Edgar Filing: DYNEGY HOLDINGS INC

form10q.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 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 x No ¨
Dynegy Holdings Inc.	Yes x 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.	x	¨	¨	¨
Dynegy Holdings Inc.	¨	¨	x	¨

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 x
Dynegy Holdings Inc.	Yes ¨ No x

Indicate the number of shares outstanding of Dynegy Inc.’s classes of common stock, as of the latest practicable date: Class A common stock, $0.01 par value per share, 504,225,664 shares outstanding as of May 1, 2009; Class B common stock, $0.01 par value per share, 340,000,000 shares outstanding as of May 1, 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.:
	March 31, 2009 and December 31, 2008		4
	Condensed Consolidated Statements of Operations—Dynegy Inc.:
	For the three months ended March 31, 2009 and 2008		5
	Condensed Consolidated Statements of Cash Flows—Dynegy Inc.:
	For the three months ended March 31, 2009 and 2008		6
	Condensed Consolidated Statements of Comprehensive Loss—Dynegy Inc.:
	For the three months ended March 31, 2009 and 2008		7
	Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.:
	March 31, 2009 and December 31, 2008		8
	Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.:
	For the three months ended March 31, 2009 and 2008		9
	Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.:
	For the three months ended March 31, 2009 and 2008		10
	Condensed Consolidated Statements of Comprehensive Loss—Dynegy Holdings Inc.:
	For the three months ended March 31, 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.	38
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—DYNEGY INC. AND DYNEGY HOLDINGS INC.	59
Item 4.	CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.	61

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	62
Item 1A.	RISK FACTORS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	62
Item 2.	UNREGISTERED SALES OF SECURITIES AND USE OF PROCEEDS—DYNEGY INC.	62
Item 6.	EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.	62

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 three-month period ended March 31, 2009 and constituting nearly 100 percent of Dynegy’s total consolidated asset base as of March 31, 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.

APB	Accounting Principles Board
BTA	Best technology available
Cal ISO	The California Independent System Operator
CARB	California Air Resources Board
CDWR	California Department of Water Resources
CEC	California Energy Commission
CFTC	Commodity Futures Trading Commission
CO2	Carbon Dioxide
CRM	Our former customer risk management business segment
CUSA	Chevron U.S.A. Inc., a wholly owned subsidiary of Chevron Corporation
DHI	Dynegy Holdings Inc., Dynegy’s primary financing subsidiary
DMG	Dynegy Midwest Generation, Inc.
DMSLP	Dynegy Midstream Services L.P.
EITF	Emerging Issues Task Force
EPA	Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN	FASB Interpretation
FSP	FASB Staff Position
GAAP	Generally Accepted Accounting Principles of the United States of America
GEN	Our power generation business
GEN-MW	Our power generation business - Midwest segment
GEN-NE	Our power generation business - Northeast segment
GEN-WE	Our power generation business - West segment
GHG	Greenhouse Gas
ICC	Illinois Commerce Commission
IMA	In-market asset availability
ISO	Independent System Operator
LNG	Liquefied natural gas
MISO	Midwest Independent Transmission Operator, Inc.
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt hour
NPDES	National Pollutant Discharge Elimination System
NRG	NRG Energy, Inc.
NYSDEC	New York State Department of Environmental Conservation
PJM	PJM Interconnection, LLC
PPEA	Plum Point Energy Associates, LLC
PUHCA	Public Utility Holding Company Act of 1935, as amended
RGGI	Regional Greenhouse Gas Initiative
RSG	Revenue Sufficiency Guarantee
SCEA	Sandy Creek Energy Associates, LP
SCH	Sandy Creek Holdings LLC
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
SPDES	State Pollutant Discharge Elimination System
VaR	Value at Risk
VIE	Variable Interest Entity

Table of Contents

PART I. FINANCIAL INFORMATION

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

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

	March 31, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	722		$	693
Restricted cash and investments		118			87
Short-term investments		8			25
Accounts receivable, net of allowance for doubtful accounts of $22 and $22, respectively		232			340
Accounts receivable, affiliates		1			1
Inventory		185			184
Assets from risk-management activities		1,531			1,263
Deferred income taxes		—			6
Prepayments and other current assets		243			204
Assets held for sale		96			—
Total Current Assets		3,136			2,803
Property, Plant and Equipment		10,801			10,869
Accumulated depreciation		(1,947	)		(1,935	)
Property, Plant and Equipment, Net		8,854			8,934
Other Assets
Unconsolidated investments		—			15
Restricted cash and investments		1,159			1,158
Assets from risk-management activities		214			114
Goodwill		—			433
Intangible assets		438			437
Accounts receivable, affiliates		6			4
Other long-term assets		324			315
Total Assets	$	14,131		$	14,213

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	158		$	303
Accrued interest		125			56
Accrued liabilities and other current liabilities		199			160
Liabilities from risk-management activities		1,250			1,119
Notes payable and current portion of long-term debt		64			64
Deferred income taxes		8			—
Liabilities held for sale		11			—
Total Current Liabilities		1,815			1,702
Long-term debt		5,898			5,872
Long-term debt, affiliates		200			200
Long-Term Debt		6,098			6,072
Other Liabilities
Liabilities from risk-management activities		314			288
Deferred income taxes		1,236			1,166
Other long-term liabilities		488			500
Total Liabilities		9,951			9,728
Commitments and Contingencies (Note 12)
Stockholders’ Equity
Class A Common Stock, $0.01 par value, 2,100,000,000 shares authorized at March 31, 2009 and December 31, 2008; 506,745,083 and 505,821,277 shares issued and outstanding at March 31, 2009 and December 31, 2008, respectively		5			5
Class B Common Stock, $0.01 par value, 850,000,000 shares authorized at March 31, 2009 and December 31, 2008; 340,000,000 shares issued and outstanding at March 31, 2009 and December 31, 2008		3			3
Additional paid-in capital		6,486			6,485
Subscriptions receivable		(2	)		(2	)
Accumulated other comprehensive loss, net of tax		(212	)		(215	)
Accumulated deficit		(2,025	)		(1,690	)
Treasury stock, at cost, 2,679,210 and 2,568,286 shares at March 31, 2009 and December 31, 2008, respectively		(71	)		(71	)
Total Dynegy Inc. Stockholders’ Equity		4,184			4,515
Noncontrolling interest		(4	)		(30	)
Total Stockholders’ Equity		4,180			4,485
Total Liabilities and Stockholders’ Equity	$	14,131		$	14,213

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

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

	Three Months Ended March 31,
	2009			2008
Revenues	$	904		$	543
Cost of sales		(381	)		(451	)
Operating and maintenance expense, exclusive of depreciation and amortization shown separately below		(122	)		(111	)
Depreciation and amortization expense		(92	)		(92	)
Goodwill impairments		(433	)		—
Impairment and other charges, exclusive of goodwill impairments shown separately above		(5	)		—
General and administrative expenses		(38	)		(39	)

Operating loss		(167	)		(150	)
Earnings (losses) from unconsolidated investments		8			(9	)
Interest expense		(98	)		(109	)
Other income and expense, net		4			20

Loss from continuing operations before income taxes		(253	)		(248	)
Income tax (expense) benefit (Note 14)		(85	)		96

Loss from continuing operations		(338	)		(152	)
Income from discontinued operations, net of tax benefit of zero and $1, respectively (Notes 2 and 14)		1			—

Net loss		(337	)		(152	)
Less: Net loss attributable to the noncontrolling interest		(2	)		—

Net loss attributable to Dynegy Inc.	$	(335	)	$	(152	)

Loss Per Share (Note 11):
Basic loss per share:
Loss from continuing operations attributable to Dynegy Inc.	$	(0.40	)	$	(0.18	)
Income from discontinued operations attributable to Dynegy Inc.		—			—

Basic loss per share attributable to Dynegy Inc.	$	(0.40	)	$	(0.18	)

Diluted loss per share:
Loss from continuing operations attributable to Dynegy Inc.	$	(0.40	)	$	(0.18	)
Income from discontinued operations attributable to Dynegy Inc.		—			—

Diluted loss per share attributable to Dynegy Inc.	$	(0.40	)	$	(0.18	)

Basic shares outstanding		841			839
Diluted shares outstanding		843			841

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Three Months Ended March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(337	)	$	(152	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization		94			94
Goodwill impairments		433			—
Impairment and other charges		5			—
(Earnings) losses from unconsolidated investments, net of cash distributions		(8	)		9
Risk-management activities		(168	)		280
Deferred income taxes		79			(95	)
Other		16			—
Changes in working capital:
Accounts receivable		56			36
Inventory		(6	)		14
Prepayments and other assets		(38	)		(55	)
Accounts payable and accrued liabilities		42			18
Changes in non-current assets		(7	)		(7	)
Changes in non-current liabilities		4			4

Net cash provided by operating activities		165			146

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(138	)		(131	)
Unconsolidated investments		1			(6	)
Proceeds from asset sales, net		—			57
Decrease in short-term investments		8			—
Increase in restricted cash		(32	)		(25	)
Other investing		—			10

Net cash used in investing activities		(161	)		(95	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		25			51
Other financing, net		—			(1	)

Net cash provided by financing activities		25			50

Net increase in cash and cash equivalents		29			101
Cash and cash equivalents, beginning of period		693			328

Cash and cash equivalents, end of period	$	722		$	429

Other non-cash investing activity:
Non-cash capital expenditures	$	23		$	9

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)

	Three Months Ended March 31,
	2009			2008

Net loss	$	(337	)	$	(152	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		34			(26	)
Reclassification of mark-to-market losses to earnings, net		—			8
Deferred losses on cash flow hedges, net		(3	)		—

Changes in cash flow hedging activities, net (net of tax (expense) benefit of $(9) and $5, respectively)		31			(18	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $2 and zero)		(1	)		—
Net unrealized loss on securities, net (net of tax benefit of zero and $3, respectively)		—			(4	)
Unconsolidated investments other comprehensive loss, net (net of tax expense of $1 and zero)		1			—

Other comprehensive income (loss), net of tax		31			(22	)

Comprehensive loss		(306	)		(174	)
Less: Comprehensive income (loss) attributable to the noncontrolling interest		26			(11	)

Comprehensive loss attributable to Dynegy Inc.	$	(332	)	$	(163	)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)

	March 31, 2009			December 31, 2008
ASSETS
Current Assets
Cash and cash equivalents	$	539		$	670
Restricted cash and investments		118			87
Short-term investments		8			24
Accounts receivable, net of allowance for doubtful accounts of $20 and $20, respectively		234			343
Accounts receivable, affiliates		1			1
Inventory		185			184
Assets from risk-management activities		1,531			1,263
Deferred income taxes		—			4
Prepayments and other current assets		243			204
Assets held for sale		96			—
Total Current Assets		2,955			2,780
Property, Plant and Equipment		10,801			10,869
Accumulated depreciation		(1,947	)		(1,935	)
Property, Plant and Equipment, Net		8,854			8,934
Other Assets
Restricted cash and investments		1,159			1,158
Assets from risk-management activities		214			114
Goodwill		—			433
Intangible assets		438			437
Accounts receivable, affiliates		6			4
Other long-term assets		323			314
Total Assets	$	13,949		$	14,174

LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	158		$	284
Accrued interest		125			56
Accrued liabilities and other current liabilities		193			157
Liabilities from risk-management activities		1,250			1,119
Notes payable and current portion of long-term debt		64			64
Deferred income taxes		10			1
Liabilities held for sale		11			—
Total Current Liabilities		1,811			1,681
Long-term debt		5,898			5,872
Long-term debt, affiliates		200			200
Long-Term Debt		6,098			6,072
Other Liabilities
Liabilities from risk-management activities		314			288
Deferred income taxes		1,103			1,052
Other long-term liabilities		487			498
Total Liabilities		9,813			9,591
Commitments and Contingencies (Note 12)
Stockholders' Equity
Capital Stock, $1 par value, 1,000 shares authorized at March 31, 2009 and December 31, 2008		—			—
Additional paid-in capital		5,545			5,684
Affiliate receivable		(829	)		(827	)
Accumulated other comprehensive loss, net of tax		(212	)		(215	)
Accumulated deficit		(364	)		(29	)
Total Dynegy Holdings Inc. Stockholder’s Equity		4,140			4,613
Noncontrolling interest		(4	)		(30	)
Total Stockholders’ Equity		4,136			4,583
Total Liabilities and Stockholders’ Equity	$	13,949		$	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 March 31,
	2009			2008
Revenues	$	904		$	543
Cost of sales		(381	)		(451	)
Operating and maintenance expense, exclusive of depreciation and amortization shown separately below		(124	)		(111	)
Depreciation and amortization expense		(92	)		(92	)
Goodwill impairments		(433	)		—
Impairment and other charges, exclusive of goodwill impairments shown separately above		(5	)		—
General and administrative expenses		(38	)		(39	)

Operating loss		(169	)		(150	)
Earnings (losses) from unconsolidated investments		7			(5	)
Interest expense		(98	)		(109	)
Other income and expense, net		4			20

Loss from continuing operations before income taxes		(256	)		(244	)
Income tax (expense) benefit (Note 14)		(82	)		91

Loss from continuing operations		(338	)		(153	)
Income from discontinued operations, net of tax benefit of zero and $1, respectively (Notes 2 and 14)		1			—

Net loss		(337	)		(153	)
Less: Net loss attributable to the noncontrolling interest		(2	)		—

Net loss attributable to Dynegy Holdings Inc.	$	(335	)	$	(153	)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Three Months Ended March 31,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(337	)	$	(153	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization		94			94
Goodwill impairments		433			—
Impairment and other charges		5			—
(Earnings) losses from unconsolidated investments, net of cash distributions		(7	)		5
Risk-management activities		(168	)		280
Deferred income taxes		80			(90	)
Other		16			(1	)
Changes in working capital:
Accounts receivable		56			36
Inventory		(6	)		14
Prepayments and other assets		(38	)		(55	)
Accounts payable and accrued liabilities		58			19
Changes in non-current assets		(7	)		(6	)
Changes in non-current liabilities		4			3

Net cash provided by operating activities		183			146

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(138	)		(131	)
Proceeds from asset sales, net		—			57
Decrease in short-term investments		8			—
Increase in restricted cash		(32	)		(25	)
Affiliate transactions		(2	)		1
Other investing		—			6

Net cash used in investing activities		(164	)		(92	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net		25			51
Dividend to affiliate		(175	)		—
Other financing, net		—			(1	)

Net cash provided by (used in) financing activities		(150	)		50

Net increase (decrease) in cash and cash equivalents		(131	)		104
Cash and cash equivalents, beginning of period		670			292

Cash and cash equivalents, end of period	$	539		$	396

Other non-cash investing activity:
Non-cash capital expenditures	$	23		$	9

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)

	Three Months Ended March 31,
	2009			2008

Net loss	$	(337	)	$	(153	)
Cash flow hedging activities, net:
Unrealized mark-to-market gains (losses) arising during period, net		34			(26	)
Reclassification of mark-to-market losses to earnings, net		—			8
Deferred losses on cash flow hedges, net		(3	)		—

Changes in cash flow hedging activities, net (net of tax (expense) benefit of $(9) and $5, respectively)		31			(18	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $2 and zero)		(1	)		—
Net unrealized loss on securities, net (net of tax benefit of zero and $3, respectively)		—			(4	)
Unconsolidated investments other comprehensive loss, net (net of tax expense of $1 and zero)		1			—

Other comprehensive income (loss), net of tax		31			(22	)

Comprehensive loss		(306	)		(175	)
Less: Comprehensive income (loss) attributable to the noncontrolling interest		26			(11	)

Comprehensive loss attributable to Dynegy Holdings Inc.	$	(332	)	$	(164	)

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 March 31, 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 SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (“SFAS No. 160”), as discussed below, but does not include all disclosures required by accounting principles generally accepted in the United States of America. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in Dynegy’s and DHI’s Form 10-K for the year ended December 31, 2008 filed on February 26, 2009, which we refer to as each registrant’s “Form 10-K”.

The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal and recurring nature that, in the opinion of management, are necessary for a fair statement of the results for the interim periods. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors. The preparation of the unaudited condensed consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations. These estimates and judgments also impact the nature and extent of disclosure, if any, of our contingent liabilities based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications, (vi) estimating various factors used to value our pension assets and liabilities and (vii) determining the primary beneficiary of certain VIEs from a set of related parties. Actual results could differ materially from any such estimates. Certain reclassifications have been made to prior period amounts in order to conform to current year presentation.

Accounting Principles Adopted

SFAS No. 141(R). On January 1, 2009, we adopted SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) requires the acquiring entity in a business combination to recognize the assets acquired and liabilities assumed in the transaction; establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; and requires the acquirer to disclose to investors and other users all of the information they need to evaluate and understand the nature and financial effect of the business combination. The adoption of this statement had no impact on our financial statements.

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

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

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

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

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

Accounting Principle Not Yet Adopted

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

Note 2—Discontinued Operations

Heard County. On April 30, 2009, we completed our sale of our interest in the Heard County power generation facility to Oglethorpe Power Corporation (“Oglethorpe”) for approximately $105 million and will record a gain of approximately $10 million in the second quarter 2009.

Beginning in the first quarter 2009, Heard County met the held for sale classification requirements of SFAS No. 144, "Accounting for the impairment or Disposal of Long-Lived Assets", and is classified as such on our unaudited condensed consolidated balance sheet. The major classes of current and long-term assets classified as assets held for sale at March 31, 2009 are approximately $95 million of property, plant and equipment, net, less than $1 million of inventory, $11 million of deferred tax liabilities and less than $1 million of accrued liabilities and other current liabilities.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of Heard County’s property, plant and equipment during the first quarter 2009. Depreciation and amortization expense related to Heard County totaled approximately $1 million in the three-month periods ended March 31, 2009 and 2008. Also pursuant to SFAS No. 144, 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 to Entergy Gulf States, Inc. for approximately $56 million, net of transaction costs.

In accordance with SFAS No. 144, we discontinued depreciation and amortization of Calcasieu’s property, plant and equipment during the first quarter 2007. Depreciation and amortization expense related to Calcasieu totaled zero in the three-month period ended March 31, 2008. Also pursuant to SFAS No. 144, we are reporting the results of Calcasieu’s operations in discontinued operations for the three-month period ended March 31, 2008.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

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

	Heard County		Calcasieu			Total
	(in millions)
Three Months Ended March 31, 2009
Revenues	$	2	$	—		$	2
Income from operations before taxes		1		—			1
Income from operations after taxes		1		—			1

Three Months Ended March 31, 2008
Revenues	$	2	$	—		$	2
Loss on sale before taxes		—		(1	)		(1	)
Loss on sale after taxes		—		—			—

Note 3—Noncontrolling Interests

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

	Dynegy Inc.						Dynegy Holdings Inc.
	Three Months Ended March 31,						Three Months Ended March 31,
	2009			2008			2009			2008
	(in millions)
Loss from continuing operations	$	(336	)	$	(152	)	$	(336	)	$	(153	)
Income from discontinued operations, net of tax benefit of zero, $1, zero and $1, respectively		1			—			1			—

Net loss	$	(335	)	$	(152	)	$	(335	)	$	(153	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

The following table presents a reconciliation of the carrying amount of total equity, equity attributable to Dynegy and the equity attributable to the noncontrolling interest at the beginning and the end of the three months ended March 31, 2009:

	Controlling Interest			Noncontrolling Interest			Total
	(in millions)
December 31, 2008	$	4,515		$	(30	)	$	4,485
Net loss		(335	)		(2	)		(337	)
Other comprehensive loss, net of tax:
Unrealized mark-to-market gains arising during period		4			30			34
Reclassification of mark-to-market gains (losses) to earnings		(1	)		1			—
Deferred losses on cash flow hedges		—			(3	)		(3	)
Amortization of unrecognized prior service cost and actuarial loss		(1	)		—			(1	)
Unconsolidated investments other comprehensive loss		1			—			1
Total other comprehensive income, net of tax		3			28			31
Other equity activity:
Options and restricted stock granted		2			—			2
401(k) plan and profit sharing stock		1			—			1
Board of directors stock compensation		(2	)		—			(2	)

March 31, 2009	$	4,184		$	(4	)	$	4,180

	Controlling Interest			Noncontrolling Interest			Total
	(in millions)
December 31, 2007	$	4,506		$	23		$	4,529
Net loss		(152	)		—			(152	)
Other comprehensive loss, net of tax:
Unrealized mark-to-market losses arising during period		(15	)		(11	)		(26	)
Reclassification of mark-to-market gains to earnings		8			—			8
Net unrealized loss on securities		(4	)		—			(4	)
Total other comprehensive loss, net of tax		(11	)		(11	)		(22	)
Other equity activity:
Subscriptions receivable		2			—			2
401(k) plan and profit sharing stock		1			—			1
Options and restricted stock granted		4			—			4

March 31, 2008	$	4,350		$	12		$	4,362

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

The following table presents a reconciliation of the carrying amount of total equity, equity attributable to DHI and the equity attributable to the noncontrolling interest at the beginning and the end of the of the three months ended March 31, 2009.

	Controlling Interest			Noncontrolling Interest			Total
	(in millions)
December 31, 2008	$	4,613		$	(30	)	$	4,583
Net loss		(335	)		(2	)		(337	)
Other comprehensive loss, net of tax:
Unrealized mark-to-market gains arising during period		4			30			34
Reclassification of mark-to-market gains (losses) to earnings		(1	)		1			—
Deferred losses on cash flow hedges		—			(3	)		(3	)
Amortization of unrecognized prior service cost and actuarial loss		(1	)		—			(1	)
Unconsolidated investments other comprehensive loss		1			—			1
Total other comprehensive income, net of tax		3			28			31
Other equity activity:
Dividend to Dynegy		(175	)		—			(175	)
Contribution from Dynegy		36			—			36
Affiliate activity		(2	)		—			(2	)

March 31, 2009	$	4,140		$	(4	)	$	4,136

	Controlling Interest			Noncontrolling Interest			Total
	(in millions)
December 31, 2007	$	4,597		$	23		$	4,620
Net loss		(153	)		—			(153	)
Other comprehensive loss, net of tax:
Unrealized mark-to-market losses arising during period		(15	)		(11	)		(26	)
Reclassification of mark-to-market gains to earnings		8			—			8
Net unrealized loss on securities		(4	)		—			(4	)
Total other comprehensive loss, net of tax		(11	)		(11	)		(22	)
Other equity activity:
Affiliate activity		5			—			5

March 31, 2008	$	4,438		$	12		$	4,450

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 commercial team also uses financial instruments in an attempt to capture the benefit of fluctuations in market prices in the geographic regions where our assets operate. Our treasury team seeks to manage our financial risks and exposures associated with interest expense variability.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

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 pursuant to the guidance in SFAS No. 133. We also manage commodity price risk by entering into capacity forward sales arrangements, tolling arrangements, RMR contracts, fixed price coal purchases and other arrangements that do not receive fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase normal sales.” As a result, the gains and losses with respect to these arrangements are not reflected in the unaudited condensed consolidated statements of operations until the settlement dates.

Quantitative Disclosures Related to Financial Instruments and Derivatives

On January 1, 2009, we adopted SFAS No. 161, which requires disclosure of the fair values of derivative instruments and their gains and losses in a tabular format. It also provides more information about an entity’s liquidity by requiring disclosure of derivative features that are credit risk-related and it requires cross-referencing within footnotes to enable financial statement users to locate important information about derivative instruments.

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 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 March 31, 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 March 31, 2009, we had net long/(short) commodity derivative contracts outstanding and notional interest rate swaps outstanding in the following quantities:

Contact Type	Hedge Designation	Quantity (in millions)			Unit of Measure	Net Fair Value (in millions)

Commodity contracts:
Electric energy	Not designated		(68	)	MW	$	364
Natural gas	Not designated		199		MMBtu	$	12
Other	Not designated		2		Misc.	$	(1	)

Interest rate contracts:
Interest rate swaps	Cash flow hedge		492		Dollars	$	(193	)
Interest rate swaps	Fair value hedge		25		Dollars	$	2
Interest rate swaps	Not designated		231		Dollars	$	(24	)
Interest rate swaps	Not designated		(206	)	Dollars	$	21

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 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 March 31, 2009, segregated between designated, qualifying SFAS No. 133 hedging instruments and those that are not, and by type of contract segregated by assets and liabilities as required by SFAS No. 161. We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we did not elect to adopt the netting provisions allowed under FSP FIN 39-1, “Amendment of FASB Interpretation No. 39”, which allows an entity to offset the fair value 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 consistent with the disclosure requirements of SFAS No. 161.

Contact Type	Balance Sheet Location	March 31, 2009			December 31, 2008
		(in millions)
Derivatives designated as hedging instruments under SFAS No. 133:
Derivative Assets:
Interest rate contracts	Assets from risk management activities	$	2		$	3
Derivative Liabilities:
Interest rate contracts	Liabilities from risk management activities		(193	)		(238	)
Other contracts	Liabilities from risk management activities		—			—
Total derivatives designated as hedging instruments under SFAS No. 133, net			(191	)		(235	)


Derivatives not designated as hedging instruments under SFAS No. 133:
Derivative Assets:
Commodity contracts	Assets from risk management activities		1,722			1,355
Interest rate contracts	Assets from risk management activities		21			19
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities		(1,347	)		(1,147	)
Interest rate contracts	Liabilities from risk management activities		(24	)		(22	)
Total derivatives not designated as hedging instruments under SFAS No. 133, net			372			205
Total derivatives, net		$	181		$	(30	)

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 months ended March 31, 2009 and 2008 segregated between designated, qualifying SFAS No. 133 hedging instruments and those that are not, by type of contract as required by SFAS No. 133.

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

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

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

During the three months ended March 31, 2009 and 2008, we recorded no income related to ineffectiveness from changes in fair value of derivative positions and no amounts were excluded from the assessment of hedge effectiveness related to the hedge of future cash flows in either of the periods. During the three months ended March 31, 2009 and 2008, no amounts were reclassified to earnings in connection with forecasted transactions that were no longer considered probable of occurring.

The balance in cash flow hedging activities within Accumulated other comprehensive income(loss), net at March 31, 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 in accordance with FAS No. 34, “Capitalization of Interest Cost”, a significant portion of the current and future derivative settlements will continue to be deferred in Accumulated other comprehensive income (loss) and reclassified to depreciation expense over the expected life of the plant once the Plum Point Project commences operations. Because not all of the interest expense is capitalized, of this amount, after-tax losses of approximately $1 million are currently estimated to be reclassified into earnings over the 12-month period ending March 31, 2010. The actual amounts that will be reclassified to earnings over this period and beyond could vary materially from this estimated amount as a result of changes in market prices, hedging strategies, the probability of forecasted transactions occurring and other factors.

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 March 31, 2009 and 2008 is presented below:

Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Amount of Gain (Loss) Recognized in OCI on Derivative (Effective Portion) For the Three Months Ended March 31,					Location of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)	Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) For the Three Months Ended March 31,
	2009		2008				2009		2008
	(in millions)						(in millions)
Interest rate contracts	$	39	$	(26	)	Interest expense	$	—	$	—
Commodity contracts (1)		—		—		Revenues		—		(10	)

Total	$	39	$	(26	)		$	—	$	(10	)

______________

(1)

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

Fair Value Hedges. We also enter into derivative instruments that qualify, and that we may elect to designate, as fair value hedges. We use interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into floating-rate debt. The maximum length of time for which we have hedged our exposure for fair value hedges is through 2012. During the three months ended March 31, 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 months ended March 31, 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 March 31, 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 statement of operations for the three months ended March 31, 2009 and 2008 is presented below:

Derivatives in SFAS No. 133 Fair Value Hedging	Location of Gain (Loss) Recognized in Income on	Amount of Gain (Loss) Recognized in Income on Derivative for the Three Months Ended March 31,				Hedged Items in SFAS No. 133 Fair Value Hedge	Location of Gain (Loss) Recognized in Income on Related	Amount of Gain (Loss) Recognized in Income on Related Hedged Items For the Three Months Ended March 31,
Relationships	Derivative	2009		2008		Relationship	Hedged Items	2009		2008
		(in millions)						(in millions)
Interest rate contracts	Interest expense	$	—	$	1	Fixed-rate debt	Interest expense	$	—	$	(1	)

Financial Instruments Not Designated as Hedges. In accordance with SFAS No. 133, we elect not to designate derivatives related to our power generation business as cash flow hedges. Thus, we apply mark-to-market accounting treatment to these derivatives. Accordingly, as fair values fluctuate from period to period due to market price volatility, fair value changes and unrealized and realized gains and losses are reflected in the unaudited condensed consolidated statements of operations within Revenues pursuant to EITF Issue 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”). As such, these mark-to-market gains and losses are not reflected in the unaudited condensed consolidated statements of operations in the same period as the underlying power sales from generation activity for which the derivative instruments serve as economic hedges.

For the three-month period ended March 31, 2009, our revenues included approximately $168 million of mark-to-market gains related to this activity compared to $280 million of mark-to-market losses in the same period in the prior year.

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the three months ended March 31, 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.

		Amount of Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended March 31,
Derivatives Not Designated as Hedging Instruments under SFAS No. 133	Location of Gain (Loss) Recognized in Income on Derivatives	2009			2008
		(in millions)
Commodity contracts	Revenues	$	267		$	(280	)
Interest Rate contracts	Interest expense		(1	)		(1	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 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 March 31, 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 March 31, 2009
	Level 1		Level 2		Level 3		Total
	(in millions)
Assets:
Assets from commodity risk management activities	$	—	$	1,681	$	41	$	1,722
Assets from interest rate swaps		—		23		—		23
Other—DHI (1)		—		16		—		16
Total—DHI		—		1,720		41		1,761
Other—Dynegy (1)		—		1		—		1

Total—Dynegy and DHI	$	—	$	1,721	$	41	$	1,762

Liabilities:
Liabilities from commodity risk management activities	$	—	$	1,339	$	8	$	1,347
Liabilities from interest rate swaps		—		217		—		217

Total—Dynegy and DHI	$	—	$	1,556	$	8	$	1,564

________________

(1)

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

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

	Three Months Ended March 31, 2009
	(in millions)
Balance at December 31, 2008	$	60
Realized and unrealized losses, net		(5	)
Purchases, issuances and settlements		(22	)

Balance at March 31, 2009	$	33

Unrealized gains relating to instruments still held as of March 31, 2009	$	10

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.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

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

On January 1, 2009, we adopted EITF Issue No. 08-5, which applies to liabilities issued with an inseparable third-party credit enhancement when they are measured or disclosed at fair value on a recurring basis. The underlying principle in the consensus in EITF Issue No. 08-5 is that a third-party credit enhancement does not relieve the issuer of its ultimate obligation under the liability. We had approximately $122 million of cash collateral postings as of March 31, 2009 included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets, which represents the effect of net cash outflows arising from the daily settlements of our exchange-traded or brokered commodity futures positions held with our futures clearing manager. In addition, we had approximately $1,081 million of letters of credit issued as collateral postings as of March 31, 2009. Substantially all of our derivative liability positions with our derivative counterparties are supported by letters of credit issued pursuant to our Fifth Amended and Restated Credit Facility or by cash collateral postings. As a result of the consensus in EITF Issue No. 08-5, we no longer can consider the letters of credit as credit enhancements in our valuation of our derivative liabilities beginning in 2009. Based on our net risk management asset position as of January 1, 2009 and March 31, 2009, we did not have significant letters of credit posted in support of our derivative liabilities. Accordingly, our adoption of EITF Issue No. 08-5 did not result in a material effect on our unaudited condensed consolidated financial statements in the first quarter 2009.

On January 1, 2009, we adopted SFAS No. 157 for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis, which had been deferred under FSP SFAS No. 157-2. The following table sets forth by level within the fair value hierarchy our fair value measurements with respect to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis as of March 31, 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 March 31, 2009
	Level 1		Level 2		Level 3		Total		Total Losses
	(in millions)
Assets:
Goodwill	$	—	$	—	$	—	$	—	$	(433	)
Assets held and used		—		—		58		58	$	(5	)

Total	$	—	$	—	$	58	$	58	$	(438	)

In accordance with the provisions of SFAS No. 142, 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 6—Impairment Charge and 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.

In accordance with the provisions of SFAS No. 144, during the first quarter 2009, long-lived assets held and used with a carrying amount of $63 million were written down to their fair value of $58 million, resulting in an impairment charge of $5 million, which is included in Impairment and other charges on our unaudited condensed consolidated statements of operations. Please read Note 6—Impairment Charge 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 March 31, 2009 and 2008

Note 6—Impairment Charge

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 under SFAS No. 144. In accordance with SFAS No. 144, we performed an impairment analysis and recorded a pre-tax impairment charge of $5 million ($3 million after tax). This charge, which relates to the Bluegrass power generation facility, is included in Impairment and other charges in our unaudited condensed consolidated statements of operations. We determined the fair value of the Bluegrass facility using assumptions that reflect our best estimate of third party market participants' considerations in accordance with SFAS No. 157.

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:

	March 31, 2009			December 31, 2008
	(in millions)
Cash flow hedging activities, net	$	(122	)	$	(125	)
Unrecognized prior service cost and actuarial loss		(67	)		(66	)
Accumulated other comprehensive loss—unconsolidated investments		(23	)		(24	)

Accumulated other comprehensive loss, net of tax	$	(212	)	$	(215	)

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 in accordance with the provisions of FIN No. 46(R), “Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51” (“FIN No. 46(R)”). There was no material change during the three months ended March 31, 2009. Please see Note 12—Variable Interest Entities—Hydroelectric Generation Facilities in our Form 10-K for discussion of these entities.

PPEA Holding Company LLC. We own an approximate 37 percent interest in PPEA Holding Company LLC (“PPEA Holding”) which, through its wholly-owned subsidiary, Plum Point Energy Associates, LLC (“PPEA”) owns an approximate 57 percent undivided interest in a 665 MW coal fired power generation facility (the “Plum Point Project”), which is under construction in Mississippi County, Arkansas. Our net investment in PPEA Holding at March 31, 2009 was a liability of approximately $105 million. Our unaudited condensed consolidated balance sheet included $530 million of plant construction in progress at March 31, 2009 that is collateral for the Plum Point Project debt. As of March 31, 2009, we have posted a $15 million letter of credit 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. As such, we have consolidated it in accordance with the provisions of FIN No. 46(R). Please see Note 12—Variable Interest Entities—PPEA Holding Company LLC in our Form 10-K for further discussion.

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(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

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


	March 31, 2009			December 31, 2008
	(in millions)
Current assets	$	1		$	1
Property, plant and equipment, net	533				507
Intangible asset	193				193
Other non-current asset	27				29
Total assets	754				730
Current liabilities	22				19
Long-term debt	642				615
Non-current liabilities	199				244
Noncontrolling interest	(4		)		(30	)
Operating loss	(2		)		(1	)
Net loss	(1		)		(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.

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, in accordance with FIN No. 46(R), do not consolidate them. We account for our investments in SCH and SC Services as equity method investments pursuant to APB 18. At March 31, 2009, we had $6 million included in non-current Accounts receivable, affiliate and $68 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 $281 million.

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For the Interim Periods Ended March 31, 2009 and 2008

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% and 17%, 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 is unlikely that Dynegy’s market capitalization will 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.

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 to 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.

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(Unaudited)

For the Interim Periods Ended March 31, 2009 and 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 remains 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 has continued to remain below its book equity for more than six months and given the absence of recent asset sales transaction activity to reasonably corroborate the results of our income approach valuation, we have determined that there has been a shift in the manner in which market participants are currently valuing our business, and believe 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.

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. While we have not finalized this second step of our impairment analysis due to the complexities involved in determining the implied fair value of the goodwill of each reporting unit, based on the work performed to date, which is substantially complete we have concluded that an impairment loss is probable and can be reasonably estimated. We have therefore recorded 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 March 31, 2009	$	—		$	—		$	—		$	—

We expect to finalize the second step of our impairment analysis as soon as reasonably practicable and we will record any further accounting entries that may be required, although none are currently expected.

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(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

Note 10—Related Party Transactions

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

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

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

Note 11—Dynegy’s Loss Per Share

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

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

	Three Months Ended March 31,
	2009			2008
	(in millions, except per share amounts)
Loss from continuing operations	$	(338	)	$	(152	)
Less: Net loss attributable to the noncontrolling interest		(2	)		—
Loss from continuing operations attributable to Dynegy Inc. for basic and diluted loss per share	$	(336	)	$	(152	)

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

Loss per share from continuing operations attributable to Dynegy Inc:
Basic	$	(0.40	)	$	(0.18	)

Diluted (1)	$	(0.40	)	$	(0.18	)

___________

(1)

When an entity has a net loss from continuing operations, SFAS No. 128, “Earnings per Share,” prohibits the inclusion of potential common shares in the computation of diluted per-share amounts. Accordingly, Dynegy has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2009 and 2008.

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For the Interim Periods Ended March 31, 2009 and 2008

Note 12—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. In accordance with SFAS No. 5, “Accounting for Contingencies,” we record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. In all instances, management has assessed the matters below based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.

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

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

Danskammer SPDES Permit — In January 2005, the New York State Department of Environmental Conservation (“NYSDEC”) issued a Draft SPDES Permit renewal for the Danskammer facility. Three environmental groups sought to impose a permit requirement that the Danskammer facility install a closed cycle cooling system. A formal evidentiary hearing was held and the revised Danskammer SPDES Permit was issued on June 1, 2006 with conditions generally favorable to us. While the revised Danskammer SPDES Permit does not require installation of a closed cycle cooling system, it does require aquatic organism mortality reductions resulting from NYSDEC’s determination of BTA requirements under its regulations. The petitioners appealed and on September 19, 2008, the Appellate Division issued its Memorandum and Judgment confirming the determination of NYSDEC in issuing the revised Danskammer SPDES Permit and dismissed the appeal. Both the Third Department and the New York Court of Appeals have denied petitions for leave to appeal.

Roseton SPDES Permit — In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton facility. The Draft Roseton SPDES Permit would require the facility to actively manage its water intake to substantially reduce mortality of aquatic organisms. In July 2005, a public hearing was held to receive comments on the Draft Roseton SPDES Permit. Three environmental organizations filed petitions for party status in the permit renewal proceeding. The petitioners are seeking to impose a permit requirement that the Roseton facility install a closed cycle cooling system. In September 2006, the administrative law judge issued a ruling admitting the petitioners to party status and setting forth the issues to be adjudicated in the permit renewal hearing. Various holdings in the ruling have been appealed to the Commissioner of NYSDEC by the petitioners, NYSDEC staff and us. We expect that the adjudicatory hearing on the Draft Roseton SPDES Permit will begin in 2009. We believe that the petitioners’ claims lack merit and we plan to oppose those claims vigorously.

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For the Interim Periods Ended March 31, 2009 and 2008

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

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

Gas Index Pricing Litigation. We, several of our affiliates and other energy companies are named as defendants in numerous lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to certain index publications in the 2000-2002 timeframe. The 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 November 2007, the case was argued to the appellate court. In October 2008, the appellate court reversed the dismissal and remanded the case for further proceedings. In December 2008, the defendants applied for leave to seek review of the appellate court decision by the Tennessee Supreme Court.

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

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For the Interim Periods Ended March 31, 2009 and 2008

The remaining six cases, three of which seek class certification, are also pending in Nevada federal court. Five of the cases were transferred through the multi-district litigation management process from other states, including Kansas, Wisconsin, Missouri and Illinois. All of the cases contain similar claims that individually and in conjunction with other energy companies, we engaged in an illegal scheme to inflate natural gas prices by providing false information to natural gas index publications. The complaints rely heavily on prior FERC and CFTC investigations into and reports concerning index manipulation in the energy industry. The lawsuits seek actual and punitive damages, restitution and/or expenses, and are currently in the discovery phase. In December 2008, class plaintiffs filed motions for class certification. Defendant’s opposition is due by May 15, 2009.

We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining matters. Due to the uncertainty of litigation, we cannot predict whether we will incur any liability in connection with these lawsuits. However, given the nature of the claims, an adverse result in these proceedings could have a material effect on our financial condition, results of operations and cash flows.

Nevada Power Arbitration. Through indirect subsidiaries, we and Chevron USA are equal stakeholders in Nevada Cogeneration Associates #2 (“Black Mountain”), a power generation facility located in Clark County, Nevada. Black Mountain operates under a long-term power sale agreement (“PSA”) with NV Energy Inc (formerly known as Nevada Power Company) through April 2023. In October 2007, NV Energy Inc. (“NV Energy”) initiated an arbitration against the joint venture seeking declaratory relief that (i) NV Energy’s methodology for calculating a cumulative excess payment in the event of default or early termination is correct and (ii) the joint venture is obligated to repay to NV Energy the full amount of any outstanding excess payment in the event of a default or early termination or upon the expiration of the PSA in 2023. NV Energy alleged that as of December 31, 2007, the balance of the cumulative excess payment was approximately $136 million and projected it to be approximately $365 million in 2023. In January 2009, the arbitrator issued an order (the "January Order") in Black Mountain’s favor, holding that under the PSA: (i) the cumulative excess payment was intended solely as a remedy in the event of a material breach of the PSA by Black Mountain, and that the cumulative excess payment amount, if one then exists, is not owed at the end of the contract term; and (ii) the cumulative excess payment must be calculated using simple interest, not compound interest. In April 2009, the arbitrator issued a final award confirming the January Order and apportioning all costs associated with the arbitration to NV Energy.

Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska initiated an action in federal court in the Northern District of California against DHI and 23 other companies in the energy industry. Plaintiffs claim that defendants’ emissions of greenhouse gases including CO2 contribute to climate change and have caused significant damage to a native Alaskan Eskimo village through increased vulnerability to waves, storm surges and erosion. In June 2008, defendants filed multiple motions to dismiss which are now fully briefed. A hearing on defendants’ motions is scheduled for May 2009. We believe the plaintiffs’ suit lacks merit and we intend to oppose their claims vigorously.

Information Request under Section 114 of the Clean Air Act. On March 9, 2009, we received an information request from the U.S. EPA regarding maintenance, repair and replacement projects undertaken between January 1, 2000 and the present at the Danskammer facility. We submitted our initial response to the information request on April 7, 2009 and are continuing to cooperate with the U.S. EPA to provide additional information to assure a complete response is provided to the agency’s request. The information request is related to a nationwide enforcement initiative by the U.S. EPA that could lead to an enforcement action, the nature of which cannot be predicted 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.

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(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

Guarantees and Indemnifications

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. Related to the indemnifications discussed below, we have accrued approximately $4 million as of March 31, 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 described above for which NRG could suffer a loss subsequent to the closing and that we would indemnify NRG for all costs or losses resulting from such litigation, as well as from other proceedings based on similar acts or omissions. West Coast Power is no longer a party to any active Gas Index Pricing Litigation matters. The indemnification agreement further provides that NRG assumes responsibility for all defense costs and any risk of loss, subject to certain conditions and limitations, arising from a February 2002 complaint filed at FERC by the California Public Utilities Commission alleging that several parties, including West Cost Power subsidiaries, overcharged the State of California for wholesale power. FERC found the rates charged by wholesale suppliers to be just and reasonable. However, this matter was appealed to the U.S. Supreme Court, which remanded the case to FERC for further review.

Targa Indemnities. During 2005, as part of our sale of DMSLP, we agreed to indemnify Targa Resources, Inc. (“Targa”) against losses it may incur under indemnifications DMSLP provided to purchasers of certain assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no significant expense under these prior indemnities and deem their value to be insignificant. We have recorded an accrual in association with the remediation of groundwater contamination at the Breckenridge Gas Processing Plant. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million. We have also indemnified Targa for certain tax matters arising from periods prior to our sale of DMSLP. We have recorded a tax reserve associated with this indemnification.

Illinois Power Indemnities. As a condition of Dynegy’s 2004 sale of Illinois Power and its interest in Electric Energy Inc.’s plant in Joppa, Illinois, Dynegy provided indemnifications to third parties regarding environmental, tax, employee and other representations. These indemnifications are limited to a maximum recourse of $400 million. Additionally, Dynegy has indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased natural gas and investments in specified items. Although there is no limitation on Dynegy’s liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses. Dynegy has made certain payments in respect of these indemnities following regulatory action by the ICC, and has established reserves for further potential indemnity claims. Further events, which fall within the scope of the indemnity, may still occur. However, Dynegy is not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. Dynegy intends to contest any proposed regulatory actions.

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For the Interim Periods Ended March 31, 2009 and 2008

Other Indemnities. During 2003, as part of our sales of the Rough and Hornsea natural gas storage facilities and certain natural gas liquids assets, we provided indemnities to third parties regarding tax representations. Maximum recourse under these indemnities is limited to $857 million and $28 million, respectively. As of March 31, 2009, no claims have been made against these indemnities. We also entered into similar indemnifications regarding environmental, tax, employee and other representations when completing other asset sales such as, but not limited to the Rolling Hills, Calcasieu and CoGen Lyondell power generating facilities. As of March 31, 2009, no claims have been made against these indemnities.

Note 13—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully described in Note 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 March 31,
	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

Contributions. During the three months ended March 31, 2009 and 2008, we made no contributions to our pension plans or other postretirement benefit plans. We expect to make contributions of approximately $27 million to our pension plans and $1 million to other benefit plans during 2009.

Note 14—Income Taxes

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

	Three Months Ended March 31,
	2009			2008
	(in millions, except rates)
Income tax (expense) benefit	$	(85	)	$	96

Effective tax rate		(34	%)		39	%

For the three months ended March 31, 2009, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to nondeductible goodwill. Additionally, a change in state income tax law resulted in additional income tax expense of approximately $21 million for the three months ended March 31, 2009. For the three months ended March 31, 2008, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

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

	Three Months Ended March 31,
	2009			2008
	(in millions, except rates)
Income tax (expense) benefit	$	(82	)	$	91

Effective tax rate		(32	%)		37	%

For the three months ended March 31, 2009, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to nondeductible goodwill. Additionally, a change in state income tax law resulted in additional income tax expense of approximately $15 million for the three months ended March 31, 2009. For the three months ended March 31, 2008, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to state income taxes.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

Note 15—Segment Information

We reported 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 months ended March 31, 2009 and 2008 is presented below:

Dynegy’s Segment Data as of and for the Three Months Ended March 31, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	525		$	82		$	297		$	—		$	904

Total revenues	$	525		$	82		$	297		$	—		$	904

Depreciation and amortization	$	(52	)	$	(22	)	$	(15	)	$	(3	)	$	(92	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges		(5	)		—			—			—			(5	)

Operating income (loss)	$	200		$	(287	)	$	(43	)	$	(37	)	$	(167	)

Earnings from unconsolidated investments		—			7			—			1			8
Other items, net		2			—			—			2			4
Interest expense														(98	)

Loss from continuing operations before income taxes														(253	)
Income tax expense														(85	)

Loss from continuing operations														(338	)
Income from discontinued operations, net of taxes														1

Net loss														(337	)
Less: Net loss attributable to the noncontrolling interest														(2	)

Net loss attributable to Dynegy Inc.													$	(335	)

Identifiable assets:
Domestic	$	6,992		$	3,118		$	2,513		$	1,489		$	14,112
Other		—			—			—			19			19

Total	$	6,992		$	3,118		$	2,513		$	1,508		$	14,131

Capital expenditures	$	(128	)	$	(1	)	$	(7	)	$	(2	)	$	(138	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

Dynegy’s Segment Data As of and for the Three Months Ended March 31, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	164		$	129		$	179		$	(1	)	$	471
Other		—			—			72			—			72

Total revenues	$	164		$	129		$	251		$	(1	)	$	543

Depreciation and amortization	$	(53	)	$	(23	)	$	(13	)	$	(3	)	$	(92	)

Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)

Losses from unconsolidated investments		—			(5	)		—			(4	)		(9	)
Other items, net		—			—			6			14			20
Interest expense														(109	)

Loss from continuing operations before income taxes														(248	)
Income tax benefit														96

Loss from continuing operations														(152	)
Loss from discontinued operations, net of taxes														—

Net loss														(152	)
Less: Net income attributable to the noncontrolling interest														—

Net loss attributable to Dynegy Inc.													$	(152	)

Identifiable assets:
Domestic	$	7,650		$	3,778		$	1,958		$	1,380		$	14,766
Other		—			—			46			11			57

Total	$	7,650		$	3,778		$	2,004		$	1,391		$	14,823

Unconsolidated investments	$	—		$	8		$	—		$	63		$	71

Capital expenditures and investments in unconsolidated affiliates	$	(115	)	$	(3	)	$	(10	)	$	(9	)	$	(137	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2009 and 2008 is presented below:

DHI’s Segment Data as of and for the Three Months Ended March 31, 2009

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	525		$	82		$	297		$	—		$	904

Total revenues	$	525		$	82		$	297		$	—		$	904

Depreciation and amortization	$	(52	)	$	(22	)	$	(15	)	$	(3	)	$	(92	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges		(5	)		—			—			—			(5	)

Operating income (loss)	$	200		$	(287	)	$	(43	)	$	(39	)	$	(169	)

Earnings from unconsolidated investments		—			7			—			—			7
Other items, net		2			—			—			2			4
Interest expense														(98	)

Loss from continuing operations before income taxes														(256	)
Income tax expense														(82	)

Loss from continuing operations														(338	)
Income from discontinued operations, net of taxes														1

Net loss														(337	)
Less: Net loss attributable to the noncontrolling interest														(2	)

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

Identifiable assets:
Domestic	$	6,992		$	3,118		$	2,513		$	1,307		$	13,930
Other		—			—			—			19			19

Total	$	6,992		$	3,118		$	2,513		$	1,326		$	13,949

Capital expenditures	$	(128	)	$	(1	)	$	(7	)	$	(2	)	$	(138	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2009 and 2008

DHI’s Segment Data As of and for the Three Months Ended March 31, 2008

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	164		$	129		$	179		$	(1	)	$	471
Other		—			—			72			—			72

Total revenues	$	164		$	129		$	251		$	(1	)	$	543

Depreciation and amortization	$	(53	)	$	(23	)	$	(13	)	$	(3	)	$	(92	)

Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)

Losses from unconsolidated investment		—			(5	)		—			—			(5	)
Other items, net		—			—			6			14			20
Interest expense														(109	)

Loss from continuing operations before income taxes														(244	)
Income tax benefit														91

Loss from continuing operations														(153	)
Loss from discontinued operations, net of taxes														—

Net loss														(153	)
Less: Net income attributable to the noncontrolling interest														—

Net loss attributable to attributable to Dynegy Holdings Inc.													$	(153	)

Identifiable assets:
Domestic	$	7,650		$	3,778		$	1,958		$	1,266		$	14,652
Other		—			—			46			11			57

Total	$	7,650		$	3,778		$	2,004		$	1,277		$	14,709

Unconsolidated investments	$	—		$	8		$	—		$	—		$	8

Capital expenditures	$	(115	)	$	(3	)	$	(10	)	$	(3	)	$	(131	)

Note 16—Subsequent Event

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

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DYNEGY INC. and DYNEGY HOLDINGS INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended March 31, 2009 and 2008

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

The following discussion should be read together with the unaudited condensed consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Form 10-K.

We are holding companies and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three separate segments in our consolidated financial statements: (i) the Midwest segment (“GEN-MW”); (ii) the West segment (“GEN-WE”); and (iii) the Northeast segment (“GEN-NE”). Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as general and administrative, interest and depreciation and amortization.

In addition to our operating generation facilities, we own an approximate 37 percent interest in PPEA Holding, which through its wholly owned subsidiary, owns a 57 percent undivided interest in the Plum Point Project, a 665 MW coal-fired power generation facility under construction in Arkansas, which is included in GEN-MW. We also own a 50 percent interest in SCEA, which owns a 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.

Recent Developments

Goodwill Impairment. 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, considered in the aggregate, indicated a reduction in the fair value of our reporting segments. As a result, although we have not yet finalized the second step of our impairment analysis, we recorded impairment charges of $76 million, $260 million and $97 million for our GEN-MW, GEN-WE and GEN-NE reporting units, respectively, as of March 31, 2009. Please see Note 9—Goodwill for further discussion.

DLS Power Holdings and DLS Power Development Dissolution. In December 2008, Dynegy entered into an agreement with LS Associates to dissolve DLS Power Holdings and DLS Power Development, our development joint ventures with LS Power Associates effective January 1, 2009. Under the terms of this agreement, we acquired exclusive rights related to repowering and expansion opportunities at our existing facilities. In the first quarter 2009, Dynegy subsequently contributed these assets to DHI. In return, LS Power Associates received a cash payment of approximately $19 million, as well as full rights to new greenfield development opportunities previously held by the joint venture. Please read Note 8—Variable Interest Entities—DLS Power Holdings and DLS Power Development for further discussion.

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

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.

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Our primary sources of internal liquidity are cash flows from operations, cash on hand, available capacity under our Credit Facility, of which the revolver capacity of $1,080 million is scheduled to mature in April 2012 and the term letter of credit capacity of $850 million is scheduled to mature in April 2013, and available capacity under our Contingent LC Facility, as described further below. Additionally, DHI may borrow money from time to time from Dynegy. Our primary sources of external liquidity are asset sales proceeds and proceeds from capital market transactions to the extent we engage in these transactions.

Operating cash flows provided by our power generation assets and the available cash we currently hold are expected to be sufficient to fund the operation of our business, as well as our planned capital expenditure program, including expenditures in connection with the Midwest Consent Decree, 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 15—Debt—Fifth Amended and Restated Credit Facility in our Form 10-K for a discussion of the financial covenants contained in the DHI's Fifth Amended and Restated Credit Facility (the "Credit Facility"), as well as the discussion below regarding our Revolver Capacity.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at May 1, 2009, March 31, 2009 and December 31, 2008:

	May 1, 2009			March 31, 2009			December 31, 2008
	(in millions)
Revolver capacity (1)(2)	$	1,080		$	1,080			$	1,080
Borrowings against revolver capacity		—			—				—
Term letter of credit capacity, net of required reserves		825			825				825
Plum Point and Sandy Creek letter of credit capacity		377			377				377
Available contingent letter of credit facility capacity (3)		—			—				—
Outstanding letters of credit	(997		)		(1,081	)			(1,135	)

Unused capacity	1,285				1,201				1,147

Cash—DHI	646				539				670

Total available liquidity—DHI	1,931				1,740				1,817
Cash—Dynegy	183				183				23

Total available liquidity—Dynegy	$	2,114		$	1,923			$	1,840

____________

(1)

We currently have a syndicate of lenders participating in the revolving portion of our Credit Facility with commitments ranging from $10 million to $105 million. Other than the commitment from one lender that filed for protection from creditors under chapter 11 bankruptcy law, we have not experienced, nor do we currently anticipate, any difficulties in obtaining funding from any of the lenders at this time. However, we continue to monitor the environment, and any lack of or delay in funding by a significant member or multiple members of our banking group would negatively affect our liquidity position.

(2)

Based on management’s current 2009 forecast of EBITDA, DHI’s available liquidity under the Credit Facility is expected to be reduced temporarily in mid-to late-2009 as a result of borrowing limitations under the covenant regarding the ratio of secured debt to EBITDA. See “Revolver Capacity” below for further discussion.

(3)

Under the terms of the Contingent LC Facility, up to $300 million of capacity can become available, contingent on 2009 forward natural gas prices rising above $13/MMBtu. Over the course of 2009, the ratio of availability per dollar increase in natural gas prices will be reduced, on a pro rata monthly basis, to zero by year-end.

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Cash on Hand. At May 1, 2009 and March 31, 2009, Dynegy had cash on hand of $829 million and $722 million, respectively, as compared to $693 million at December 31, 2008. The increase in cash on hand as compared to the end of 2008 is primarily attributable to cash provided by operating activities of our power generation business.

At May 1, 2009 and March 31, 2009, DHI had cash on hand of $646 million and $539 million, respectively, as compared to $670 million at December 31, 2008. The decrease in cash on hand as compared to the end of 2008 is primarily attributable to a dividend of $175 million paid to Dynegy in January 2009 partially offset by cash provided by the operating activities of our power generation business.

Revolver Capacity. As of May 1, 2009, $997 million in letters of credit are outstanding but undrawn, and we have no revolving loan amounts drawn under the Credit Facility, which is our primary credit facility. Based on management’s current 2009 forecast of EBITDA, the potential use by DHI of available liquidity under the Credit Facility is likely to be reduced temporarily during 2009 in order to remain in compliance with the covenant set forth in Section 7.11 of the Credit Facility regarding the ratio of secured debt to EBITDA (each as defined therein). The effect of reduced availability under the Credit Facility would be less available liquidity to DHI. However, even after giving effect to this reduction, we believe we have sufficient liquidity and capital resources to support our operations for the next twelve months. Please read Note 15—Debt—Fifth Amended and Restated Credit Facility in our Form 10-K for further discussion of the Credit Facility.

Operating Activities

Historical Operating Cash Flows. Dynegy’s cash flow provided by operations totaled $165 million for the three months ended March 31, 2009. DHI’s cash flow provided by operations totaled $183 million for the three months ended March 31, 2009. During the period, our power generation business provided positive cash flow from operations of $255 million from the operation of our power generation facilities, reflecting positive earnings for the period. Corporate and other operations included a use of approximately $90 million and $72 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 and DHI’s cash flow provided by operations totaled $146 million for the three months ended March 31, 2008. During the period, our power generation business provided positive cash flow from operations of $239 million primarily due to positive earnings for the period, partly offset by an increased use of working capital. Corporate and other operations included a use of approximately $93 million in cash by Dynegy and DHI relating to corporate-level expenses and our former customer risk management business.

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

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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 May 1, 2009, March 31, 2009 and December 31, 2008:

	May 1, 2009		March 31, 2009		December 31, 2008
	(in millions)
By Business:
Generation	$	1,093	$	1,168	$	1,064
Other		189		189		189

Total	$	1,282	$	1,357	$	1,253
By Type:
Cash (1)	$	285	$	276	$	118
Letters of Credit		997		1,081		1,135

Total	$	1,282	$	1,357	$	1,253

___________

(1)

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

The changes in collateral postings from December 31, 2008 to March 31, 2009 and to May 1, 2009 is primarily due to the volume of forward power sales and fuel purchase transactions.

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

Investing Activities

Capital Expenditures. We continue to tightly manage our operating costs and capital expenditures. We had approximately $138 million and $131 million in capital expenditures during the three months ended March 31, 2009 and 2008. Our capital spending by reportable segment was as follows:

	March 31,
	2009		2008

GEN-MW	$	128	$	115
GEN-WE		1		3
GEN-NE		7		10
Other		2		3

Total	$	138	$	131

Capital spending in our GEN-MW segment primarily consisted of environmental and maintenance capital projects, as well as approximately $23 million and $54 million spent on development capital related to the Plum Point project during the three months ended March 31, 2009 and 2008, respectively. Capital spending in our GEN-WE and GEN-NE segments primarily consisted of maintenance projects.

During the first quarter 2009, we revised our estimate of the timing regarding a maintenance capital project at our Moss Landing facility in GEN-WE. We expect capital expenditures for the remainder of 2009 to be approximately $40 million higher than originally planned, primarily due to the change in timing.

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Asset Dispositions. Proceeds from asset sales during the three months ended March 31, 2008 totaled $56 million and primarily related to the sale of our Calcasieu power generating facility, net of transaction costs. Please read Note 2—Discontinued Operations—Calcasieu for further discussion.

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

Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure and market recovery expectations. We consider divestitures of non-core generation assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the value that can be captured through a divestiture outweighs the benefits of continuing to own and operate such assets. Additional dispositions of one or more generation facilities or other investments could occur in 2009 or beyond. Were any such sale or disposition to be consummated, the disposition could result in accounting charges related to the affected asset(s), and our future earnings and cash flows could be affected.

Other Investing Activities. Cash inflow related to short-term investments during the three months ended March 31, 2009 totaled $8 million for both Dynegy and DHI, reflecting a distribution from our short-term investments. There was a $32 million cash outflow during the three months ended March 31, 2009 due to changes in restricted cash balances primarily due to a $35 million increase in the Independence restricted cash balance.

Dynegy made $6 million in contributions to DLS Power Holdings during the three months ended March 31, 2008. There was a $25 million cash outflow during the three months ended March 31, 2008 due to changes in restricted cash balances primarily due to a $30 million increase in the Independence restricted cash balance. Finally, Other included $6 million of insurance proceeds and $4 million of proceeds from the liquidation of an investment during the three months ended March 31, 2008.

Financing Activities

Historical Cash Flow from Financing Activities. Dynegy’s net cash provided by financing activities during the three months ended March 31, 2009 totaled $25 million primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility. DHI’s net cash used in financing activities during the three months ended March 31, 2009 totaled $150 million. This includes a one-time dividend payment from DHI to Dynegy of $175 million offset by $25 million primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.

Dynegy’s and DHI’s net cash provided by financing activities during three months ended March 31, 2008 totaled $50 million, which primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.

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

Financial Covenants. Our Credit Facility contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter as specified below) that requires DHI and certain of its subsidiaries to maintain a ratio of secured debt to EBITDA for DHI and its relevant subsidiaries of no greater than 2.75:1 (March 31, 2009); and 2.5:1 (June 30, 2009 and thereafter); and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of EBITDA to consolidated interest expense for DHI and its relevant subsidiaries as of the last day of the measurement periods ending March 31, 2009 and June 30, 2009 of no less than 1.625:1; and ending September 30, 2009 and thereafter of no less than 1.75:1. We are in compliance with these covenants as of March 31, 2009, but expect a temporary reduction in availability of liquidity under our Credit Facility in mid-to late-2009 as a result of forecasted EBITDA and a corresponding borrowing limitation under the secured debt to EBITDA covenant. Despite this expected temporary reduction in our available liquidity, we believe we have sufficient liquidity and capital resources to support our operations for the next twelve months. Going foward, we will continue to monitor our compliance with the covenants relative to the earnings potential of our asset-based power generation portfolio. Please read “Revolver Capacity” above for further discussion.

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Subject to certain exceptions, DHI and its relevant subsidiaries are subject to restrictions on asset sales, incurring additional indebtedness, limitations on investments and certain limitations on dividends and other payments in respect of capital stock. Our lenders agreed to amend certain of these restrictions or limitations effective February 13, 2009. Based on our available liquidity as of March 31, 2009 and the additional capacity available under the Contingent LC Facility, we do not believe these limitations will affect our operations. Please read Note 15—Debt—Fifth Amended and Restated Credit Facility in our Form 10-K for further discussion of our Credit Facility.

Capital-Raising Transactions. As part of our ongoing efforts to maintain a capital structure that is closely aligned with the cash-generating potential of our asset-based business, which is subject to cyclical changes in commodity prices, we may explore additional sources of external liquidity. The timing of any transaction may be impacted by events, such as strategic growth opportunities, legal judgments or regulatory 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. Our ability to issue debt securities is limited by our financing agreements, including our Credit Facility.

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.

Capital Allocation. 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. 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.

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 first quarter 2009, and does not expect to pay a dividend on any class of its common stock in the foreseeable future.

Credit Ratings

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

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

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

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

Overview. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three month periods ended March 31, 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.

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 March 31, 2009 and 2008, respectively:

Dynegy’s Results of Operations for the Three Months Ended March 31, 2009

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

Revenues	$	525		$	82		$	297		$	—		$	904
Cost of sales		(141	)		(54	)		(186	)		—			(381	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(51	)		(33	)		(42	)		4			(122	)
Depreciation and amortization expense		(52	)		(22	)		(15	)		(3	)		(92	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above		(5	)		—			—			—			(5	)
General and administrative expense		—			—			—			(38	)		(38	)
Operating income (loss)	$	200		$	(287	)	$	(43	)	$	(37	)	$	(167	)
Earnings from unconsolidated investments		—			7			—			1			8
Other items, net		2			—			—			2			4
Interest expense														(98	)

Loss from continuing operations before income taxes														(253	)
Income tax expense														(85	)

Loss from continuing operations														(338	)
Income from discontinued operations, net of taxes														1
Net loss														(337	)

Less: Net loss attributable to the noncontrolling interest														(2	)

Net loss attributable to Dynegy Inc.													$	(335	)

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Dynegy’s Results of Operations for the Three Months Ended March 31, 2008

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

Revenues	$	164		$	129		$	251		$	(1	)	$	543
Cost of sales		(124	)		(123	)		(213	)		9			(451	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(46	)		(29	)		(46	)		10			(111	)
Depreciation and amortization expense		(53	)		(23	)		(13	)		(3	)		(92	)
General and administrative expense		—			—			—			(39	)		(39	)
Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)
Losses from unconsolidated investments		—			(5	)		—			(4	)		(9	)
Other items, net		—			—			6			14			20
Interest expense														(109	)

Loss from continuing operations before income taxes														(248	)
Income tax benefit														96

Net loss														(152	)
Less: Net loss attributable to the noncontrolling interest														—

Net loss attributable to Dynegy Inc.													$	(152	)

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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 March 31, 2009 and 2008, respectively:

DHI’s Results of Operations for the Three Months Ended March 31, 2009

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

Revenues	$	525		$	82		$	297		$	—		$	904
Cost of sales		(141	)		(54	)		(186	)		—			(381	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(51	)		(33	)		(42	)		2			(124	)
Depreciation and amortization expense		(52	)		(22	)		(15	)		(3	)		(92	)
Goodwill impairments		(76	)		(260	)		(97	)		—			(433	)
Impairment and other charges, exclusive of goodwill impairments shown separately above		(5	)		—			—			—			(5	)
General and administrative expense		—			—			—			(38	)		(38	)
Operating income (loss)	$	200		$	(287	)	$	(43	)	$	(39	)	$	(169	)
Earnings from unconsolidated investments		—			7			—			—			7
Other items, net		2			—			—			2			4
Interest expense														(98	)

Loss from continuing operations before income taxes														(256	)
Income tax expense														(82	)

Loss from continuing operations														(338	)
Income from discontinued operations, net of taxes														1

Net loss														(337	)
Less: Net loss attributable to the noncontrolling interest														(2	)

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

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DHI’s Results of Operations for the Three Months Ended March 31, 2008

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

Revenues	$	164		$	129		$	251		$	(1	)	$	543
Cost of sales		(124	)		(123	)		(213	)		9			(451	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(46	)		(29	)		(46	)		10			(111	)
Depreciation and amortization expense		(53	)		(23	)		(13	)		(3	)		(92	)
General and administrative expense		—			—			—			(39	)		(39	)
Operating loss	$	(59	)	$	(46	)	$	(21	)	$	(24	)	$	(150	)
Losses from unconsolidated investments					(5	)		—			—			(5	)
Other items, net		—			—			6			14			20
Interest expense														(109	)

Loss from continuing operations before income taxes														(244	)
Income tax benefit														91

Net loss														(153	)
Less: Net income attributable to the noncontrolling interest														—

Net loss attributable to Dynegy Holdings Inc.													$	(153	)

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The following table provides summary segmented operating statistics for the three months ended March 31, 2009 and 2008, respectively:

	Three Months Ended March 31,
	2009			2008
GEN-MW
Million Megawatt Hours Generated		6.5			5.9
In Market Availability for Coal Fired Facilities (1)		86	%		82	%
Average Capacity Factor for Combined Cycle Facilities (2)		30	%		10	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	39		$	68
Commonwealth Edison (NI Hub)	$	40		$	68
PJM West	$	55		$	79
Average Market Spark Spreads ($/MWh) (4):
PJM West	$	11		$	9

GEN-WE
Million Megawatt Hours Generated (5) (6)		1.5			2.4
Average Capacity Factor for Combined Cycle Facilities (2)		26	%		37	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)	$	40		$	80
Palo Verde	$	34		$	70
Average Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)	$	6		$	18
Palo Verde	$	5		$	9

GEN-NE
Million Megawatt Hours Generated		3.1			1.9
In Market Availability for Coal Fired Facilities (1)		97	%		94	%
Average Capacity Factor for Combined Cycle Facilities (2)		48	%		24	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	62		$	97
New York—Zone A	$	47		$	68
Mass Hub	$	59		$	90
Average Market Spark Spreads ($/MWh) (4):
New York—Zone A	$	10		$	4
Mass Hub	$	15		$	19
Fuel Oil	$	(9	)	$	(35	)

Average natural gas price—Henry Hub ($/MMBtu) (7)	$	4.58		$	8.58

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(1)

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

(2)

Reflects actual production as a percentage of available capacity.

(3)

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

(4)

Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to the Company.

(5)

Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the three months ended March 31, 2009 and 2008, respectively.

(6)

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

(7)

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

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

	Three Months Ended March 31, 2009
	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Impairments	$	(81	)	$	(260	)	$	(97	)	$	—		$	(438	)
Sandy Creek mark-to-market gains (1)		—			10			—			—			10
Taxes		—			—			—			(15	)		(15	)

Total—DHI		(81	)		(250	)		(97	)		(15	)		(443	)
Taxes		—			—			—			(6	)		(6	)

Total—Dynegy	$	(81	)	$	(250	)	$	(97	)	$	(21	)	$	(449	)

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(1)

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

There were no such items reported for the three months ended March 31, 2008.

Operating Loss

Operating loss for Dynegy was $167 million for the three months ended March 31, 2009, compared to operating loss of $150 million for the three months ended March 31, 2008. Operating loss for DHI was $169 million for the three months ended March 31, 2009, compared to operating loss of $150 million for the three months ended March 31, 2008.

Our operating loss for the first quarter 2009 was driven, in large part, by a $433 million impairment of goodwill. Please read Note 9—Goodwill for further discussion.

The impairment of goodwill was partly offset by mark-to-market gains on forward sales of power associated with our generating assets which are included in Revenues in the unaudited condensed consolidated statements of operations. Such gains, which totaled $169 million for the three months ended March 31, 2009, were a result of a decrease in forward market power prices or forward spark spreads during the first quarter. These gains compared to $284 million of mark-to-market losses for the three months ended March 31, 2008, when forward market power prices increased during the quarter.

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 March 31, 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 $200 million for the three months ended March 31, 2009, compared to an operating loss of $59 million for the three months ended March 31, 2008.

Revenues for the three months ended March 31, 2009 increased by $361 million compared to the three months ended March 31, 2008, cost of sales increased by $17 million and operating and maintenance expense increased by $5 million, resulting in a net increase of $339 million. The increase was primarily driven by the following:

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Mark-to-market gains – GEN-MW’s results for the three months ended March 31, 2009 included mark-to-market gains of $169 million related to forward sales, compared to $193 million of mark-to-market losses for the three months ended March 31, 2008. Of the $169 million in 2009 mark-to-market gains, $108 million of gains related to positions that settled or will settle in 2009, and the remaining $61 million related to positions that will settle in 2010 and beyond;

Additional capacity sales of approximately $9 million, as a result of improved capacity prices for 2009 compared with 2008; and

Increased volumes —Generated volumes increased by 10 percent, from 5.9 million MWh for the three months ended March 31, 2008, to 6.5 million MWh for the three months ended March 31, 2009. The increase in volumes was primarily driven by lower natural gas prices and higher market heat rates at our Kendall and Ontelaunee facilities offset by a forced outage at our Baldwin facility.

These items were partly offset by the following:

Decreased market prices – The average actual on-peak prices in the Cin Hub pricing region decreased from $68 per MWh for the three months ended March 31, 2008 to $39 per MWh for the three months ended March 31, 2009; and

Increased operating expense – operating expense increased from $46 million for the three months ended March 31, 2008 to $51 million for the three months ended March 31, 2009, primarily as a result of the timing of planned outages at certain of our coal-fired generating facilities.

Depreciation expense decreased from $53 million for the first quarter 2008 to $52 million for the first quarter 2009.

Operating income for the three months ended March 31, 2009 included a pre-tax charge of approximately $76 million for the impairment of goodwill, reflected in Goodwill impairment in our unaudited condensed consolidated statements of operations. Please read Note 9—Goodwill for further discussion.

In addition, we recorded a $5 million impairment of our Bluegrass power generating facility, reflected in Impairment and other charges in our unaudited condensed consolidated statements of operations.

Power Generation—West Segment. Operating loss for GEN-WE was $287 million for three months ended March 31, 2009, compared to a loss of $46 million for the three months ended March 31, 2008. Such amounts do not include results from our Heard County power generating facility, which have been classified as discontinued operations for all periods presented.

Revenues for the three months ended March 31, 2009 decreased by $47 million compared to the three months ended March 31, 2008, cost of sales decreased by $69 million and operating and maintenance expense increased by $4 million, resulting in a net increase of $18 million. The increase was primarily driven by the following: Reduced mark-to-market losses – GEN-WE’s results for the three months ended March 31, 2009 included mark-to-market losses of $29 million, compared to $47 million of mark-to-market losses for the three months ended March 31, 2008. Of the $29 million in 2009 mark-to-market losses, $18 million related to positions that settled or will settle in 2009, and the remaining $11 million related to positions that will settle in 2010 and beyond.

This item was offset by decreased volumes. Generated volumes were 1.5 million MWh for the three months ended March 31, 2009, down from 2.4 million MWh for the three months ended March 31, 2008. The volume decrease was driven in large part by decreased market spark spreads and reduced dispatch opportunities.

Depreciation expense decreased from $23 million for the first quarter 2008 to $22 million for the first quarter 2009.

Operating loss for the three months ended March 31, 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.

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Power Generation—Northeast Segment. Operating loss for GEN-NE was $43 million for the three months ended March 31, 2009, compared to an operating loss of $21 million for the three months ended March 31, 2008.

Revenues for the three months ended March 31, 2009 increased by $46 million compared to the three months ended March 31, 2008, cost of sales decreased by $27 million and operating and maintenance expense decreased by $4 million, resulting in a net increase of $77 million. The increase was primarily driven by the following:

Mark-to-market gains – GEN-NE’s results for the three months ended March 31, 2009 included mark-to-market gains of $29 million related to forward sales, compared to losses of $44 million for the three months ended March 31, 2008. Of the $29 million in 2009 mark-to-market gains, $23 million of gains related to positions that settled or will settle in 2009, and the remaining $6 million related to positions that will settle in 2010 and beyond; and

Increased volumes – Although on-peak market prices in New York Zone G, New York Zone A and Mass Hub decreased by 36 percent, 31 percent and 34 percent, respectively, spark spreads improved as a result of lower fuel prices resulting in higher volumes at each of our non-coal fired facilities.

Depreciation expense increased from $13 million for the first quarter 2008 to $15 million for the first quarter 2009.

Operating loss for the three months ended March 31, 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.

Other. Dynegy’s other operating loss for the three months ended March 31, 2009 was $37 million, compared to an operating loss of $24 million for the three months ended March 31, 2008. DHI’s other operating loss for the three months ended March 31, 2009 was $39 million, compared to an operating loss of $24 million for the three months ended March 31, 2008. Operating losses in both periods were comprised primarily of general and administrative expenses.

Cost of sales for the three months ended March 31, 2008 included the release of a $9 million liability associated with an assignment of a natural gas transportation contract. Operating and maintenance expense for the three months ended March 31, 2008 included the release of an $8 million of sales and use tax liability.

Consolidated general and administrative expenses were $38 million and $39 million for the three months ended March 31, 2009 and 2008, respectively.

Earnings (Losses) from Unconsolidated Investments

Dynegy’s earnings from unconsolidated investments were $8 million for the three months ended March 31, 2009 of which $7 related to the GEN-WE investment in Sandy Creek. The $7 million consisted of $10 million mark-to-market gains primarily related to interest rate swap contracts offset by $3 million of financing costs. Losses from unconsolidated investments were $9 million for the three months ended March 31, 2008, including a $5 million loss related to the GEN-WE investment in Sandy Creek. The remaining $4 million loss related to Dynegy’s investment in DLS Power Development, included in Other.

DHI’s earnings from unconsolidated investments of $7 million for the three months ended March 31, 2009 related to the GEN-WE investment in Sandy Creek. The $7 million consisted of $10 million mark-to-market gains primarily related to interest rate swap contracts offset by $3 million of financing costs. Losses from unconsolidated investments for the three months ended March 31, 2008 were $5 million, related to the GEN-WE investment in Sandy Creek.

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Other Items, Net

Dynegy’s and DHI’s other items, net, totaled $4 million of income for the three months ended March 31, 2009, compared to $20 million of income for the three months ended March 31, 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 $98 million for the three months ended March 31, 2009, compared to $109 million for the three months ended March 31, 2008. The decrease was primarily attributable to lower LIBOR rates on our variable-rate debt.

Income Tax (Expense) Benefit

Dynegy reported an income tax expense from continuing operations of $85 million for the three months ended March 31, 2009, compared to an income tax benefit from continuing operations of $96 million for the three months ended March 31, 2008. The 2009 effective tax rate was (34) percent, compared to 39 percent in 2008.

DHI reported an income tax expense from continuing operations of $82 million for the three months ended March 31, 2009, compared to an income tax benefit of $91 million from continuing operations for the three months ended March 31, 2008. The 2009 effective tax rate was (32) percent, compared to 37 percent in 2008.

The primary difference between the effective rates of (34) and (32) percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted from the effect of the goodwill impairment charge. As a result of this charge, which was nondeductible, we reported income tax expense for the period ended March 31, 2009, despite the fact that we reported a loss from continuing operations before income taxes. Additionally, for the three months ended March 31, 2009, Dynegy and DHI recorded $21 million and $15 million, respectively, of income tax expense related to a change in California state tax law. For the period ended March 31, 2008, the difference between the effective rates of 39 and 37 percent for Dynegy and DHI, respectively and the statutory rate of 35 percent resulted primarily from the effect of state income taxes in the taxing jurisdictions in which our assets operate.

Discontinued Operations

Income (Loss) From Discontinued Operations Before Taxes

During the three months ended March 31, 2009, our pre-tax income from discontinued operations was $1 million, related to the operation of the Heard County power generation facility. During the three months ended March 31, 2008, our pre-tax loss from discontinued operations was $1 million, related to a loss on the sale of the Calcasieu power generation facility.

Income Tax Benefit From Discontinued Operations

We recorded an income tax expense from discontinued operations of less than $1 million during the three months ended March 31, 2009, compared to an income tax benefit of $1 million during the three months ended March 31, 2008. These amounts reflect effective rates of zero and 100 percent, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” requires a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35 percent.

Outlook

Our fleet includes a diverse mixture of assets with various fuel, dispatch and merit order characteristics within each of our three regions. 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 sales will be achieved by selling energy and capacity through a combination of spot market sales and near-term contracts over a rolling 12–36 month time frame in time periods that we describe as Current, Current +1, and Current +2. At any given point in time, we will seek to balance predictability of earnings and cash flow with achieving the highest level of earnings and cash flow possible over the Current, Current +1 and Current +2 periods. In these periods, we understand that short-term market volatility can negatively impact our profitability, and we will seek to reduce those negative impacts through the disciplined use of near- and intermediate-term forward sales. As a result, our fleet-wide forward sales profile is fluid and subject to change. We expect to make fewer forward sales beyond the Current+2 period in order to realize the anticipated benefit of improved market prices over time as the supply and demand balance tightens.

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We expect that our future financial results will continue to reflect sensitivity to fuel and commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and IMA. Our commercial team actively manages commodity price risk associated with our unsold power production by trading in the forward markets that are correlated with our assets. We also participate in various regional auctions and bilateral opportunities. Our regional commercial strategies are particularly driven by the types of units that we have within a given region and the operating characteristics of those units.

Currently, substantially all of our expected generation for 2009 is contracted. As we look forward to 2010 and beyond, we are actively hedging and expect to enter 2010 with a substantial portion of the output of our fleet contracted for that year. Based on specific market conditions, at any point in time we may enter into transactions that will increase or decrease the portion of our output that has been contracted, since we actively manage our near-term market positions of less than three years. The financial markets continue to be characterized by turmoil and stock prices across industries, including ours, continue to be significantly depressed. These market conditions have resulted in a decreased willingness on the part of lenders to enter into new loans and a reduction in the number of counterparties participating in, and the volume of transactions available for execution in, the bilateral energy markets. Thus, it can be more difficult for us to optimize the value of our assets.

To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil, electric energy and capacity markets.

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

GEN-MW. Our Midwest consent decree (“Midwest Consent Decree”) requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. We have achieved all emission reductions scheduled to date under the Midwest Consent Decree and are in the process of installing additional emission control equipment to meet future Midwest Consent Decree emission limits. We expect our costs associated with the Midwest Consent Decree projects, which we expect to incur through 2012, to be approximately $960 million, which includes approximately $369 million spent to date. This estimate includes a number of assumptions and uncertainties beyond our control, including an assumption that labor and material costs will increase at four percent per year over the remaining project term.

Our Midwest coal and transportation requirements are 100 percent contracted through 2010. For 2009, the prices associated with these contracts are fixed. For 2010, approximately 25 percent of our coal requirements are unpriced and will be negotiated in 2009, becoming effective January 1, 2010. We expect that any price changes will be consistent with the historical price trend over the past several years.

We expect to participate in PJM’s future forward capacity auctions when they occur.

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

During the first quarter 2009, we revised our estimated timeline to perform certain maintenance activities at our Moss Landing power generation facility. We now expect this outage to occur in the latter half of 2009 rather than in 2010. We expect capital expenditures for the Moss Landing Facility to be approximately $40 million higher due to this change in timing.

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GEN-NE. We continue to maintain sufficient coal and fuel oil inventories to effectively manage our operations. We have contracted 100 percent and approximately 65 percent of our expected coal supply and freight requirements for 2009 and 2010, respectively, for our Danskammer power generation facility primarily from South American suppliers. Multiple sourcing options are available and under evaluation for the remainder of our 2010 supply needs. Coal prices in both the international and domestic markets have decreased significantly 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 further mitigate cost and supply risks for near and long-term coal supplies.

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

In New England, the ISO-NE is in the process of restructuring its capacity market and will be transitioning to a forward capacity market in 2010. During the transition from the pre-existing capacity markets in ISO-NE to the forward capacity market, all listed ICAP resources will receive monthly capacity payments, adjusted for each power year. The transitional payments for capacity commenced in December 2006, with a price of $3.05/KW-month, and gradually rise to $4.10/KW-month through September 1, 2010, when the forward capacity market will be fully effective. Capacity auctions for the 2010/2011 and 2011/2012 were held in 2008 and resulted in capacity payments of $4.50 KW/month and $3.60 KW/month respectively for our assets in New England.

Regulatory Matters

Climate Change and Greenhouse Gases. The federal government, and many states where we have generation facilities, are considering or are in some stage of implementing regulatory programs intended to reduce emissions of GHGs as a means of addressing climate change issues. 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). If the proposal becomes final, the U.S. EPA will be required to promulgate GHG emission standards under the CAA for GHGs emitted by mobile sources, which could result in significant impacts on the power generation industry through future rule-making activity. The imposition of limits on emissions of CO2, and equivalents by 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. Beginning in 2009, certain of our generating facilities are required to obtain CO2 allowances, through purchases from the states where they operate, in sufficient quantity to cover CO2 emissions. The extent to which the costs of meeting mandated emission reductions would be borne by power generators, or the ultimate users of electricity, is not known.

On March 31, 2009, the House Energy and Commerce Committee released a discussion draft of the American Clean Energy and Security Act of 2009. Title III of the discussion draft, entitled Reducing Global Warming Pollution, would establish a federal cap-and-trade program for GHG emissions aimed at reducing GHG emissions in the United States to 20% below 2005 levels by 2020 and to 83% below 2005 levels by 2050. Leaders in both houses of Congress and President Obama’s executive branch have expressed strong support for federal legislation to address climate change. While the discussion draft represents a comprehensive effort to restructure the energy market in the United States, at this early stage in the legislative process we cannot predict the specific requirements of any legislation that may ultimately be adopted by Congress and signed into law. Any significant mandatory reduction of GHG emissions from the electric generating sector aimed at addressing climate change could have a material adverse effect on our financial condition, results and cash flows.

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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 will be filed with FERC in June 2009.

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

In August 2007, three complaints were filed at FERC regarding the RSG allocation methodology. On November 10, 2008, FERC issued an order finding the then-existing RSG charge methodology unjust and unreasonable because it was not based on or related to cost-causation. FERC’s order also established a replacement cost allocation, which is currently being used to resettle RSG charges for the period from August 2007 until a redesigned RSG allocation is approved by FERC and implemented. Under the replacement cost allocation formula, we estimate that our net cash liability is approximately $6 million. In addition, certain market participants are in default of their share of the resettlement charges. Presently, such short-pay amounts are being apportioned to net creditors of MISO (including Dynegy); however, MISO is ultimately expected to consider the defaulted charges uncollectible and uplift the amount to all non-defaulting market participants, resulting in a refund of some portion of the shortage back to the original parties. On April 28, 2009, proceedings were initiated in the U.S. Court of Appeals for the D.C. Circuit, seeking modifications of FERC's order. Those proceeding are pending.

GEN-WE. Our assets in California will be subject to various state initiatives. As previously disclosed, we 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.

GEN-NE. Our assets in New York, Connecticut and Maine are subject to a mandatory state-driven GHG program known as the RGGI. The participating RGGI states have implemented a rule regulating GHG using a cap-and-trade program to reduce carbon emissions by at least 10 percent of base-year emission levels by the year 2018.

On March 18, 2009, RGGI held its third auction, in which over 31 million allowances for allocation year 2009, and over 2 million allowances for allocation year 2012, were sold at clearing prices of $3.51 per allowance and $3.05 per allowance, respectively. We have participated in each of the RGGI auctions and purchased a portion of the allowances required to cover our projected GHG emissions in the Northeast for the compliance periods beginning in 2009 and 2012. Auctions are expected to be held quarterly, with the fourth auction scheduled for June 17, 2009.

Assuming that 2009 CO2 emissions from our generating facilities in New York, Maine and Connecticut are comparable to 2008 CO2 emissions from these facilities (5.2 million tons), our estimated cost of allowances necessary to operate these facilities in 2009 would be approximately $17 million, based on the average cost of allowances purchased to date for the 2009 allocation year. Compliance with the allowance requirement under a cap-and-trade program can be achieved by reducing emissions, purchasing allowances or securing offset allowances from an approved offset project.

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RISK-MANAGEMENT DISCLOSURES

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

	As of and for the Three Months Ended March 31, 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		250
Cash received related to risk-management contracts settled in the period, net		(78	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other (2)		39

Fair value of portfolio at March 31, 2009	$	181

___________

(1)	Our modeling methodology has been consistently applied.

(2)	This amount consists of changes in value associated with fair value and cash flow hedges on debt.

The net risk management asset of $181 million is the aggregate of the following line items on our unaudited condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures. The following tables depict the mark-to-market value and cash flow components of our net risk-management assets and liabilities at March 31, 2009 and December 31, 2008. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below:

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

	Total		2009 (2)		2010		2011			2012		2013		Thereafter
	(in millions)
March 31, 2009	$	372	$	271	$	103	$	(6	)	$	1	$	1	$	2
December 31, 2008		205		158		41		1			1		1		3

Increase (decrease) (3)	$	167	$	113	$	62	$	(7	)	$	—	$	—	$	(1	)

____________

(1)

The table reflects the fair value of our net risk-management asset position, which considers time value, credit, price and other valuation adjustments necessary to determine fair value. These amounts exclude the fair value associated with certain derivative instruments designated as hedges. The net risk-management asset at March 31, 2009 of $181 million on the unaudited condensed consolidated balance sheets includes the $372 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts.

(2)	Amounts represent April 1 to December 31, 2009 values in the March 31, 2009 row and January 1 to December 31, 2009 values in the December 31, 2008 row.

(3)	The increase in the net risk management asset is due to an increase in the volume of outstanding positions as well as a significant decrease in the prices associated with these positions during the three months ended March 31, 2009.

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Cash Flow Components of Net Risk-Management Asset

	Three Months Ended March 31, 2009			Nine Months Ended December 31, 2009		Total 2009		2010		2011			2012		2013		Thereafter
	(in millions)
March 31, 2009 (1)	$	(83	)	$	298	$	215	$	126	$	(5	)	$	1	$	1	$	3
December 31, 2008							175		49		1			1		1		3

Increase (decrease)						$	40	$	77	$	(6	)	$	—	$	—	$	—

______________

(1)

The cash flow values for 2009 reflect realized cash flows for the three months ended March 31, 2009 and anticipated undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other valuation adjustments. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges.

The following table provides an assessment of net contract values by year as of March 31, 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)	$	148	$	230	$	73	$	(19	)	$	(15	)	$	(12	)	$	(109	)
Prices based on models		33		28		8		(7	)		1			1			2

Total (2)	$	181	$	258	$	81	$	(26	)	$	(14	)	$	(11	)	$	(107	)

_____________

(1)	Prices obtained from actively traded, liquid markets for commodities.

(2)	The market quotations and prices based on models categorization differs from the SFAS No. 157 categories of Level 1, Level 2 and Level 3 due to the application of the different methodologies. Please see Note 5—Fair Value Measurements for further discussion.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

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

beliefs about commodity pricing and generation volumes;

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

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

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

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

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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;

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

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

beliefs and assumptions regarding the current financial crisis and its impact on our liquidity needs and on the credit markets generally and our access thereto;

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

expectations regarding our revolver capacity, collateral demands, capital expenditures, interest expense and other payments;

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

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

expectations and estimates regarding capital and maintenance expenditures, including the Midwest Consent Decree and its associated costs; and

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

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth under Part II–Other Information, Item 1A-Risk Factors and Item 1A-Risk Factors of our Form 10-K.

RECENT ACCOUNTING PRONOUNCEMENTS

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

CRITICAL ACCOUNTING POLICIES

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

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 March 31, 2009.

Value at Risk (“VaR”). The following table sets forth the aggregate daily VaR of the mark-to-market portion of our risk-management portfolio primarily associated with the GEN segments and the remaining legacy customer risk management business. The VaR calculation does not include market risks associated with the accrual portion of the risk-management portfolio that is designated as a cash flow hedge or a “normal purchase normal sale”, nor does it include expected future production from our generating assets. The increase in the March 31, 2009 VaR was primarily due to increased forward sales as compared to December 31, 2008. Please read “Value at Risk” in our Form 10-K for a complete description of our valuation methodology.

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Daily and Average VaR for Risk-Management Portfolios

	March 31, 2009		December 31, 2008
	(in millions)
One day VaR—95 percent confidence level	$	34	$	21
One day VaR—99 percent confidence level	$	48	$	29
Average VaR for the year-to-date period—95 percent confidence level	$	26	$	42

Credit Risk. The following table represents our credit exposure at March 31, 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	$	180	$	—	$	180
Utility and power generators		12		—		12
Commercial, industrial and end users		—		4		4
Other		—		2		2

Total	$	192	$	6	$	198

Of the $6 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 March 31, 2009, our fixed rate debt instruments, as a percentage of total debt instruments, were approximately 74 percent. Adjusted for interest rate swaps, net notional fixed rate debt as a percentage of total debt was approximately 82 percent. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of March 31, 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 March 31, 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 March 31, 2009 and December 31, 2008, respectively:

Absolute Notional Contract Amounts

	March 31, 2009		December 31, 2008
Cash flow hedge interest rate swaps (in millions of U.S. dollars)	$	492	$	471
Fixed interest rate paid on swaps (percent)		5.32		5.32
Fair value hedge interest rate swaps (in millions of U.S. dollars)	$	25	$	25
Fixed interest rate received on swaps (percent)		5.70		5.70
Interest rate risk-management contract (in millions of U.S. dollars)	$	231	$	231
Fixed interest rate paid on swaps (percent)		5.35		5.35
Interest rate risk-management contract (in millions of U.S. dollars)	$	206	$	206
Fixed interest rate received on swaps (percent)		5.28		5.28

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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 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 March 31, 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 March 31, 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 12—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
January 1-31		1,765	$	2.38		—		N/A
February 1-28		2,483	$	1.84		—		N/A
March 1-31		106,676	$	1.04		—		N/A

Total		110,924	$	1.08		—		N/A

These were the only purchases of equity securities made by us during the three months ended March 31, 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
10.1			Dynegy Inc. 2009 Phantom Stock Plan (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443).

10.2			Form of Performance Award Agreement (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443).

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Exhibit Number			Description
10.3			Form of Performance Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443).

10.4			Form of Phantom Stock Unit Award Agreement (for Managing Directors and Above) (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443).

**10.5			Form of Phantom Stock Unit Award Agreement (for Directors and Below).

10.6			Form of Phantom Stock Unit Award Agreement between Dynegy Inc., all of its affiliates, and Bruce A. Williamson (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2009, File No. 001-33443).

**10.7			Form of Non Qualified Stock Option Award Agreement.

**10.8			Form of Non Qualified Stock Option Award Agreement between Dynegy Inc., all of its affiliates, and Bruce A. Williamson.

10.9			Dissolution Agreement by and between Dynegy Inc. and LS Power Associates, L.P., effective January 1, 2009 (incorporated by reference to Exhibit 10.14 to the Annual Report on Form 10-K of Dynegy Inc. filed on February 26, 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: May 7, 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: May 7, 2009	By:	/s/ HOLLI C. NICHOLS
		Holli C. Nichols Executive Vice President and Chief Financial Officer (Duly Authorized Officer and Principal Financial Officer)