEN-NE was $424 million for the nine months ended September 30, 2009, compared to operating income of $41 million for the nine months ended September 30, 2008.

Revenues for the nine months ended September 30, 2009 decreased by $120 million compared to the nine months ended September 30, 2008, cost of sales decreased by $130 million and operating and maintenance expense decreased by $8 million, resulting in a net increase of $18 million. The increase was primarily driven by the following:

Additional capacity sales of $9 million;

Increased sales of emission credits of $8 million;

Increased volumes – Volumes produced by our natural gas-fired combined cycle fleet increased as a result of reduced congestion and improved dispatch opportunities at our Independence facility, as well as a reduction in transmission outages at our Casco Bay facility;

Reduced mark-to-market losses – GEN-NE’s results for the nine months ended September 30, 2009 included mark-to-market losses of $8 million related to forward sales, compared to losses of $9 million for the nine months ended September 30, 2008. Of the $8 million in 2009 mark-to-market losses, $7 million in gains related to positions that settled or will settle in 2009, offset by $15 million of losses related to positions that will settle in 2010 and beyond; and

Reduced operating expense of $8 million, largely as a result of a reduction in property taxes.

These items were partly offset by the following:

A coal inventory write-down of approximately $11 million recorded during the nine months ended September 30, 2009; and

Lower market prices – on-peak market prices in New York Zone G and Mass Hub decreased by 55 percent in each of these regions.

Depreciation expense decreased from $41 million for the nine months ended September 30, 2008 to $39 million for the nine months ended September 30, 2009.

Operating loss for the nine months ended September 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.

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 $209 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 nine months ended September 30, 2009 was $134 million, compared to an operating loss of $95 million for the nine months ended September 30, 2008. DHI’s other operating loss for the nine months ended September 30, 2009 was $136 million, compared to an operating loss of $95 million for the nine months ended September 30, 2008. Operating losses in both periods were comprised primarily of general and administrative expenses.

Cost of sales for the nine months ended September 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 nine months ended September 30, 2008 included a benefit from the release of $16 million of sales and use tax liability, as well as a $9 million benefit from the release of a liability associated with an assignment of a natural gas transportation contract.

Gain on sale of assets for the nine months ended September 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.

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Consolidated general and administrative expenses decreased from $126 million from the nine months ended September 30, 2008 to $125 million for the nine months ended September 30, 2009.

Earnings (Losses) from Unconsolidated Investments

Dynegy’s earnings from unconsolidated investments were $13 million for the nine months ended September 30, 2009 of which $12 million related to the GEN-WE investment in Sandy Creek. The $12 million consisted of $20 million mark-to-market gains primarily related to interest rate swap contracts offset by $8 million of financing costs. The remaining $1 million of earnings relates to Dynegy’s former investment in DLS Power Development, included in Other. Losses from unconsolidated investments were $17 million for the nine months ended September 30, 2008. GEN-WE recognized $7 million of losses related to its investment in the Sandy Creek Project. These losses were comprised of $20 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 Dynegy’s investment in DLS Power Development, included in Other.

DHI’s earnings from unconsolidated investments of $12 million for the nine months ended September 30, 2009 related to the GEN-WE investment in Sandy Creek. The $12 million consisted of $20 million mark-to-market gains primarily related to interest rate swap contracts offset by $8 million of financing costs. Losses from unconsolidated investments for the nine months ended September 30, 2008 were $7 million. GEN-WE recognized $7 million of losses related to its investment in the Sandy Creek Project. These losses were comprised of $20 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 $10 million and $9 million, respectively, of income for the nine months ended September 30, 2009, compared to $46 million and $45 million, respectively, of income for the nine months ended September 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 $311 million for the nine months ended September 30, 2009, compared to $322 million for the nine months ended September 30, 2008. The decrease was primarily attributable to lower LIBOR rates on our variable-rate debt in 2009, partly offset by $14 million of expense related to the change in value and settlement of interest rate swaps associated with our PPEA Credit Agreement Facility in 2009.

Income Tax Benefit (Expense)

Dynegy reported an income tax benefit from continuing operations of $147 million for the nine months ended September 30, 2009, compared to an income tax expense from continuing operations of $121 million for the nine months ended September 30, 2008. The 2009 effective tax rate was 16 percent, compared to 42 percent in 2008.

DHI reported an income tax benefit from continuing operations of $152 million for the nine months ended September 30, 2009, compared to an income tax expense of $127 million from continuing operations for the nine months ended September 30, 2008. The 2009 effective tax rate was 17 percent, compared to 43 percent in 2008.

The primary difference between the effective rates of 16 and 17 percent for Dynegy and DHI, respectively, for the nine months ended September 30, 2009 and the statutory rate of 35 percent resulted from the effect of the nondeductible goodwill impairment charge. Additionally, for the nine months ended September 30, 2009, Dynegy and DHI recorded $19 million and $14 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 nine months ended September 30, 2009. The third quarter provision also considered the impact of disallowed losses in connection with the planned transaction with LS Power. For the period ended September 30, 2008, the difference between the effective rates of 42 and 43 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.

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Discontinued Operations

Income (Loss) From Discontinued Operations Before Taxes

For the nine months ended September 30, 2009, our pre-tax loss from discontinued operations was $232 million, related to the operation of our Arlington Valley, Griffith, Bluegrass and Heard County facilities. We recorded impairment charges of $235 million related to our Arlington Valley and Griffith Facilities, as these facilities collectively met the criteria for classification as held for sale at August 9, 2009. Additionally, we recorded impairment charges of $23 million related to our Bluegrass facility. For the nine months ended September 30, 2008, our pre-tax income from discontinued operations was $23 million, related to the operation of the Calcasieu, Heard County, Bluegrass, Arlington Valley and Griffith power generation facilities.

Income Tax (Expense) Benefit From Discontinued Operations

We recorded an income tax benefit from discontinued operations of $91 million during the nine months ended September 30, 2009, compared to an income tax expense of $10 million during the nine months ended September 30, 2008. These amounts reflect effective rates of 39 percent and 43 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.

Noncontrolling Interest

We recorded $14 million of noncontrolling interest expense for the nine months ended September 30, 2009, compared with $3 million of noncontrolling interest expense for the nine months ended September 30, 2008 related to the Plum Point Project. The change in noncontrolling interest expense is primarily related to the mark-to-market losses related to the interest rate swap agreements associated with the Plum Point Credit Agreement Facility. Effective July 28, 2009, the interest rate swap agreements were no longer accounted for as a cash flow hedges; therefore, the change in value is reflected in the unaudited condensed consolidated statement of operations and is no longer reflected in accumulated other comprehensive loss.

Outlook

On August 9, 2009, we entered into a purchase and sale agreement with LS Power in which we agreed to sell our ownership interests in 4,788 MW of peaking and combined-cycle power generation assets, as well as our remaining interests in the Sandy Creek Project under construction in Texas, and to issue $235 million principal amount of DHI 7.50 percent senior unsecured notes due 2015. Upon closing of the transaction, which is expected in the fourth quarter 2009 assuming all necessary closing conditions are satisfied or waived, we will receive from LS Power approximately $1.025 billion in cash (consisting, in part, of the release of $175 million of restricted cash that was used to support our funding commitment to Sandy Creek and approximately $200 million for the unsecured notes), subject to working capital adjustments, and 245 million of Dynegy’s Class B shares.

Upon closing of the transaction, the remaining 95 million shares of Dynegy’s Class B common stock held by LS Power will be converted into the same 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 ownership for a specified period and eliminates special approval, board representation and certain other rights associated with the Class B common shares. Please see Note 2—Dispositions and Discontinued Operations—Dispositions—LS Power Transaction for further information.

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Assuming the LS Power transaction is consummated, our power generation capacity will consist of almost 13,000 MW of generating capacity and will continue to be diversified by fuel source (i.e., coal, natural gas and fuel oil) and dispatch type (i.e., baseload, intermediate and peaking facilities). Approximately 34 percent of our power generation fleet will be natural gas-fired, combined-cycle capacity, 31 percent will be baseload coal-fired capacity, 25 percent will be natural gas-fired peaking capacity, and the remaining 10 percent will be dual-fuel capable. We believe that our fuel and dispatch type diversity positions us to capture market opportunities that may not be available to less diverse generators.

Our power generation capacity also will be diversified by geographic location across seven U.S. states, as approximately 43 percent of our generating capacity will be located in the Midwest, 25 percent will be located in the Northeast, and 32 percent will be located in the West. We believe that this geographic diversity will continue to position us to benefit from the portfolio effect of different supply/demand characteristics across broad geographic regions, including in the Northeast and California where new supply options may be limited.

These different supply/demand characteristics can occur over the short-term (e.g., based on weather patterns or the unavailability of other suppliers) or over the long-term (e.g., based on long-term demand growth that exceeds supply additions).

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, 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.

Beginning in 2009, we set specific limits for “gross margin at risk” for the entire portfolio and require power hedging up to minimum levels, while seeking to ensure that corresponding fuel supplies also are appropriately hedged, as we progress through time. We will also attempt to specifically manage basis risk to hubs that are not the natural sales hub for a facility and implement other changes that sharpen our focus on optimizing the commercial factors that we can control and mitigating commodity risk where appropriate and possible.

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.

We have volumetrically hedged substantially all of our expected generation volumes through 2010 and approximately 50 percent of such expected generation volumes for 2011. 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. We may do this by buying back positions and selling at more attractive prices in an attempt to capture margin opportunities or mitigate downside risk associated with changes in commodity prices. However, our future operating cash flows may vary based on a number of factors, including the value of capacity and ancillary services, the operational performance of our generating facilities, and legal, environmental and regulatory requirements.

To the extent that we choose not to enter into forward transactions, the gross margin from our assets is highly sensitive to 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.

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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 2013, to be approximately $960 million, which includes approximately $490 million spent to date. This estimate includes a number of assumptions about 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.

Our Midwest coal and transportation requirements are 100 percent contracted and priced through 2010. For 2011 and 2012, approximately 35 percent of our coal requirements are contracted, and the price for these volumes will be determined in 2010 under the terms of the coal purchase contract.

More wind generation has come online in the Midwest, resulting in lower off-peak prices and an increase in minimum generation events. During these events, baseload generation may be directed to shut down or run at minimum loads. As additional wind generation enters the grid, these events will occur more frequently. We seek to mitigate the price impacts of these minimum generation events through hedging. However, continued cycling of coal-fired units over time could reduce our in-market availability as these events could lead to an increase in overall maintenance costs and plant outages.

GEN-WE. Approximately seventy percent of Dynegy’s power plant capacity in the West is contracted through 2010 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 and Oakland power generation facilities are operating under RMR agreements with the Cal ISO through December 31, 2009. For 2010, the Cal ISO has designated Oakland and three of the five units at South Bay as RMR facilities. The RMR designation by the Cal ISO for the South Bay facility is subject to being terminated early if the Cal ISO determines other San Diego-area generation projects or transmission upgrades are completed successfully.

GEN-NE. The northeast portfolio includes several generating units with dual fuel capability. We have fully contracted our 2009 coal supply and freight requirements and have secured approximately 80 percent of our 2010 expected supply needs for our Danskammer power generation facility.

While we have sourced most of our coal from South America, we have access to and are exploring multiple options for the balance 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 short-term market value through strategic purchases of fuel oil and sales of power in the spot or forward markets.

The ISO-NE is in the process of restructuring its capacity market and will be transitioning from a fixed payment structure to implementation of a forward capacity market structure in 2010. The transitional payments for capacity commenced in December 2006, with a price of $3.05 KW/month, and have risen gradually to $4.10 KW/month through May 31, 2010. The delivery of capacity under the forward capacity market will be fully effective on June 1, 2010. Capacity auctions for the 2010/2011, 2011/2012 and 2012/2013 market periods were held in 2008 and 2009 and resulted in capacity payments of $4.50 KW/month, $3.60 KW/month and $2.95 KW/month respectively for our asset in ISO-NE. Discussions to address identified flaws with the forward capacity market design are currently underway by the ISO and its stakeholders.

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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.

Federal Legislation Regarding Greenhouse Gases. Several bills have been introduced in Congress since 2003 that would compel reductions in CO2 emissions from power plants, but only recently has any proposed bill received majority support in the House of Representatives or Senate. On June 26, 2009 the House of Representatives passed the American Clean Energy and Security Act of 2009 (“H.R. 2454”). Title III of H.R. 2454 would add a new Title VII to the CAA creating a Global Warming Pollution Reduction Program. H.R. 2454 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.

On September 30, 2009, the Senate Environment and Public Works Committee introduced the Clean Energy Jobs and American Power Act (“S. 1733”), a bill similar to H.R. 2454. The targets for GHG emission reductions in S. 1733 are 3 percent below 2005 levels by 2012, 20 percent below 2005 levels by 2020, 42 percent below 2005 levels by 2030 and 83 percent below 2005 levels by 2050.

The House and Senate bills represent a comprehensive effort to restructure the energy market in the United States. We cannot confidently predict the content of federal legislation that ultimately may be enacted to control GHG emissions. However, depending on various factors that are outside our control, including the specific provisions of any approved legislation and our ability to recover any additional costs through market pricing, the significant mandatory reductions of CO2 emissions from the electric generating sector contemplated by these bills could have a material adverse effect on our financial condition, results of operations and cash flows.

Federal Regulation of Greenhouse Gases. Several federal regulatory initiatives and actions under the CAA are being developed or implemented that address GHG emissions. 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 for mobile sources.

On June 30, 2009, the Administrator of the 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, they may become subject to other sections of the CAA including the best available control technology requirements under the prevention of significant deterioration provisions.

On September 15, 2009, the U.S. EPA and the U.S. Department of Transportation released a proposed joint rule that would regulate GHG emissions from passenger cars and light trucks. If the rule becomes final, it may render GHGs, including CO2, “subject to regulation” under the Act.

On September 22, 2009, the U.S. EPA released its final rule requiring mandatory reporting of GHG emissions from all sectors of the economy. The rule will require that sources above certain threshold levels monitor and report GHG emissions. Our power generating facilities will be subject to these new reporting requirements; we are currently reviewing our systems and procedures for measuring and inventorying the subject emissions to prepare to meet these new requirements.

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On September 30, 2009, the U.S. EPA proposed to “phase in” new GHG emission applicability thresholds for its PSD permit program and for the operating permit program under Title V of the CAA. The proposed rule would establish a temporary GHG applicability threshold for these programs at 25,000 tons per year of CO2 equivalent (CO2e: an expression of the global warming potential of the various GHGs relative to the global warming potential of CO2) for new sources, and a temporary GHG significance level under the PSD Permit Program between 10,000 and 25,000 tons per year CO2e for modifications to major sources. According to the agency, this rule is being proposed on the basis of the legal doctrines of “absurd results” and “administrative necessity” in anticipation of GHG becoming subject to regulation under the CAA and to avoid subjecting small sources to individualized PSD permit and control technology requirements that would otherwise be required by the thresholds set forth in the CAA. Our power generation facilities’ GHG emissions would become subject to these programs when GHG emissions become subject to regulation regardless of the U.S. EPA’s proposal to amend the statutory thresholds in this rulemaking. Public debate is ongoing as to the U.S. EPA’s legal authority to adopt this rule, making legal challenges likely. We cannot predict with certainty the outcome of this rulemaking process or a specific impact on our generating portfolio.

State Regulation of Greenhouse Gases. 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 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, 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.

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.

In late June 2009, the California State Water Resources Control Board issued draft regulations for power plants with once-through cooling. Our options include closed system cooling structures and other measures for reducing impingement/entrainment. Our low heat rate plants, Moss Landing units 1 and 2, would have until 2017 to develop solutions. Some of our older, less efficient units may not be profitable if the rule becomes final, and therefore may be considered for retirement. As an active stakeholder in the process, we are continuing to monitor the development of draft regulations, and will continue to provide input as solutions move from their current draft status to final regulations.

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. While allowances are sold by year, actual compliance is measured across a three year control period. The first control period is for the 2009-2011 timeframe.

On September 9, 2009, RGGI held its fifth auction, in which approximately 28 million of allowances for allocation year 2009, and over two million allowances for allocation year 2012, were sold at clearing prices of $2.19 per allowance and $1.87 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. One additional auction is scheduled for 2009 with auctions expected to be held quarterly throughout 2010.

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We project that 2009 CO2 emissions from our generating facilities in New York and Maine will be approximately 4.6 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 is approximately $15 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. 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. In September 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. 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.

RISK-MANAGEMENT DISCLOSURES

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

	As of and for the Nine Months Ended September 30, 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		297
Cash received related to risk-management contracts settled in the period, net		(359	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		176

Fair value of portfolio at September 30, 2009 (3)	$	84

__________________

(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.

(3)

Includes $9 million of risk management assets classified as held for sale as of September 30, 2009.

The net risk management asset of $84 million is the aggregate of the following line items on our unaudited condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Current Assets—Assets held for sale, Current Liabilities—Liabilities from risk-management activities, Current Liabilities—Liabilities associated with assets held for sale and Other Liabilities—Liabilities from risk-management activities.

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Risk-Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of September 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)	$	114		$	80	$	55	$	(21	)	$	—		$	—		$	—
Prices based on models		(30	)		12		19		(30	)		(4	)		(3	)		(24	)

Total (2)	$	84		$	92	$	74	$	(51	)	$	(4	)	$	(3	)	$	(24	)

__________________

(1)

Prices obtained from actively traded, liquid markets for commodities.

(2)

The market quotations and prices based on models categorization differs from the fair value accounting standards’ 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 benefits to be derived from the transaction with LS Power, expected use of any proceeds from the transaction and any impairments and charges related to such transaction;

beliefs and expectations regarding the closing of the LS power transaction and the timing, terms and success thereof;

the timing and anticipated benefits to be achieved through our 2010-2013 company-wide cost savings program;

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 regulations or changes to current regulations, including those relating to climate change;

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

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

the effectiveness of our 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;

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

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

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

beliefs associated with Dynegy’s market capitalization;

beliefs and expectations regarding financing and associated credit ratings, development and timing of the Plum Point Project;

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

the impact of executing, or failing to execute, any acquisition, disposition or combination transactions.

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.

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 September 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 “normal purchase normal sale”, nor does it include expected future production from our generating assets. The increase in the September 30, 2009 VaR was primarily due to increased forward commodity transactions as compared to December 31, 2008. Please read “Value at Risk” in our Form 10-K for a complete description of our valuation methodology.

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Daily and Average VaR for Risk-Management Portfolios

	September 30, 2009		December 31, 2008
	(in millions)
One day VaR—95 percent confidence level	$	41	$	21
One day VaR—99 percent confidence level	$	58	$	29
Average VaR for the year-to-date period—95 percent confidence level	$	32	$	42

Credit Risk. The following table represents our credit exposure at September 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	$	76	$	—	$	76
Utility and power generators		14		5		19
Commercial, industrial and end users		—		5		5
Other		1		2		3

Total	$	91	$	12	$	103

Of the $12 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 September 30, 2009, our fixed rate debt instruments, as a percentage of total debt instruments, were approximately 73 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 September 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 September 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 September 30, 2009 and December 31, 2008, respectively:

Absolute Notional Contract Amounts

	September 30, 2009		December 31, 2008
Cash flow hedge interest rate swaps (in millions of U.S. dollars)	$	—	$	471
Fixed interest rate paid on swaps (percent)		—		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)	$	763	$	231
Fixed interest rate paid on swaps (percent)		5.33		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

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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 September 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 September 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
July 1-31		—	$	—		—		N/A
August 1-31		77	$	1.83		—		N/A
September 1-30		—	$	—		—		N/A

Total		77	$	1.83		—		N/A

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

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		Purchase and Sale Agreement, dated August 9, 2009 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 13, 2009, File No. 001-33443).
10.1		Amendment No. 4 to the Fifth Amended and Restated Credit Agreement dated as of April 2, 2007 (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. 001-33443).
10.2		Shareholder Agreement between Dynegy Inc. and LS Power and its affiliates, dated August 9, 2009 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 13, 2009, File No. 001-33443).

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Exhibit Number		Description
10.3		Amendment No. 1 to the Registration Rights Agreement dated September 14, 2006 by and between Dynegy Inc. and LS Power and affiliates, dated August 9, 2009 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on August 13, 2009, File No. 001-33443).
10.4		Note Purchase Agreement by and between Dynegy Holdings Inc. and Adio Bond, LLC, dated August 9, 2009 (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on August 13, 2009, File No. 001-33443).
**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.1(a)		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.2		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.2(a)		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
†32.1		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.1(a)		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.2(a)		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Filed herewith.

†

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

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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: November 5, 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: November 5, 2009	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)