Edgar Filing: DYNEGY HOLDINGS INC

form10-q.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, 2011

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

For the transition period from ________ to ________

DYNEGY INC.

DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)

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


1000 Louisiana, Suite 5800
Houston, Texas			77002
(Address of principal executive offices)			(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Dynegy Inc.			Yes x No o
Dynegy Holdings Inc.			Yes x No o

Indicate by check mark whether the registrant 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 o No o
Dynegy Holdings Inc.			Yes o No o

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

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

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

Dynegy Inc.			Yes o No x
Dynegy Holdings Inc.			Yes o No x

Indicate the number of shares outstanding of Dynegy Inc.’s classes of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 122,135,478 shares outstanding as of May 2, 2011. 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.

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			Page
PART I. FINANCIAL INFORMATION

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

	Condensed Consolidated Balance Sheets—Dynegy Inc.: March 31, 2011 and December 31, 2010		4
	Condensed Consolidated Statements of Operations—Dynegy Inc.: For the three months ended March 31, 2011 and 2010		5
	Condensed Consolidated Statements of Cash Flows—Dynegy Inc.: For the three months ended March 31, 2011 and 2010		6
	Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Inc.: For the three months ended March 31, 2011 and 2010		7
	Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.: March 31, 2011 and December 31, 2010		8
	Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.: For the three months ended March 31, 2011 and 2010		9
	Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.: For the three months ended March 31, 2011 and 2010		10
	Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Holdings Inc.: For the three months ended March 31, 2011 and 2010		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.	36
	Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK - DYNEGY INC. AND DYNEGY HOLDINGS INC.	61
	Item 4.	CONTROLS AND PROCEDURES - DYNEGY INC. AND DYNEGY HOLDINGS INC.	62

PART II. OTHER INFORMATION

	Item 1.	LEGAL PROCEEDINGS - DYNEGY INC. AND DYNEGY HOLDINGS INC.	63
	Item 1A.	RISK FACTORS - DYNEGY INC. AND DYNEGY HOLDINGS INC.	63
	Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS - DYNEGY INC.	63
	Item 6.	EXHIBITS - DYNEGY INC. AND DYNEGY HOLDINGS INC.	64

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, 2011 and constituting nearly 100 percent of Dynegy’s total consolidated asset base as of March 31, 2011. 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.

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DEFINITIONS

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

ASU	Accounting Standards Update
BACT	Best available control technology
BART	Best available retrofit technology
BTA	Best technology available
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAISO	The California Independent System Operator
CAMR	Clean Air Mercury Rule
CARB	California Air Resources Board
CAVR	The Clean Air Visibility Rule
CCR	Coal Combustion Residuals
CERCLA	The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CO2	Carbon Dioxide
CWA	Clean Water Act
DHI	Dynegy Holdings Inc., Dynegy’s primary financing subsidiary
DMSLP	Dynegy Midstream Services L.P.
EBITDA	Earnings before interest, taxes, depreciation and amortization
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles of the United States of America
GEN	Our power generation business
GEN-MW	Our power generation business - Midwest segment
GEN-NE	Our power generation business - Northeast segment
GEN-WE	Our power generation business - West segment
GHG	Greenhouse Gas
HAPs	Hazardous air pollutants, as defined by the Clean Air Act
ICC	Illinois Commerce Commission
IMA	In-market asset availability
ISO	Independent System Operator
ISO-NE	Independent System Operator New England
MACT	Maximum achievable control technology
MGGA	Midwest Greenhouse Gas Accord
MGGRP	Midwestern Greenhouse Gas Reduction Program
MISO	Midwest Independent Transmission System Operator, Inc.
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt hour
NOL	Net operating loss
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NRG	NRG Energy, Inc.
NSPS	New Source Performance Standard
NYISO	New York Independent System Operator
NYSDEC	New York State Department of Environmental Conservation
OAL	Office of Administrative Law
OTC	Over-the-counter
PJM	PJM Interconnection, LLC
PPEA	Plum Point Energy Associates, LLC
PPEA Holding	Plum Point Energy Associates Holding Company, LLC
PSD	Prevention of significant deterioration
RACT	Reasonably available control technology
RCRA	Resource Conservation and Recovery Act
RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must Run
SEC	U.S. Securities and Exchange Commission
SIP	State Implementation Plan
SO2	Sulfur dioxide
SPDES	State Pollutant Discharge Elimination System
VaR	Value at Risk
VIE	Variable Interest Entity
WCI	Western Climate Initiative

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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, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	328		$	291
Restricted cash and investments		911			81
Short-term investments		76			106
Accounts receivable, net of allowance for doubtful accounts of $31 and $32, respectively		179			230
Accounts receivable, affiliates		1			1
Inventory		130			121
Assets from risk-management activities		1,065			1,199
Deferred income taxes		12			12
Broker margin account		110			80
Prepayments and other current assets		118			123
Total Current Assets		2,930			2,244
Property, Plant and Equipment		8,649			8,593
Accumulated depreciation		(2,434	)		(2,320	)
Property, Plant and Equipment, Net		6,215			6,273
Other Assets
Restricted cash and investments		9			859
Assets from risk-management activities		112			72
Intangible assets		129			141
Other long-term assets		424			424
Total Assets	$	9,819		$	10,013

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	128		$	134
Accrued interest		109			36
Accrued liabilities and other current liabilities		88			109
Liabilities from risk-management activities		1,014			1,138
Notes payable and current portion of long-term debt		1,153			148
Total Current Liabilities		2,492			1,565
Long-term debt		3,421			4,426
Long-term debt, affiliates		200			200
Long-Term Debt		3,621			4,626
Other Liabilities
Liabilities from risk-management activities		126			99
Deferred income taxes		584			641
Other long-term liabilities		325			336
Total Liabilities		7,148			7,267
Commitments and Contingencies (Note 9)
Stockholders’ Equity
Common Stock, $0.01 par value, 420,000,000 shares authorized at March 31, 2011 and December 31, 2010; 122,466,663 and 121,687,198 shares issued and outstanding at March 31, 2011 and December 31, 2010, respectively		1			1
Additional paid-in capital		6,068			6,067
Subscriptions receivable		(2	)		(2	)
Accumulated other comprehensive loss, net of tax		(52	)		(53	)
Accumulated deficit		(3,273	)		(3,196	)
Treasury stock, at cost, 727,746 and 628,014 shares at March 31, 2011 and December 31, 2010, respectively		(71	)		(71	)
Total Stockholders’ Equity		2,671			2,746
Total Liabilities and Stockholders’ Equity	$	9,819		$	10,013

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,
	2011			2010
Revenues	$	505		$	858
Cost of sales		(278	)		(308	)
Operating and maintenance expense, exclusive of depreciation and amortization shown separately below		(110	)		(113	)
Depreciation and amortization expense		(126	)		(75	)
General and administrative expenses		(40	)		(31	)

Operating income (loss)		(49	)		331
Losses from unconsolidated investments		—			(34	)
Interest expense		(89	)		(89	)
Other income and expense, net		1			1

Income (loss) from continuing operations before income taxes		(137	)		209
Income tax benefit (expense) (Note 12)		60			(65	)

Income (loss) from continuing operations		(77	)		144
Income from discontinued operations, net of tax (expense) benefit of zero and zero, respectively (Note 2)		—			1

Net income (loss)	$	(77	)	$	145

Earnings (Loss) Per Share (Note 8):
Basic earnings (loss) per share:
Earnings (loss) from continuing operations	$	(0.64	)	$	1.20
Income (loss) from discontinued operations		—			0.01

Basic earnings (loss) per share	$	(0.64	)	$	1.21

Diluted earnings (loss) per share:
Earnings (loss) from continuing operations	$	(0.64	)	$	1.19
Income (loss) from discontinued operations		—			0.01

Diluted earnings (loss) per share	$	(0.64	)	$	1.20

Basic shares outstanding		121			120
Diluted shares outstanding		121			121

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,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(77	)	$	145
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		130			79
Losses from unconsolidated investments, net of cash distributions		—			34
Risk-management activities		(3	)		(253	)
Deferred income taxes		(59	)		62
Other		9			12
Changes in working capital:
Accounts receivable		51			47
Inventory		(9	)		1
Broker margin account		5			310
Prepayments and other assets		8			(12	)
Accounts payable and accrued liabilities		32			31
Changes in non-current assets		(7	)		2
Changes in non-current liabilities		3			—

Net cash provided by operating activities		83			458

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(66	)		(101	)
Maturities of short-term investments		70			—
Purchases of short-term investments		(75	)		(114	)
Decrease (increase) in restricted cash		20			(35	)
Other		4			9

Net cash used in investing activities		(47	)		(241	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from issuance of capital stock		1			—

Net cash provided by financing activities		1			—

Net increase in cash and cash equivalents		37			217
Cash and cash equivalents, beginning of period		291			471

Cash and cash equivalents, end of period	$	328		$	688

Other non-cash investing activity:
Non-cash capital expenditures	$	(8	)	$	9
Non-cash unconsolidated investment	$	—		$	15

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended March 31,
	2011			2010

Net income (loss)	$	(77	)	$	145
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $1 and zero)		1			2

Other comprehensive income, net of tax		1			2

Comprehensive income (loss)	$	(76	)	$	147

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)

	March 31, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	281		$	253
Restricted cash and investments		911			81
Short-term investments		68			90
Accounts receivable, net of allowance for doubtful accounts of $12 and $13, respectively		179			229
Accounts receivable, affiliates		1			1
Inventory		130			121
Assets from risk-management activities		1,065			1,199
Deferred income taxes		4			3
Broker margin account		110			80
Prepayments and other current assets		117			123
Total Current Assets		2,866			2,180
Property, Plant and Equipment		8,649			8,593
Accumulated depreciation		(2,434	)		(2,320	)
Property, Plant and Equipment, Net		6,215			6,273
Other Assets
Restricted cash and investments		9			859
Assets from risk-management activities		112			72
Intangible assets		129			141
Other long-term assets		424			424
Total Assets	$	9,755		$	9,949

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	128		$	134
Accrued interest		109			36
Accrued liabilities and other current liabilities		88			106
Liabilities from risk-management activities		1,014			1,138
Notes payable and current portion of long-term debt		1,153			148
Total Current Liabilities		2,492			1,562
Long-term debt		3,421			4,426
Long-term debt, affiliates		200			200
Long-Term Debt		3,621			4,626
Other Liabilities
Liabilities from risk-management activities		126			99
Deferred income taxes		549			606
Other long-term liabilities		326			337
Total Liabilities		7,114			7,230
Commitments and Contingencies (Note 9)
Stockholder’s Equity
Capital Stock, $1 par value, 1,000 shares authorized at March 31, 2011 and December 31, 2010		—			—
Additional paid-in capital		5,135			5,135
Affiliate receivable		(813	)		(814	)
Accumulated other comprehensive loss, net of tax		(52	)		(53	)
Accumulated deficit		(1,629	)		(1,549	)
Total Stockholder’s Equity		2,641			2,719
Total Liabilities and Stockholder’s Equity	$	9,755		$	9,949

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,
	2011			2010
Revenues	$	505		$	858
Cost of sales		(278	)		(308	)
Operating and maintenance expense, exclusive of depreciation and amortization shown separately below		(110	)		(113	)
Depreciation and amortization expense		(126	)		(75	)
General and administrative expenses		(41	)		(31	)

Operating income (loss)		(50	)		331
Losses from unconsolidated investments		—			(34	)
Interest expense		(89	)		(89	)
Other income and expense, net		1			1

Income (loss) from continuing operations before income taxes		(138	)		209
Income tax benefit (expense) (Note 12)		58			(72	)

Income (loss) from continuing operations		(80	)		137
Income from discontinued operations, net of tax (expense) benefit of zero and zero, respectively (Note 2)		—			1

Net income (loss)	$	(80	)	$	138

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,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(80	)	$	138
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation and amortization		130			79
Losses from unconsolidated investments, net of cash distributions		—			34
Risk-management activities		(3	)		(253	)
Deferred income taxes		(57	)		73
Other		8			11
Changes in working capital:
Accounts receivable		51			47
Inventory		(9	)		1
Broker margin account		5			310
Prepayments and other assets		8			(12	)
Accounts payable and accrued liabilities		34			31
Changes in non-current assets		(7	)		2
Changes in non-current liabilities		3			—

Net cash provided by operating activities		83			461

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(66	)		(101	)
Maturities of short-term investments		56			—
Purchases of short-term investments		(69	)		(114	)
Decrease (increase) in restricted cash		20			(35	)
Affiliate transactions		—			(3	)
Other		4			8

Net cash used in investing activities		(55	)		(245	)

Net increase in cash and cash equivalents		28			216
Cash and cash equivalents, beginning of period		253			419

Cash and cash equivalents, end of period	$	281		$	635

Other non-cash investing activity:
Non-cash capital expenditures	$	(8	)	$	9
Non-cash unconsolidated investment	$	—		$	15

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended March 31,
	2011			2010

Net income (loss)	$	(80	)	$	138
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $1 and zero)		1			2

Other comprehensive income, net of tax		1			2

Comprehensive income (loss)	$	(79	)	$	140

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, 2011 and 2010

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 consolidated financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in Dynegy’s and DHI’s annual reports on Form 10-K for the year ended December 31, 2010, filed on March 8, 2011, 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 consolidated financial statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations 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 deferred 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 variable interest entities (“VIEs”). Actual results could differ materially from our estimates.

Going Concern. Our accompanying unaudited condensed consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these unaudited condensed consolidated financial statements. However, continued low power prices over the past two years have had a significant adverse impact on our business. Further, as our credit rating has declined, counterparty requirements for posting collateral in support of our risk management positions and other contractual obligations have become more stringent. Over the next twelve months, we expect that we will continue to rely on the issuance of letters of credit and/or cash borrowings and/or securing additional sources of capital to continue to meet our operating needs.

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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, 2011 and 2010

The agreements governing our Fifth Amended and Restated Credit Agreement, as amended (the “Credit Facility”), require us to meet specific financial covenants both as a matter of course and as a condition to the incurrence of additional debt and to the making of restricted payments or asset sales, among other things. These specific financial covenants are required to be calculated on a quarterly basis and become more restrictive over the course of the next twelve months. Given the increasingly stringent requirements under our EBITDA to Consolidated Interest Expense covenant over the next twelve months, and considering latest available forward commodity price curves and our current derivative contracts, we project that it is likely that we will not be in compliance with this covenant, as currently set forth in our Credit Facility, beginning in the third or fourth quarter of 2011, and it is virtually certain that we will not be in compliance with this covenant at some point over the next twelve months unless we reach agreement on an amendment to or replacement of the Credit Facility, or obtain a waiver of its terms. Furthermore, we expect that our available liquidity will continue to be reduced as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA, as defined in our Credit Facility. To continue as a going concern over the next twelve months, we must in the near-term (i) meet the financial covenants so that we can access our Credit Facility, (ii) amend or replace our Credit Facility or obtain a waiver of certain of its requirements, or (iii) otherwise secure additional capital. Further, our Credit Facility includes a revolving credit facility which had undrawn capacity of $649 million at March 31, 2011, and expires by its terms on April 2, 2012. Even if we are able to meet the financial covenants included in our Credit Facility in the near-term, we will be required to amend or replace the Credit Facility or otherwise secure additional capital upon the expiration of this revolving facility. We are currently discussing with lenders the terms upon which an amendment to the Credit Facility or a new credit facility could be implemented. We expect the capacity of any amended or new credit facility to be less than the current capacity of $1 billion and to be at a higher cost.

At March 31, 2011, we have the following obligations outstanding under the Credit Facility:

●

$68 million due April 2013 under the Term Loan B (as defined in Note 18—Debt—Credit Facility in the Form 10-K);

●

$850 million due April 2013 under the Term Facility (as defined in Note 18—Debt—Credit Facility in the Form 10-K) (fully collateralized by $850 million of current restricted cash); and

●

$439 million in issued letters of credit.

A failure by us to comply with our financial covenants or to comply with the other restrictions in our Credit Facility could result in reduced borrowing capacity or even a default, causing our debt obligations under such financing agreements, and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, to potentially become immediately due and payable. We could avoid a default under the Credit Facility if we were to repay the amounts owed and cash collateralize the related letters of credit. However, this course of action would not alleviate the going concern and liquidity issues that we are facing over the next twelve months. If we are unable to cure any such default, or obtain a waiver or a replacement financing, and those lenders accelerate the payment of such indebtedness, in the case that we are unable to repay those amounts, the holders of the indebtedness under our secured debt obligations would be entitled to initiate foreclosure actions designed to acquire control of substantially all of our assets. The success of any such actions which would have a material adverse impact on our financial condition, results of operations and cash flows.

We may also seek additional sources of liquidity in order to ensure that we have sufficient cash available to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. The Finance and Restructuring Committee of Dynegy’s Board of Directors has retained professional advisers in connection with potential debt restructuring activities, and we have begun work on this initiative. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans.

Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to achieve the operating results necessary to comply with the covenants in our existing Credit Facility, amend or replace our existing Credit Facility, or achieve the operating results necessary to comply with the covenants in any amended or new credit facility. Such compliance will be dependent on our ability to successfully execute our commercial strategies, manage our collateral requirements, and continue to execute the company-wide cost reduction initiatives that are ongoing. The accompanying unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the foregoing uncertainties, although certain of our obligations have been reclassified to current liabilities in recognition of the uncertainties. Please read Note 10—Debt for further information.

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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, 2011 and 2010

Note 2—Dispositions and Discontinued Operations

Dispositions

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

	GEN-MW		GEN-WE		Total
	(in millions)

Three Months Ended March 31, 2010
Revenues	$	—	$	—	$	—
Income from operations before taxes		—		1		1
Income from operations after taxes		—		1		1

Note 3—Investments

The amortized cost basis, unrealized gains and losses and fair values of investments in available for sale investments is shown in the tables below:

	Investments as of March 31, 2011
	Cost Basis		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(in millions)
Available for Sale investments:
Commercial Paper	$	27	$	—	$	—	$	27
Certificates of Deposit		10		—		—		10
Corporate Securities		—		—		—		—
U.S. Treasury and Government Securities (1)		151		—		—		151

Total—DHI	$	188	$	—	$	—	$	188
Commercial Paper		2		—		—		2
Certificates of Deposit		6		—		—		6
Corporate Securities		—		—		—		—
Total—Dynegy	$	196	$	—	$	—	$	196

(1)

Includes $120 million in Broker margin account on our unaudited condensed consolidated balance sheets in support of transactions with our futures clearing manager.

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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, 2011 and 2010

	Investments as of December 31, 2010
	Cost Basis		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(in millions)
Available for Sale investments:
Commercial Paper	$	41	$	—	$	—	$	41
Certificates of Deposit		12		—		—		12
Corporate Securities		2		—		—		2
U.S. Treasury and Government Securities (1)		120		—		—		120

Total—DHI	$	175	$	—	$	—	$	175
Commercial Paper		4		—		—		4
Certificates of Deposit		8		—		—		8
Corporate Securities		4		—		—		4

Total—Dynegy	$	191	$	—	$	—	$	191

(1)

Includes $85 million in Broker margin account on our consolidated balance sheets in support of transactions with our futures clearing manager.

During the three months ended March 31, 2011, we received proceeds of less than $1 million from the sale of available for sale securities.

Note 4—Risk Management Activities, Derivatives and Financial Instruments

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

Our commodity risk management strategy gives us the flexibility to sell energy and capacity through a combination of spot market sales and near-term contractual arrangements (generally over a rolling 1 to 3 year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term. Our increasing collateral requirements and liquidity position as discussed in Note 1—Accounting Policies—Going Concern, could impact our ability to effectively employ our risk management strategy. Many of our contractual arrangements are derivative instruments and must be accounted for at fair value. We also manage commodity price risk by entering into capacity forward sales arrangements, tolling arrangements, RMR contracts, fixed price coal purchases and other arrangements that do not receive fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase normal sales”. As a result, the gains and losses with respect to these arrangements are not reflected in the unaudited condensed consolidated statements of operations until the settlement dates.

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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, 2011 and 2010

Quantitative Disclosures Related to Financial Instruments and Derivatives

The following disclosures and tables present information concerning the impact of derivative instruments on our unaudited condensed consolidated balance sheets and statements of operations. In the table below, commodity contracts primarily consist of derivative contracts related to our power generation business that we have not designated as accounting hedges, that are entered into for purposes of economically hedging future fuel requirements and sales commitments and securing commodity prices. Interest rate contracts primarily consist of derivative contracts related to managing our interest rate risk. As of March 31, 2011, 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, 2011, we had net long/(short) commodity derivative contracts outstanding and notional interest rate swaps outstanding in the following quantities:

Contract Type	Hedge Designation	Quantity			Unit of Measure	Net Fair Value
		(in millions)				(in millions)
Commodity contracts:
Electric energy (1)	Not designated		(51	)	MW	$	215
Natural gas (1)	Not designated		140		MMBtu	$	(160	)
Heat rate derivatives	Not designated		(5)/50		MW/MMBtu	$	(26	)
Other (2)	Not designated		2		Misc.	$	8

Interest rate contracts:
Interest rate swaps	Fair value hedge		(25	)	Dollars	$	1
Interest rate swaps	Not designated		231		Dollars	$	(6	)
Interest rate swaps	Not designated		(206	)	Dollars	$	5

(1)

Mainly comprised of swaps, options and physical forwards.

(2)

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

Derivatives on the Balance Sheet. We execute a significant volume of transactions through a futures clearing manager. Our daily cash payments (receipts) to (from) our futures clearing manager consist of three parts: (i) fair value of open positions (exclusive of options) (“Daily Cash Settlements”); (ii) initial margin requirements related to open positions (exclusive of options) (“Initial Margin”); and (iii) fair value and margin requirements related to options (“Options”, and collectively with Initial Margin, “Collateral”). We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we do not elect to offset the fair value amounts recognized for the Daily Cash Settlements paid or 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 related Daily Cash Settlements and Collateral, as applicable, on a gross basis. As of March 31, 2011, of the approximately $110 million included in the Broker margin account on our unaudited condensed consolidated balance sheets, approximately $114 million represents Collateral offset by approximately $11 million representing Daily Cash Settlements due to the broker. As of December 31, 2010, of the approximately $80 million included in the Broker margin account on our unaudited condensed consolidated balance sheets, approximately $75 million represented Collateral and approximately $5 million represented Daily Cash Settlements due to the broker.

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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, 2011 and 2010

The following table presents the fair value and balance sheet classification of derivatives in the unaudited condensed consolidated balance sheet as of March 31, 2011, and December 31, 2010 segregated between designated, qualifying hedging instruments and those that are not, and by type of contract segregated by assets and liabilities.

Contract Type	Balance Sheet Location	March 31, 2011			December 31, 2010
		(in millions)
Derivatives designated as hedging instruments:
Derivative Assets:
Interest rate contracts	Assets from risk management activities	$	1		$	1

Total derivatives designated as hedging instruments			1			1

Derivatives not designated as hedging instruments:
Derivative Assets:
Commodity contracts	Assets from risk management activities		1,171			1,265
Interest rate contracts	Assets from risk management activities		5			5
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities		(1,134	)		(1,231	)
Interest rate contracts	Liabilities from risk management activities		(6	)		(6	)

Total derivatives not designated as hedging instruments			36			33

Total derivatives, net		$	37		$	34

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, 2011 and 2010 segregated between designated, qualifying hedging instruments and those that are not, by type of contract.

Cash Flow Hedges. We may 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. We had no cash flow hedges in place during the three months ended March 31, 2011 and 2010.

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. These hedges and the corresponding hedged debt matured April 1, 2011. During the three months ended March 31, 2011 and 2010, 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, 2011 and 2010, there were no gains or losses related to the recognition of firm commitments that no longer qualified as fair value hedges.

The impact of interest rate swap contracts designated as fair value hedges and the related hedged item on our unaudited condensed consolidated statement of operations for the three months ended March 31, 2011 and 2010 was immaterial.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Financial Instruments Not Designated as Hedges. We elect not to designate derivatives related to our power generation business and certain interest rate instruments as cash flow or fair value hedges. Thus, we account for changes in the fair value of these derivatives within the consolidated statements of operations (herein referred to as “mark-to-market accounting treatment”). As a result, these mark-to-market gains and losses are not reflected in the unaudited condensed consolidated statements of operations in the same period as the underlying activity for which the derivative instruments serve as economic hedges.

For the three-month period ended March 31, 2011, our revenues included approximately $2 million of mark-to-market gains related to this activity compared to $253 million of mark-to-market gains in the same period in the prior year.

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the three months ended March 31, 2011 and 2010 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross profit we expect to realize when the underlying physical transactions settle.

Derivatives Not Designated as Hedging Instruments	Location of Gain Recognized in Income on Derivatives	Amount of Gain Recognized in Income on Derivatives for the Three Months Ended March 31,
Derivatives Not Designated as Hedging Instruments	Location of Gain Recognized in Income on Derivatives		2011		2010
		(in millions)
Commodity contracts	Revenues	$	19	$	325

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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, 2011 and 2010

Note 5—Fair Value Measurements

The following tables set 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, 2011 and December 31, 2010. 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, 2011
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—	$	463		$	67		$	530
Natural gas derivatives		—		580			5			585
Other derivatives		—		56			—			56
Total assets from commodity risk management activities	$	—	$	1,099		$	72		$	1,171
Assets from interest rate swaps		—		6			—			6
Short-term investments:
Commercial paper		—		27			—			27
Certificates of deposit		—		10			—			10
U.S. Treasury and government securities (1)		—		151			—			151
Total—DHI short-term investments	$	—	$	188		$	—		$	188

Total—DHI		—		1,293			72			1,365
Short-term investments:
Commercial paper		—		2			—			2
Certificates of deposit		—		6			—			6
Total—Dynegy	$	—	$	1,301		$	72		$	1,373

Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(296	)	$	(19	)	$	(315	)
Natural gas derivatives		—		(745	)		—			(745	)
Heat rate derivatives		—		—			(26	)		(26	)
Other derivatives		—		(48	)		—			(48	)
Total liabilities from commodity risk management activities	$	—	$	(1,089	)	$	(45	)	$	(1,134	)
Liabilities from interest rate swaps		—		(6	)		—			(6	)

Total	$	—	$	(1,095	)	$	(45	)	$	(1,140	)

(1)	Includes $120 million in Broker margin account on our consolidated balance sheets in support of transactions with our futures clearing manager.

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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, 2011 and 2010

	Fair Value as of December 31, 2010
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—	$	526		$	77		$	603
Natural gas derivatives		—		613			5			618
Other derivatives		—		44			—			44
Total assets from commodity risk management activities	$	—	$	1,183		$	82		$	1,265
Assets from interest rate swaps		—		6			—			6
Short-term investments:
Commercial paper		—		41			—			41
Certificates of deposit		—		12			—			12
Corporate securities		—		2			—			2
U.S. Treasury and government securities (1)		—		120			—			120
Total—DHI short-term investments	$	—	$	175		$	—		$	175

Total—DHI		—		1,364			82			1,446
Short-term investments:
Commercial paper		—		4			—			4
Certificates of deposit		—		8			—			8
Corporate securities		—		4			—			4
Total—Dynegy	$	—	$	1,380		$	82		$	1,462

Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(311	)	$	(28	)	$	(339	)
Natural gas derivatives		—		(825	)		—			(825	)
Heat rate derivatives		—		—			(31	)		(31	)
Other derivatives		—		(36	)		—			(36	)
Total liabilities from commodity risk management activities	$	—	$	(1,172	)	$	(59	)	$	(1,231	)
Liabilities from interest rate swaps		—		(6	)		—			(6	)

Total	$	—	$	(1,178	)	$	(59	)	$	(1,237	)

(1)	Includes $85 million in Broker margin account on our consolidated balance sheets in support of transactions with our futures clearing manager.

We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. For example, assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts. Some exchange-traded derivatives are valued using broker or dealer quotations, or market transactions in either the listed or OTC markets. In such cases, these exchange-traded derivatives are classified within Level 2. OTC derivative trading instruments include swaps, forwards, options and complex structures that are valued at fair value. In certain instances, these instruments may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Certain OTC derivatives trade in less active markets with a lower availability of pricing information. In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3. We have consistently used this valuation technique for all periods presented. Please read Note 2—Summary of Significant Accounting Policies—Fair Value Measurements in our Form 10-K 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, 2011 and 2010

The following tables set 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, 2011
	Electricity Derivatives			Natural Gas Derivatives		Heat Rate Derivatives			Total
	(in millions)
Balance at December 31, 2010	$	49		$	5	$	(31	)	$	23
Total gains included in earnings		4			—		1			5
Settlements		(5	)		—		4			(1	)

Balance at March 31, 2011	$	48		$	5	$	(26	)	$	27

Unrealized gains relating to instruments still held as of March 31, 2011	$	7		$	1	$	2		$	10

	Three Months Ended March 31, 2010
	Electricity Derivatives			Natural Gas Derivatives		Heat Rate Derivatives			Interest Rate Swaps			Total
	(in millions)
Balance at December 31, 2009	$	6		$	5	$	17		$	(50	)	$	(22	)
Deconsolidation of Plum Point		—			—		—			50			50
Total gains included in earnings		78			—		17			—			95
Purchases, sales and settlements:
Purchases		1			—		1			—			2
Sales		(10	)		—		—			—			(10	)
Settlements		(5	)		—		(15	)		—			(20	)

Balance at March 31, 2010	$	70		$	5	$	20		$	—		$	95

Unrealized gains relating to instruments held as of March 31, 2010	$	73		$	—	$	13		$	—		$	86

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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, 2011 and 2010

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. We did not have any transfers between Level 1, Level 2 and Level 3 for the three months ended March 31, 2011 and 2010.

Nonfinancial Assets and Liabilities. 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. 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, 2010
	Level 1		Level 2		Level 3		Total		Total Losses
	(in millions)

Equity method investment	$	—	$	—	$	—	$	—	$	(37	)

Total	$	—	$	—	$	—	$	—	$	(37	)

On January 1, 2010, we recorded an impairment of our investment in PPEA Holding as part of our cumulative effect of a change in accounting principle. We determined the fair value of our investment using assumptions that reflect our best estimate of third party market participants’ considerations based on the facts and circumstances related to our investment at that time. The fair value of our investment on January 1, 2010 was considered a Level 3 measurement as the fair value was determined based on probability weighted cash flows resulting from various alternative scenarios including no change in the financing structure, a restructuring of the project debt and insolvency. These scenarios and the related probability weighting are consistent with the scenarios used at December 31, 2009 in our long-lived asset impairment analysis. At March 31, 2010, we fully impaired our investment in PPEA Holding due to the uncertainty and risk surrounding PPEA’s financing structure. Please read Note 7—Impairment and Restructuring Charges—2010 Impairment Charges—Other in our Form 10-K.

Fair Value of Financial Instruments. We have determined the estimated fair-value amounts using available market information and selected valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies could have a material effect on the estimated fair-value amounts.

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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, 2011 and 2010

The carrying values of financial assets and liabilities (cash, accounts receivable, short-term investments and accounts payable) not presented in the table below approximate fair values due to the short-term maturities of these instruments. The fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes for the periods ending March 31, 2011 and December 31, 2010, respectively.

	March 31, 2011						December 31, 2010
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(in millions)
Interest rate derivatives designated as fair value accounting hedges (1)	$	1		$	1		$	1		$	1
Interest rate derivatives not designated as accounting hedges (1)		(1	)		(1	)		(1	)		(1	)
Commodity-based derivative contracts not designated as accounting hedges (1)		37			37			34			34
Term Loan B, due 2013		68			67			68			67
Term Facility, floating rate due 2013		850			842			850			845
Senior Notes and Debentures:
6.875 percent due 2011 (2)		80			79			80			79
8.75 percent due 2012		89			88			89			87
7.5 percent due 2015 (3)		769			651			768			592
8.375 percent due 2016 (4)		1,043			874			1,043			777
7.125 percent due 2018		172			128			172			116
7.75 percent due 2019		1,100			850			1,100			728
7.625 percent due 2026		171			122			171			107
Subordinated Debentures payable to affiliates, 8.316 percent, due 2027		200			102			200			83
Sithe Senior Notes, 9.0 percent due 2013 (5)		232			229			233			233
Other—DHI (6)		188			188			175			175
Other—Dynegy (7)		8			8			16			16

(1)

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

(2)

Payment in full was made on April 1, 2011, which was the maturity date of this debt.

(3)

Includes unamortized discounts of $16 million and $17 million at March 31, 2011 and December 31, 2010, respectively.

(4)

Includes unamortized discounts of $4 million and $4 million at March 31, 2011 and December 31, 2010, respectively.

(5)

Includes unamortized premiums of $7 million and $8 million at March 31, 2011 and December 31, 2010, respectively.

(6)

Other represents short-term investments, including $120 million and $85 million of short-term investments included in the Broker margin account at March 31, 2011 and December 31, 2010, respectively.

(7)

Other represents short-term investments at March 31, 2011 and December 31, 2010.

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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, 2011 and 2010

Note 6—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, 2011			December 31, 2010
	(in millions)
Cash flow hedging activities, net	$	3		$	3
Unrecognized prior service cost and actuarial loss, net		(55	)		(56	)

Accumulated other comprehensive loss, net of tax	$	(52	)	$	(53	)

Note 7—Variable Interest Entities

PPEA Holding Company, LLC. Until the sale of our interest on November 10, 2010, we owned an approximate 37 percent interest in PPEA Holding, which through PPEA, its wholly-owned subsidiary, owns an approximate 57 percent undivided interest in the Plum Point Project. On November 10, 2010, we completed the sale of our interest in PPEA Holding to one of the other investors in PPEA Holding. Please read Note 7—Impairment and Restructuring Charges—2010 Impairment Charges—Other in our Form 10-K.

Due to the uncertainty and risk surrounding PPEA’s financing structure as a result of events that occurred in 2010, we concluded that there was an other-than-temporary impairment of our investment in PPEA Holding and fully impaired our equity investment at March 31, 2010. As a result, we recorded an impairment charge of approximately $37 million for the three months ended March 31, 2010, which is included in Losses from unconsolidated investments in our unaudited condensed consolidated statements of operations. The impairment is a Level 3 non-recurring fair value measurement and reflected our best estimate of third party market participants’ considerations including probabilities related to restructuring of the project debt and potential insolvency. Please read Note 5—Fair Value Measurements for further discussion.

Summarized aggregate financial information for unconsolidated equity investments and our equity share thereof was:

	Three Months Ended March 31, 2010
	Total			Equity Share
	(in millions)
Revenues	$	—		$	—
Operating income		(1	)		—
Net income		9			3

Losses from unconsolidated investments for the three months ended March 31, 2010 were $34 million, which includes an impairment loss of $37 million, discussed above. This impairment was partially offset by equity earnings of $3 million, comprised primarily of mark-to-market gains related to PPEA’s interest rate swaps, partly offset by financing expenses.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Note 8—Dynegy’s Earnings (Loss) Per Share

Basic earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy common stock outstanding during the period. Diluted earnings (loss) per share represents the amount of earnings (losses) for the period available to each share of Dynegy common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period. Basic and diluted shares outstanding for all periods presented have been calculated to reflect the 1-for-5 reverse stock split effected May 25, 2010. Please read Note 23—Capital Stock in our Form 10-K for further discussion.

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

	Three Months Ended March 31,
	2011			2010
	(in millions, except per share amounts)
Income (loss) from continuing operations for basic and diluted earnings (loss) per share	$	(77	)	$	144

Basic weighted-average shares		121			120
Effect of dilutive securities:
Stock options and restricted stock		—			1
Diluted weighted-average shares		121			121

Earnings (loss) per share from continuing operations:
Basic	$	(0.64	)	$	1.20

Diluted (1)	$	(0.64	)	$	1.19

(1)

Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per-share amounts. Accordingly, Dynegy Inc. has utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2011.

Note 9—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. We record reserves for contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. In addition, we disclose matters for which management believes a material loss is at least reasonably possible. In all instances, management has assessed the matters below based on current information and made a judgment concerning their potential outcome, giving due consideration to the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may prove materially inaccurate and such judgment is made subject to the known uncertainty of litigation.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Stockholder Litigation Relating to the Blackstone and Icahn Merger Agreements. In connection with the merger agreement with an affiliate of The Blackstone Group L.P. (as amended, the “Blackstone Merger Agreement”) and the merger agreement with an affiliate of Icahn Enterprises L.P. (as amended, the “Icahn Merger Agreement” and, together with the Blackstone Merger Agreement, the “Merger Agreements”), numerous stockholder lawsuits were filed in the District Courts of Harris County, Texas, the Southern District of Texas, and the Court of Chancery of the State of Delaware. The cases in these three jurisdictions were ultimately consolidated into one action in each jurisdiction (the “Consolidated Texas State Court Action,” the “Consolidated Texas Federal Action,” and the “Consolidated Delaware Chancery Court Action”). One stockholder derivative lawsuit was filed in a District Court in Harris County, Texas.

On November 7, 2010, during the pendency of the Blackstone transaction, the parties entered into a memorandum of understanding providing for the full and final settlement of the Texas state stockholder class actions and the Delaware actions. The memorandum of understanding and settlement were expressly subject to and conditioned upon the consummation of the transactions contemplated by the Blackstone Merger Agreement. Accordingly, when the Blackstone Merger Agreement was terminated, the settlement became null and void. Thereafter, the motion by the plaintiff in the stockholder derivative action to nonsuit all defendants without prejudice was granted on December 14, 2010.

Following the termination of the Icahn Merger Agreement and upon Dynegy’s insistence, the plaintiffs in the Consolidated Texas Federal Action and Consolidated Delaware Chancery Court Action moved to dismiss their claims without prejudice. The courts dismissed the cases on March 1, 2011, and March 16, 2011, respectively. On March 28, 2011, plaintiff’s counsel in the Consolidated Texas State Court Action filed a motion seeking attorneys’ fees and expenses in the amount of approximately $1.6 million for their efforts in representing plaintiff. Dynegy is vigorously opposing this motion.

Gas Index Pricing Litigation. We, several of our affiliates, our former joint venture affiliate and other energy companies were 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 various index publications in the 2000-2002 timeframe. Many of the cases have been resolved and those which remain are pending in Nevada federal district court. Recent developments include:

●

In February 2007, the Tennessee state court dismissed a class action on defendants’ motion. Plaintiffs appealed and, in October 2008, the appellate court reversed the dismissal. Thereafter, defendants appealed to the Tennessee Supreme Court which, in April 2010, reversed the appellate court ruling and dismissed all of plaintiffs’ claims. Plaintiffs’ deadline to appeal to the United States Supreme Court has expired.

●

In February 2008, the United States District Court in Las Vegas, Nevada granted defendants’ motion for summary judgment in a Colorado class action and, ultimately, dismissed the case and all of plaintiffs’ claims. The decision is subject to appeal once the remaining defendants’ claims are adjudicated.

●

The remaining five cases, three of which seek class certification, are also pending in Nevada federal court. 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 in four states by providing false information to natural gas index publications. In November 2009, following defendants’ motion for reconsideration, the court invited defendants to renew their motions for summary judgment on preemption of plaintiffs’ state law claims, which were filed shortly thereafter. Plaintiffs concurrently moved to amend their complaints to add federal claims. In October 2010, the court denied plaintiffs’ motion to amend. We await an order on defendants’ motions for summary judgment or further instruction from the court. In the interim, discovery and plaintiffs’ class certification motions are stayed.

We continue to analyze the Gas Index Pricing Litigation and are vigorously defending the remaining individual matters. Due to the uncertainty of litigation, we cannot predict whether we will incur any liability in connection with these lawsuits. We believe these cases lack merit and we will continue to oppose plaintiff’s claims vigorously.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Cooling Water Intake Permits. The cooling water intake structures at several of our power generation facilities are regulated under Section 316(b) of the Clean Water Act. This provision generally provides that standards set for power generation facilities require that the location, design, construction and capacity of cooling water intake structures reflect the BTA for minimizing adverse environmental impact. These standards are developed and implemented for power generating facilities through the NPDES permits or individual SPDES permits on a case-by-case basis.

The environmental groups that participate in our 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 power generation facilities (Danskammer, Roseton and Moss Landing) have been challenged on this basis. The Danskammer SPDES permit, which was renewed and issued in June 2006, does not require installation of a closed cycle cooling system; however, it does require aquatic organism mortality reductions resulting from NYSDEC’s determination of BTA requirements under its regulations. All appeals of this permit have been exhausted. Two permit challenges are still pending.

●

Roseton SPDES Permit — In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton plant. The permit is opposed by environmental groups challenging the BTA determination. In October 2006, various holdings in the administrative law judge’s ruling admitting the environmental group petitioners to party status and setting forth the issues to be adjudicated in the permit renewal hearing were appealed to the Commissioner of NYSDEC by the petitioners, NYSDEC staff and us. The permit renewal hearing will be scheduled after the Commissioner rules on those appeals. We believe that the petitioners’ claims lack merit and we plan to oppose those claims vigorously.

●

Moss Landing NPDES Permit — The California Regional Water Quality Control Board (“Water Board”) issued an NPDES permit for the Moss Landing power generating facility in 2000 that did not require closed cycle cooling. A local environmental group challenged the BTA determination of the permit. The Water Board’s decision was affirmed by the Superior Court in 2004 and by the Court of Appeals in 2007. The Supreme Court of California granted review in March 2008. The petitioner’s brief was filed in December 2009. We filed a motion to dismiss and our responsive brief in March 2010. The petitioner’s reply brief was filed in May 2010. Our motion to dismiss was denied in June 2010. In July 2010, the California Energy Commission filed an application for leave to file a brief in support of our argument challenging the jurisdiction of the Superior Court. In September 2010, four air quality control districts filed an application for leave to file a brief in support of jurisdiction of the Superior Court. Recently, the Supreme Court of California scheduled the matter for oral argument in May 2011. We believe that petitioner’s claims lack merit and we plan to continue to oppose those claims vigorously.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

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 GHG 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 September 2009, the court dismissed all of the plaintiffs’ claims based on lack of subject matter jurisdiction and because plaintiffs lacked standing to bring the suit. Shortly thereafter, plaintiffs appealed to the Ninth Circuit. The appeal is fully briefed and in February 2011, the Ninth Circuit issued an order staying the scheduling of oral argument until at least June 15, 2011, pending the United States Supreme Court’s ruling in Connecticut vs. AEP. We believe the plaintiffs’ suit lacks merit and we will continue to oppose their claims vigorously.

Illinova Generating Company Arbitration. In May 2007, Dynegy’s subsidiary Illinova Generating Company (“IGC”) received an adverse award in an arbitration brought by Ponderosa Pine Energy, LLC (“PPE”). The award required IGC to pay PPE $17 million, which IGC paid in June 2007 under protest while simultaneously seeking to vacate the award in the District Court of Dallas County, Texas. In March 2010, the Dallas District Court vacated the award, finding that one of the arbitrators had exhibited evident partiality. PPE is appealing that decision to the Fifth District Court of Appeals in Dallas, Texas. Coinciding with the appeal, IGC filed a claim against PPE seeking recovery of the $17 million plus interest. In September 2010, the Dallas District Court ordered PPE to deposit the $17 million principal in an interest-bearing escrow account jointly owned by IGC and PPE pending the Dallas Court of Appeals decision, which has not yet been issued. As a result of the uncertainty surrounding the outcome of PPE’s appeal, our receivable from PPE is fully reserved at March 31, 2011.

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

Guarantees and Indemnifications

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. Related to the indemnifications discussed below, we have accrued approximately $2 million as of March 31, 2011.

LS Power Indemnities. In connection with the LS Power Transactions we agreed in the purchase and sale agreement to indemnify LS Power against claims regarding any breaches in our representations and warranties and certain other potential liabilities. Claims for indemnification shall survive until twelve months subsequent to closing with exceptions for tax claims, which shall survive for the applicable statute of limitations plus 30 days, and certain other representations and potential liabilities, which shall survive indefinitely. The indemnifications provided to LS Power are limited to $1.3 billion in total; however, several categories of indemnifications are not available to LS Power until the liabilities incurred in the aggregate are equal to or exceed $15 million and are capped at a maximum of $100 million. Further, the purchase and sale agreement provides in part that we may not reduce or avoid liability for a valid claim based on a claim of contribution. In addition to the above indemnities related to the LS Power Transactions, we have agreed to indemnify LS Power against claims related to the Riverside/Foothills Project for certain aspects of the project. Namely, LS Power has been indemnified for any disputes that arise as to ownership, transfer of bonds related to the project, and any failure by us to obtain approval for the transfer of the payment in-lieu of taxes program already in place. The indemnities related solely to the Riverside/Foothills Project are capped at a maximum of $180 million and extend until the earlier of the expiration of the tax agreement or December 26, 2026. At this time, we have incurred no significant expenses under these indemnities. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—LS Power Transactions in our Form 10-K for further discussion.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

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 indemnification agreement in relevant part 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. At this time, FERC has not acted on remand.

Targa Indemnities. During 2005, as part of our sale of our midstream business (“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 material expense under these prior indemnities. We have recorded an accrual of less than $1 million for remediation of groundwater contamination at the Breckenridge Gas Processing Plant sold by DMSLP in 2001. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million.

Illinois Power Indemnities. 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 absolute 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.

Black Mountain Guarantee. Through one of our subsidiaries, we hold a 50 percent ownership interest in Black Mountain (Nevada Cogeneration) (“Black Mountain”), in which our partner is a Chevron subsidiary. Black Mountain owns the Black Mountain power generation facility and has a power purchase agreement with a third party that extends through April 2023. In connection with the power purchase agreement, pursuant to which Black Mountain receives payments which decrease in amount over time, we agreed to guarantee 50 percent of certain payments that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement. At March 31, 2011, if an event of default due to early termination had occurred under the terms of the mortgage on the facility entered into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $54 million under the guarantee.

Other Indemnities. We entered into indemnifications regarding environmental, tax, employee and other representations when completing asset sales such as, but not limited, to the Rolling Hills, Calcasieu, CoGen Lyondell and Heard County power generating facilities. As of March 31, 2011, no claims have been made against these indemnities. There is no limitation on our liability under certain of these indemnities. However, management is unaware of any existing claims.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Note 10—Debt

Credit Facility. Our Credit Facility, currently consists of a $1.08 billion revolving credit facility, an $850 million term letter of credit facility and a $68 million senior secured term loan facility. The agreements governing this Credit Facility require us to meet specific financial covenants, including an EBITDA to Consolidated Interest Expense covenant, as set forth in our Credit Facility. Compliance is determined when the results from the relevant fiscal quarter are available, and is measured as of the last day of the relevant fiscal quarter using the trailing four quarters of historical financial data. Please read Note 18—Debt in our Form 10-K for further discussion. We are in compliance with our EBITDA to Consolidated Interest Expense covenant as of March 31, 2011. However, given the increasingly stringent requirements under this covenant over the next twelve months, and considering the latest available forward commodity price curves and our current derivative contracts, we project that it is likely that we will not be in compliance with this covenant, as currently set forth in the Credit Facility, beginning in the third or fourth quarter of 2011, and it is virtually certain that we will not be in compliance with this covenant at some point over the next twelve months unless we reach agreement on an amendment to or replacement of the Credit Facility, or obtain a waiver of its terms.

During the first quarter of 2011, our EBITDA to Consolidated Interest Expense ratio has continued to deteriorate. The following table summarizes the required ratio at different periods of time, as well as the actual ratio for the last two twelve month periods:

Period Ended:	Requirement:	Actual:
December 31, 2010	No less than 1.30 : 1	1.668
March 31, 2011	No less than 1.35 : 1	1.423
June 30, 2011	No less than 1.40 : 1	N/A
September 30, 2011	No less than 1.60 : 1	N/A
December 31, 2011	No less than 1.60 : 1	N/A
Thereafter	No less than 1.75 : 1	N/A

As noted above, this ratio has declined over the last three months. Additionally, the most stringent ratio that we will be required to meet within twelve months of the balance sheet date has increased. As a result of the decrease in our actual EBITDA to Consolidated Interest Expense ratio coupled with the increasingly stringent ratio requirements, we have classified the debt outstanding under the Credit Facility and the restricted cash collateralizing this debt as current on our unaudited condensed consolidated balance sheets at March 31, 2011.

A failure by us to comply with our financial covenants or to comply with the other restrictions in our Credit Facility could result in reduced borrowing capacity or even a default, causing our debt obligations under such financing agreements, and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, to potentially become immediately due and payable. We could avoid a default under the Credit Facility if we were to repay the amounts owed and cash collateralize the related letters of credit. However, this course of action would not alleviate the going concern and liquidity issues that we are facing over the next twelve months. If we are unable to cure any such default, or obtain a waiver or a replacement financing, and those lenders accelerate the payment of such indebtedness, in the case that we are unable to repay those amounts, the holders of the indebtedness under our secured debt obligations would be entitled to initiate foreclosure actions designed to acquire control of substantially all of our assets. The success of any such actions would have a material adverse impact on our financial condition, results of operations and cash flows.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Note 11—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully described in Note 24—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,
	2011			2010			2011		2010
	(in millions)
Service cost benefits earned during period	$	3		$	3		$	1	$	1
Interest cost on projected benefit obligation		4			3			1		1
Expected return on plan assets		(4	)		(4	)		—		—
Recognized net actuarial loss		1			1			—		—

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

Contributions. During the three months ended March 31, 2011, we made $2 million in contributions to our pension plans or other postretirement benefit plans. We made $4 million in contributions to our pension plans or other postretirement benefit plans during the three months ended March 31, 2010. We expect to make contributions of approximately $12 million to our pension plans and $2 million to other benefit plans during 2011.

Note 12—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,
	2011			2010
	(in millions, except rates)
Income tax benefit (expense)	$	60		$	(65	)

Effective tax rate		44	%		31	%

For the period ended March 31, 2011, the difference between the effective rate of 44 percent for Dynegy and the statutory rate of 35 percent resulted primarily from the impact of state taxes including a benefit of $9 million related to an increase in state NOLs due to the acceptance of amended returns, which we filed as a result of a change in a tax position, partially offset by an expense of $3 million related to an increase in the Illinois statutory rate. For the period ended March 31, 2010, the difference between the effective rate of 31 percent and the statutory rate of 35 percent was due primarily to a benefit of $16 million related to the release of a reserve for uncertain tax positions upon completion of an audit, partly offset by the impact of state taxes.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

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

	Three Months Ended March 31,
	2011			2010
	(in millions, except rates)
Income tax benefit (expense)	$	58		$	(72	)

Effective tax rate		42	%		34	%

For the period ended March 31, 2011, the difference between the effective rate of 42 percent for DHI and the statutory rate of 35 percent resulted primarily from the impact of state taxes including a benefit of $6 million related to an increase in state NOLs due to the acceptance of amended returns, which we filed as a result of a change in a tax position, partially offset by an expense of $2 million related to an increase in the Illinois statutory rate. For the period ended March 31, 2010, the difference between the effective rate of 34 percent and the statutory rate of 35 percent resulted primarily from a benefit of $11 million related to the release of a reserve for uncertain tax positions upon completion of an audit, partly offset by the impact of state taxes.

Note 13—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, 2011 and 2010 is presented below:

Dynegy’s Segment Data as of and for the Three Months Ended March 31, 2011

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	280		$	62		$	163		$	—		$	505

Total revenues	$	280		$	62		$	163		$	—		$	505

Depreciation and amortization	$	(100	)	$	(17	)	$	(7	)	$	(2	)	$	(126	)

Operating income (loss)	$	(3	)	$	1		$	(5	)	$	(42	)	$	(49	)

Other items, net		—			—			—			1			1
Interest expense														(89	)

Loss from continuing operations before income taxes														(137	)
Income tax benefit														60

Net loss													$	(77	)

Identifiable assets:
Domestic	$	4,970		$	1,828		$	1,670		$	1,351		$	9,819

Total	$	4,970		$	1,828		$	1,670		$	1,351		$	9,819

Capital expenditures	$	(44	)	$	(5	)	$	(17	)	$	—		$	(66	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Dynegy’s Segment Data as of and for the Three Months Ended March 31, 2010

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	486		$	143		$	229		$	—		$	858

Total revenues	$	486		$	143		$	229		$	—		$	858

Depreciation and amortization	$	(50	)	$	(16	)	$	(8	)	$	(1	)	$	(75	)

Operating income (loss)	$	260		$	45		$	60		$	(34	)	$	331

Losses from unconsolidated investments		(34	)		—			—			—			(34	)
Other items, net		—			—			1			—			1
Interest expense														(89	)

Income from continuing operations before income taxes														209
Income tax expense														(65	)

Income from continuing operations														144
Income from discontinued operations, net of taxes														1

Net income													$	145

Identifiable assets:
Domestic	$	5,705		$	2,061		$	2,003		$	1,664		$	11,433
Other		—			—			—			24			24

Total	$	5,705		$	2,061		$	2,003		$	1,688		$	11,457

Capital expenditures	$	(89	)	$	(8	)	$	(3	)	$	(1	)	$	(101	)

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended March 31, 2011 and 2010

Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2011 and 2010 is presented below:

DHI’s Segment Data as of and for the Three Months Ended March 31, 2011

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	280		$	62		$	163		$	—		$	505

Total revenues	$	280		$	62		$	163		$	—		$	505

Depreciation and amortization	$	(100	)	$	(17	)	$	(7	)	$	(2	)	$	(126	)

Operating income (loss)	$	(3	)	$	1		$	(5	)	$	(43	)	$	(50	)

Other items, net		—			—			—			1			1
Interest expense														(89	)

Loss from continuing operations before income taxes														(138	)
Income tax benefit														58
Net loss													$	(80	)

Identifiable assets:
Domestic	$	4,970		$	1,828		$	1,670		$	1,287		$	9,755

Total	$	4,970		$	1,828		$	1,670		$	1,287		$	9,755

Capital expenditures	$	(44	)	$	(5	)	$	(17	)	$	—		$	(66	)

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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, 2011 and 2010

DHI’s Segment Data as of and for the Three Months Ended March 31, 2010

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	486		$	143		$	229		$	—		$	858

Total revenues	$	486		$	143		$	229		$	—		$	858

Depreciation and amortization	$	(50	)	$	(16	)	$	(8	)	$	(1	)	$	(75	)

Operating income (loss)	$	260		$	45		$	60		$	(34	)	$	331

Losses from unconsolidated investments		(34	)		—			—			—			(34	)
Other items, net		—			—			1			—			1
Interest expense														(89	)

Income from continuing operations before income taxes														209
Income tax expense														(72	)

Income from continuing operations														137
Income from discontinued operations, net of taxes														1

Net income													$	138

Identifiable assets:
Domestic	$	5,705		$	2,061		$	2,003		$	1,612		$	11,381
Other		—			—			—			24			24

Total	$	5,705		$	2,061		$	2,003		$	1,636		$	11,405

Capital expenditures	$	(89	)	$	(8	)	$	(3	)	$	(1	)	$	(101	)

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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, 2011 and 2010

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.

The agreements governing our Fifth Amended and Restated Credit Agreement, as amended (the “Credit Facility”), require us to meet specific financial covenants both as a matter of course and as a condition to the incurrence of additional debt and to the making of restricted payments or asset sales, among other things. These specific financial covenants are required to be calculated on a quarterly basis and become more restrictive over the course of the next twelve months. Given the increasingly stringent requirements under our EBITDA to Consolidated Interest Expense covenant over the next twelve months, and considering the latest available forward commodity price curves and our current derivative contracts, we project that it is likely that we will not be in compliance with this covenant, as currently set forth in the Credit Facility, beginning in the third or fourth quarter of 2011, and it is virtually certain that we will not be in compliance with this covenant at some point over the next twelve months unless we reach agreement on an amendment to or replacement of the Credit Facility, or obtain a waiver of its terms. Furthermore, we expect that our available liquidity will continue to be reduced as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA, as defined in our Credit Facility. To continue as a going concern over the next twelve months, we must, in the near-term (i) meet the financial covenants so that we can access our Credit Facility, (ii) amend or replace our Credit Facility or obtain a waiver of certain of its requirements, or (iii) otherwise secure additional capital. Further, our Credit Facility includes a revolving credit facility which had undrawn capacity of $649 million at March 31, 2011, and expires by its terms on April 2, 2012. Even if we are able to meet the financial covenants included in our Credit Facility in the near-term, we will be required to amend or replace the Credit Facility or otherwise secure additional capital upon the expiration of this revolving facility. We are currently discussing with lenders the terms upon which an amendment to the Credit Facility or a new credit facility could be implemented. We expect the capacity of any amended or new credit facility to be less than the current capacity of $1 billion and to be at a higher cost.

At March 31, 2011, we have the following obligations outstanding under the Credit Facility:

●

$68 million due April 2013 under the Term Loan B (as defined in Note 18—Debt—Credit Facility in the Form 10-K);

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●

$850 million due April 2013 under the Term Facility (as defined in Note 18—Debt—Credit Facility in the Form 10-K) (fully collateralized by $850 million of current restricted cash); and

●

$439 million in issued letters of credit.

A failure by us to comply with our financial covenants or to comply with the other restrictions in our Credit Facility could result in reduced borrowing capacity or even a default, causing our debt obligations under such financing agreements, and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, to potentially become immediately due and payable. We could avoid a default under the Credit Facility if we were to repay the amounts owed and cash collateralize the related letters of credit. However, this course of action would not alleviate the going concern and liquidity issues that we are facing over the next twelve months. If we are unable to cure any such default, or obtain a waiver or a replacement financing, and those lenders accelerate the payment of such indebtedness, in the case that we are unable to repay those amounts, the holders of the indebtedness under our secured debt obligations would be entitled to initiate foreclosure actions designed to acquire control of substantially all of our assets. The success of any such actions would have a material adverse impact on our financial condition, results of operations and cash flows.

We may also seek additional sources of liquidity in order to ensure that we have sufficient cash available to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. The Finance and Restructuring Committee of Dynegy’s Board of Directors has retained advisers in connection with potential debt restructuring activities, and we have begun work on this initiative. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans.

Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to achieve the operating results necessary to comply with the covenants in our existing Credit Facility, amend or replace our existing Credit Facility, or achieve the operating results necessary to comply with the covenants in any amended or new credit facility. Such compliance will be dependent on our ability to successfully execute our commercial strategies, manage our collateral requirements, and continue to execute the company-wide cost reduction initiatives that are ongoing. Please read Note 1—Accounting Policies—Going Concern and Note 10—Debt for further information.

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, collateral requirements, fixed capacity payments and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll.

Our primary sources of internal liquidity are cash flows from operations, cash on hand, short-term investments and available capacity under our Credit Facility, of which the revolver capacity of $1,080 million (currently $649 million due to the capacity reductions discussed below) is scheduled to mature in April 2012 and the term letter of credit capacity of $850 million is scheduled to mature in April 2013. However, in light of our expected non-compliance in the next twelve months with certain covenants in the Credit Facility as discussed above, we have classified the Credit Facility obligations and related restricted cash as current as of March 31, 2011. Please read Note 10—Debt for further information.

In the absence of an amendment to or replacement of the Credit Facility, or a waiver of its terms, our cash on hand and short-term investments as of March 31, 2011 and our internally forecasted cash flows for the remainder of 2011, are not expected to be sufficient to fund our remaining planned capital expenditure program for 2011 and our debt service requirements for the year. As discussed above, we are attempting to amend or replace our existing Credit Facility. We are currently discussing with lenders the terms upon which an amendment to the Credit Facility or a new credit facility could be implemented. Please see Note 1—Accounting Policies—Going Concern for further discussion.

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We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. Please read Capital-Structuring Transactions and Asset Dispositions below for more detail. The Finance and Restructuring Committee of Dynegy’s Board of Directors has retained advisers in connection with potential debt restructuring activities, and we have begun work on this initiative. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans.

Please read Note 1—Accounting Policies—Going Concern and Note 10—Debt in this Form 10-Q and the discussion below regarding Revolver Capacity as well as Note 18 Debt—Credit Facility in our Form 10-K for a further discussion of the financial covenants contained in the Credit Facility. For additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see Item 1A—Risk Factors in our Form 10-K.

Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at May 2, 2011, March 31, 2011 and December 31, 2010:

	May 2, 2011			March 31, 2011			December 31, 2010
	(in millions)
Revolver capacity (1) (2)	$	649		$	649			$	954
Borrowings against revolver capacity		—			—				—
Term letter of credit capacity, net of required reserves		825			825				825
Available contingent letter of credit facility capacity (3)		—			—				—
Outstanding letters of credit	(544		)		(439	)			(375	)

Unused capacity	930				1,035				1,404

Cash—DHI	172				281				253
Short-term investments—DHI (4)	21				68				90

Total available liquidity—DHI	1,123				1,384				1,747
Cash—Dynegy	49				47				38
Short-term investments—Dynegy (4)	9				8				16

Total available liquidity—Dynegy	$	1,181		$	1,439			$	1,801

(1)

We currently have a syndicate of lenders participating in the revolving portion of our Credit Facility with commitments ranging from $30 million to $165 million.

(2)

As of May 2, 2011, March 31, 2011, and December 31, 2010, DHI’s available liquidity under the Credit Facility was reduced by $431million, $431 million and $126 million, respectively, as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA. Further reduction in capacity may occur based on our ratio of Secured Debt to EBITDA at June 30, 2011, September 30, 2011 and December 31, 2011. Please see Revolver Capacity below for further discussion.

(3)

Under the terms of the Contingent LC Facility, up to $150 million of capacity can become available, contingent on changes in forward spark spreads and power prices for 2012.

(4)

We invest our available cash balances in certain investments permitted by our internal policies and external financing agreements. Please read Note 3—Investments for further discussion.

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Cash on Hand. At May 2, 2011 and March 31, 2011, Dynegy had cash on hand of $221 million and $328 million, respectively, as compared to $291 million at December 31, 2010. The decrease in cash on hand at May 2, 2011 as compared to March 31, 2011 is primarily due to the payment of debt that matured on April 1, 2011 of $80 million and interest payments on our debt of $56 million partially offset by maturities of short-term investments of $49 million. The increase in cash on hand at March 31, 2011 as compared to the end of 2010 is primarily attributable to the expiration of a security and deposit agreement and the subsequent release of $50 million of restricted cash.

At May 2, 2011 and March 31, 2011, DHI had cash on hand of $172 million and $281 million, respectively, as compared to $253 million at December 31, 2010. The decrease in cash on hand at May 2, 2011 as compared to March 31, 2011 is primarily due to the payment of debt that matured on April 1, 2011 of $80 million and interest payments on our debt of $56 million partially offset by maturities of short-term investments of $47 million. The increase in cash on hand at March 31, 2011 as compared to the end of 2010 is primarily attributable to the expiration of a security and deposit agreement and the subsequent release of $50 million of restricted cash.

Revolver Capacity. DHI’s available liquidity under the Credit Facility was reduced by $431 million and $126 million as of March 31, 2011 and December 31, 2010, respectively, as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA (as defined in our Credit Facility). The effect of reduced availability under the Credit Facility is less available liquidity to DHI. Further reductions in capacity are likely to occur at June 30, 2011, September 30, 2011 and December 31, 2011. Given the increasingly stringent requirements under this covenant over the next twelve months, and considering the latest available forward commodity price curves and our current derivative contracts, we project that it is likely that we will not be in compliance with our EBITDA to Consolidated Interest Expense covenant, as currently set forth in our Credit Facility, beginning in the third or fourth quarter of 2011, and it is virtually certain that we will not be in compliance with this covenant at some point over the next twelve months unless we reach agreement on an amendment to or replacement of the Credit Facility, or obtain a waiver of its terms. In such event, the Credit Facility may be terminated by the lenders and outstanding amounts thereunder accelerated. Accordingly, we are currently discussing with lenders an amendment to or the replacement of our existing Credit Facility. We expect the capacity of any amended or new credit facility to be less than the current capacity of $1 billion and to be at a higher cost. Please read Note 1—Accounting Policies—Going Concern and Note 10—Debt in this Form 10-Q for further discussion of our Credit Facility.

Capital-Structuring Transactions. We may seek additional sources of liquidity in order to ensure that we have sufficient cash available to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. Matters to be considered include depressed prices for assets, cash interest expense, covenant compliance and maturity profile, all to be balanced with the need to maintain adequate liquidity. 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, the going concern emphasis paragraph in our most recent audit report, recent changes to our senior management and Dynegy’s Board of Directors, our non-investment grade credit ratings, significant debt maturities, business prospects and other factors beyond our control, including current and projected market conditions. Any issuance of equity by Dynegy likely would have other effects as well, including stockholder dilution, and our ability to issue debt securities may be limited by our financing agreements.

Operating Activities

Historical Operating Cash Flows. Dynegy’s and DHI’s cash flow provided by operations totaled $83 million for the three months ended March 31, 2011. During the period, our power generation business provided positive cash flow from operations of $167 million from the operation of our power generation facilities. Corporate and other operations included a use of approximately $84 million in cash by Dynegy and DHI primarily due to interest payments to service debt and general and administrative expenses.

Dynegy’s cash flow provided by operations totaled $458 million for the three months ended March 31, 2010. DHI’s cash flow provided by operations totaled $461 million for the three months ended March 31, 2010. During the period, our power generation business provided positive cash flow from operations of $537 million from the operation of our power generation facilities due primarily to cash received for changes in value of our positions with a futures clearing manager. Corporate and other operations included a use of approximately $79 million and $76 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.

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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 power, the price of natural gas and its correlation to power prices, the cost of coal and fuel oil, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, our ability to achieve the cost savings contemplated in our cost reduction programs and the level of our ability to capture value associated with commodity price volatility. Given current forward commodity price curves, our future operating cash flows are likely to be insufficient to fund our planned capital expenditure program and our debt service requirements.

Collateral Postings. We use a significant portion of our capital resources, in the form of cash, short-term investments 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. At March 31, 2011, we had approximately $92 million of our cash collateral postings and $72 million of our letter of credit collateral postings related to our hedging activities. The following table summarizes our consolidated collateral postings to third parties by line of business at May 2, 2011, March 31, 2011 and December 31, 2010:

		May 2, 2011		March 31, 2011		December 31, 2010
	(in millions)
By Business:
Generation business		$	483	$	470	$	377
Other			173		87		85

Total		$	656	$	557	$	462
By Type:
Cash and marketable securities (1)		$	112	$	118	$	87
Letters of credit			544		439		375

Total		$	656	$	557	$	462

(1)

Includes Broker margin account on our consolidated balance sheets as well as other collateral postings included in Prepayments and other current assets on our consolidated balance sheets.

The change in letters of credit postings from December 31, 2010 to March 31, 2011 is primarily due to higher initial margin posting requirements and reduction in usage of bilateral first lien collateral arrangements. Collateral posting increased from March 31, 2011 to May 2, 2011 primarily due to contractual obligations under certain operational agreements.

In addition to cash and letters of credit posted as collateral, we have granted additional permitted first priority liens on the assets currently subject to first priority liens under our Credit Facility as collateral under certain of our commodity derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. At their discretion, the counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under the Credit Facility. The fair value of our commodity derivatives collateralized by first priority liens, netted by counterparty, included liabilities of $8 million, $15 million and $30 million at May 2, 2011, March 31, 2011 and December 31, 2010, respectively. We do not expect to use first lien arrangements for a significant portion of our collateral requirements going forward.

We expect counterparties’ future 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. If we do not have access to our Credit Facility or another borrowing facility, it will be difficult for us to satisfy counterparties’ collateral demands, including those for which no collateral is currently posted. For further discussion, see Going Concern above. Furthermore, our ability to use forward economic hedging instruments could be limited, due to the collateral requirements the use of such instruments entails. If our commercial strategy is adjusted to reduce such collateral needs, we would be exposed to future increases and decreases in commodity prices and be limited in our ability to capture the extrinsic value associated with our portfolio of assets.

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Investing Activities

Capital Expenditures. We continue to tightly manage our operating costs and capital expenditures. We had approximately $66 million and $101 million in capital expenditures during the three months ended March 31, 2011 and 2010, respectively. Our capital spending by reportable segment was as follows:

	For the Three Months Ended
	March 31,
	2011		2010
	(in millions)
GEN-MW	$	44	$	89
GEN-WE		5		8
GEN-NE		17		3
Other		—		1

Total	$	66	$	101

Capital spending in our GEN-MW segment primarily consisted of environmental and maintenance capital projects. Capital spending in our GEN-WE and GEN-NE segments primarily consisted of maintenance projects.

Asset Dispositions. Consistent with industry practice, we regularly evaluate our generation fleet based primarily on geographic location, fuel supply, market structure, market recovery expectations, regulatory or legislative risks and cash flows. We consider divestitures of assets where the balance of the above factors suggests that such assets’ earnings potential is limited or that the benefits that can be captured through a divestiture outweigh the benefits of continuing to own and operate such assets. As future operating cash flows are likely to be insufficient to fund our planned capital expenditure program, lease obligations and our debt service requirements, additional asset divestures will be considered to supplement our liquidity position, potentially at terms not favorable to us.

Other Investing Activities. Cash outflow related to purchases of short-term investments during the three months ended March 31, 2011 totaled $75 million and $69 million for Dynegy and DHI, respectively. Cash inflow related to maturities of short-term investments for the three months ended March 31, 2011 were $70 million and $56 million for Dynegy and DHI, respectively. There was a $20 million cash inflow related to restricted cash balances during the three months ended March 31, 2011 due to a release of $50 million related to the expiration of a security and deposit agreement offset by an increase of $30 million in the restricted cash balance related to the Sithe senior notes. Other included $4 million of insurance proceeds.

Cash outflow related to purchases of short-term investments during the three months ended March 31, 2010 totaled $114 million for both Dynegy and DHI. Cash inflow related to distributions from short-term investments for the three months ended March 31, 2010 were $9 million and $8 million for Dynegy and DHI, respectively. There was a $35 million cash outflow related to restricted cash balances during the three months ended March 31, 2010 due to an increase in the restricted cash balance related to the Sithe senior notes. Other included $9 million and $8 million related to distribution of an investment for Dynegy and DHI, respectively.

Financing Activities

Historical Cash Flow from Financing Activities. Dynegy’s cash flow provided by financing activities totaled $1 million for the three months ended March 31, 2011 due to proceeds from stock option exercises. DHI had no financing activities during the three months ended March 31, 2011.

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 the violation of financial covenants, including the Interest Coverage Ratio discussed below (and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions), insolvency events, defaults on scheduled principal or interest payments, acceleration of other financial obligations and change of control provisions. We do not have any trigger events tied to specified Dynegy or DHI credit ratings or Dynegy’s stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.

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Financial Covenants. Our Credit Facility contains certain financial covenants, including (i) a covenant (measured as of the last day of the relevant fiscal quarter using the trailing four quarters of historical financial data) that requires DHI and certain of its subsidiaries to maintain a ratio of Secured Debt to EBITDA (each as defined therein) for DHI and its relevant subsidiaries of no greater than a specified amount; and (ii) a covenant that requires DHI and certain of its subsidiaries to maintain a ratio of EBITDA to Consolidated Interest Expense (each as defined therein) for DHI and its relevant subsidiaries as of the last day of the measurement periods as specified below of no less than a specified amount. The following table summarizes the required ratios:

	(i) Secured Debt: EBITDA	(ii) EBITDA: Consolidated Interest Expense
Period Ended:	No greater than:	No less than:
March 31, 2011	3.50 : 1	1.35 : 1
June 30, 2011	3.50 : 1	1.40 : 1
September 30, 2011	3.25 : 1	1.60 : 1
December 31, 2011	3.00 : 1	1.60 : 1
Thereafter	2.50 : 1	1.75 : 1

We are in compliance with these covenants as of March 31, 2011.

As of March 31, 2011, DHI’s available liquidity under the Credit Facility was reduced by $431 million as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA. Further reductions in capacity are likely to occur based on our ratio of Secured Debt to EBITDA at June 30, 2011, September 30, 2011 and December 31, 2011 based on our current projections. Please see Going Concern and Revolver Capacity above for further discussion.

Given the increasingly stringent requirements under our EBITDA to Consolidated Interest Expense covenant over the next twelve months, and considering latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be in compliance with this covenant, as currently set forth in our Credit Facility, beginning in the third or fourth quarter of 2011, and it is virtually certain that we will not be in compliance with this covenant at some point over the next twelve months unless we reach agreement on an amendment to or replacement of the Credit Facility, or obtain a waiver of its terms. We could avoid a default under the Credit Facility if we were to repay the amounts owed and cash collateralize the related letters of credit. However, this course of action would not alleviate the going concern and liquidity issues that we are facing over the next twelve months. If we are unable to cure any such default, or obtain a waiver or replacement financing, and those lenders accelerate the payment of such indebtedness, in the case that we are unable to repay those amounts, the holders of the indebtedness under our secured debt obligations would be entitled to initiate foreclosure actions designed to acquire control of substantially all of our assets. The success of any such actions would have a material adverse impact on our financial condition, results of operations and cash flows. Please see Going Concern above for further discussion.

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 with respect to capital stock. Please read Note 18—Debt—Credit Facility in our Form 10-K for further discussion of our Credit Facility.

Dividends on Dynegy Common Stock. Dividend payments on Dynegy’s common stock are at the discretion of its Board of Directors and subject to limits contained in our Credit Facility and applicable law. Dynegy did not declare or pay a cash dividend on its common stock during the first quarter 2011.

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Credit Ratings

Our credit rating status is currently “non-investment grade”; our senior unsecured debt is rated “Caa3” by Moody’s, “CC” by Standard & Poor’s and “CC” by Fitch. On March 28, 2011, Moody’s downgraded our corporate family ratings to “Caa3” from “Caa1”; the rating outlook is negative. On March 18, 2011, Standard & Poor’s downgraded our corporate family ratings to “CC” from “CCC”. The agency also placed all ratings on credit watch with negative implications. On March 9, 2011, Fitch Ratings downgraded our corporate family ratings to “CC” from “CCC”; the rating outlook is negative. Additional downgrades could occur in the future based on the ratings agencies’ views of near-term risk of bankruptcy and going concern issues. The downgrades did not trigger any obligations under our financing arrangements; however, as of result of the downgrades, we have received demands to post additional collateral in support of certain of our operational agreements.

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.

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, 2011 and 2010. 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, 2011 and 2010, respectively:

Dynegy’s Results of Operations for the Three Months Ended March 31, 2011

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

Revenues	$	280		$	62		$	163		$	—		$	505
Cost of sales		(136	)		(20	)		(122	)		—			(278	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(47	)		(24	)		(39	)		—			(110	)
Depreciation and amortization expense		(100	)		(17	)		(7	)		(2	)		(126	)
General and administrative expense		—			—			—			(40	)		(40	)
Operating income (loss)	$	(3	)	$	1		$	(5	)	$	(42	)	$	(49	)
Other items, net		—			—			—			1			1
Interest expense														(89	)

Loss from continuing operations before income taxes														(137	)
Income tax benefit														60

Net loss													$	(77	)

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Dynegy’s Results of Operations for the Three Months Ended March 31, 2010

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

Revenues	$	486		$	143		$	229		$	—		$	858
Cost of sales		(127	)		(59	)		(122	)		—			(308	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(49	)		(23	)		(39	)		(2	)		(113	)
Depreciation and amortization expense		(50	)		(16	)		(8	)		(1	)		(75	)
General and administrative expense		—			—			—			(31	)		(31	)
Operating income (loss)	$	260		$	45		$	60		$	(34	)	$	331
Losses from unconsolidated investments		(34	)		—			—			—			(34	)
Other items, net		—			—			1			—			1
Interest expense														(89	)

Income from continuing operations before income taxes														209
Income tax expense														(65	)

Income from continuing operations														144
Income from discontinued operations, net of taxes														1

Net income													$	145

EBITDA and Adjusted EBITDA-Dynegy. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted for certain items described below and presented in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with GAAP (a non-GAAP measure), and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with GAAP. Our Credit Facility includes a similar measure as a basis for certain financial covenants.

We believe that Adjusted EBITDA provides a meaningful representation of our operating performance. Adjusted EBITDA is meant to reflect the true operating performance of our power generation fleet; consequently, it excludes the impact of mark-to-market accounting and other items that could be considered “non-operating” or “non-core” in nature, and includes the contributions of those plants classified as discontinued operations. Because Adjusted EBITDA is a financial measure that management uses to allocate resources, determine Dynegy’s ability to fund capital expenditures, assess performance against its peers and evaluate overall financial performance, we believe it provides useful information for our investors. In addition, many analysts, fund managers and other stakeholders that communicate with us typically request our financial results in an Adjusted EBITDA format.

We believe that Adjusted EBITDA is only useful as an additional tool to help management and investors make informed decisions about Dynegy’s financial and operating performance. By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the GAAP measures. Non-GAAP financial measures are not standardized; therefore, it may not be possible to compare Adjusted EBITDA with other companies’ financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

We use these non-GAAP financial measures in addition to, and in conjunction with, results presented in accordance with GAAP. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in our results of operations, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy, and must be considered in conjunction with GAAP measures.

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In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with Dynegy’s Board of Directors, stockholders, creditors, analysts and investors concerning our financial performance.

When Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to Adjusted EBITDA is net income (loss). Further, because management does not allocate interest expense and income taxes on a segment level, the most directly comparable GAAP financial measure to Adjusted EBITDA when performance is discussed on a segment level or plant level is Operating income (loss).

The tables below provide a reconciliation of Adjusted EBITDA to our operating income (loss) on a segment basis and to net income (loss) on a consolidated basis for the three month periods ended March 31, 2011 and 2010, respectively.

Dynegy’s Adjusted EBITDA for Three Months Ended March 31, 2011

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Net loss													$	(77	)
Income tax benefit														(60	)
Interest expense														89
Other items, net														(1	)

Operating income (loss)	$	(3	)	$	1		$	(5	)	$	(42	)	$	(49	)
Depreciation and amortization expense		100			17			7			2			126
Other items, net		—			—			—			1			1

EBITDA		97			18			2			(39	)		78

Merger agreement termination fee and other legal expenses		—			—			—			9			9
Executive separation agreement expenses		—			—			—			3			3
Mark-to-market (gains) losses, net		(1	)		(15	)		13			—			(3	)

Adjusted EBITDA	$	96		$	3		$	15		$	(27	)	$	87

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Dynegy’s Adjusted EBITDA for the Three Months Ended March 31, 2010

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Net income.													$	145
Income tax expense														65
Interest expense														89
Losses from unconsolidated investments														34
Income from discontinued operations, net of taxes														(1	)
Other items, net														(1	)

Operating income (loss)	$	260		$	45		$	60		$	(34	)	$	331
Other items, net		—			—			1			—			1
Depreciation and amortization expense		50			16			8			1			75
Losses from unconsolidated investments		(34	)		—			—			—			(34	)

EBITDA from continuing operations		276			61			69			(33	)		373
EBITDA from discontinued operations		—			1			—			—			1

EBITDA		276			62			69			(33	)		374
Asset impairment		37			—			—			—			37
Plum Point mark-to-market gains		(6	)		—			—			—			(6	)
Mark-to-market gains, net		(179	)		(23	)		(51	)		—			(253	)

Adjusted EBITDA	$	128		$	39		$	18		$	(33	)	$	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, 2011 and 2010, respectively:

DHI’s Results of Operations for the Three Months Ended March 31, 2011

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

Revenues	$	280		$	62		$	163		$	—		$	505
Cost of sales		(136	)		(20	)		(122	)		—			(278	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(47	)		(24	)		(39	)		—			(110	)
Depreciation and amortization expense		(100	)		(17	)		(7	)		(2	)		(126	)
General and administrative expense		—			—			—			(41	)		(41	)
Operating income (loss)	$	(3	)	$	1		$	(5	)	$	(43	)	$	(50	)
Other items, net		—			—			—			1			1
Interest expense														(89	)

Loss from continuing operations before income taxes														(138	)
Income tax benefit														58
Net loss													$	(80	)

DHI’s Results of Operations for the Three Months Ended March 31, 2010

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

Revenues	$	486		$	143		$	229		$	—		$	858
Cost of sales		(127	)		(59	)		(122	)		—			(308	)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below		(49	)		(23	)		(39	)		(2	)		(113	)
Depreciation and amortization expense		(50	)		(16	)		(8	)		(1	)		(75	)
General and administrative expense		—			—			—			(31	)		(31	)
Operating income (loss)	$	260		$	45		$	60		$	(34	)	$	331
Losses from unconsolidated investments		(34	)		—			—			—			(34	)
Other items, net		—			—			1			—			1
Interest expense														(89	)

Income from continuing operations before income taxes														209
Income tax expense														(72	)

Income from continuing operations														137
Income from discontinued operations, net of taxes														1

Net income													$	138

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The following table provides summary segmented operating statistics for the three months ended March 31, 2011 and 2010, respectively:

	Three Months Ended March 31,
	2011			2010
GEN-MW
Million Megawatt Hours Generated		7.2			6.4
In Market Availability for Coal Fired Facilities (1)		92	%		94	%
Average Capacity Factor for Combined Cycle Facilities (2)		30	%		16	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	41		$	42
Commonwealth Edison (NI Hub)	$	39		$	42
PJM West	$	51		$	52
Average Market Spark Spreads ($/MWh) (4):
PJM West	$	11		$	9

GEN-WE
Million Megawatt Hours Generated (5)		0.4			1.4
Average Capacity Factor for Combined Cycle Facilities (2)		15	%		58	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)	$	35		$	47

Average Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)	$	3		$	7

GEN-NE
Million Megawatt Hours Generated		1.5			1.5
In Market Availability for Coal Fired Facilities (1)		95	%		92	%
Average Capacity Factor for Combined Cycle Facilities (2)		32	%		28	%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	64		$	57
New York—Zone A	$	42		$	40
Mass Hub	$	65		$	55
Average Market Spark Spreads ($/MWh) (4):
New York—Zone A	$	8		$	—
Mass Hub	$	17		$	9
Fuel Oil	$	(98	)	$	(72	)

Average natural gas price—Henry Hub ($/MMBtu) (6)	$	4.16		$	5.15

(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 we realized.

(4)

Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator or an 11.0 MMBtu/MWh heat rate fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.

(5)

Includes our ownership percentage in the MWh generated by our GEN-WE investment in the Black Mountain power generation facility for the three months ended March 31, 2011 and 2010, respectively.

(6)

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

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

	Three Months Ended March 31, 2010
	Power Generation
	GEN-MW			GEN-WE		GEN-NE		Other		Total
	(in millions)
PPEA Holding impairment	$	(37	)	$	—	$	—	$	—	$	(37	)
Taxes		—			—		—		11		11

Total—DHI		(37	)		—		—		11		(26	)
Taxes		—			—		—		5		5

Total—Dynegy	$	(37	)	$	—	$	—	$	16	$	(21	)

There were no such items reported for the three months ended March 31, 2011.

Operating Income (Loss)

Operating loss for Dynegy was $49 million for the three months ended March 31, 2011, compared to operating income of $331 million for the three months ended March 31, 2010. Operating loss for DHI was $50 million for the three months ended March 31, 2011, compared to operating income of $331 million for the three months ended March 31, 2010.

Mark-to market gains on forward sales of power and other derivatives associated with our generating assets are included in Revenues in the unaudited condensed consolidated statements of operations. Such gains totaled $2 million for the three months ended March 31, 2011, compared to $253 million of mark-to-market gains for the three months ended March 31, 2010. The gains in both periods were primarily the result of a decrease in forward market prices and forward spark spreads, partially offset by losses related to the expiration during the quarter of certain risk management positions for which the mark-to-market gains were recognized in previous periods.

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. For the majority of our commodity derivative instruments, we cash settle the change in value of the instrument on a daily basis through our broker margin account, resulting in working capital changes related to our mark-to-market gains and losses. Our overall mark-to-market position and the related mark-to-market value will change as we buy or sell volumes within the forward market and as forward commodity prices fluctuate.

Power Generation—Midwest Segment. Operating loss for GEN-MW was $3 million for the three months ended March 31, 2011, compared to operating income of $260 million for the three months ended March 31, 2010.

Revenues for the three months ended March 31, 2011 decreased by $206 million compared to the three months ended March 31, 2010, cost of sales increased by $9 million and operating and maintenance expense decreased by $2 million, resulting in a net decrease of $213 million. The decrease was primarily driven by the following:

●

Reduced Mark-to-market gains – GEN-MW’s results for the three months ended March 31, 2011 included mark-to-market gains of $1 million related to forward sales and other derivative contracts, compared to $179 million of mark-to-market gains for the three months ended March 31, 2010. Of the $1 million in 2011 mark-to-market gains, $4 million of losses related to positions that settled or will settle in 2011, and was more than offset by $5 million of gains related to positions that will settle in 2012 and beyond;

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●

Energy sales – GEN-MW’s results from energy sales, including both physical and financial transactions, decreased from $132 million for the three months ended March 31, 2010 to $117 million for the three months ended March 31, 2011. The contribution from physical transactions increased primarily as a result of improved spark spreads for our combined-cycle facilities. The increase from physical transactions was more than offset by reduced contributions from financial transactions; and

●

Decreased tolling/capacity revenues of $21 million – Tolling and capacity revenues decreased by $23 million primarily as a result of the monetization and replacement, at a lower volume, of a tolling agreement on the Kendall facility in 2010 and another $4 million due to lower capacity prices in MISO. These decreases were partially offset by a $6 million increase attributable to higher PJM capacity prices and the additional capacity made available by the termination of the previous Kendall tolling agreement.

Depreciation expense increased from $50 million for the first quarter 2010 to $100 million for the first quarter 2011, primarily as a result of fully depreciating the value of our Vermilion facility which was mothballed during the first quarter 2011.

Power Generation—West Segment. Operating income for GEN-WE was $1 million for three months ended March 31, 2011, compared to operating income of $45 million for the three months ended March 31, 2010.

Revenues for the three months ended March 31, 2011 decreased by $81 million compared to the three months ended March 31, 2010, cost of sales decreased by $39 million and operating and maintenance expense increased by $1 million, resulting in a net decrease of $43 million. The decrease was primarily driven by:

●

Energy sales – GEN-WE’s results from energy sales, including both physical and financial transactions, decreased from $29 million for the three months ended March 31, 2010 to $6 million for the three months ended March 31, 2011. The contribution from physical transactions decreased primarily as a result of reduced spark spreads. The contribution from financial transactions also decreased;

●

Decreased tolling revenues of $5 million – Tolling revenues decreased primarily as a result of the timing of earnings under our new tolling agreement for the Moss Landing facility compared to the timing of earnings under the previous agreement; and

●

Reduced mark-to-market gains – GEN-WE’s results for the three months ended March 31, 2011 included mark-to-market gains of $16 million related to forward sales and other derivative contracts, compared to $23 million of mark-to-market gains for the three months ended March 31, 2010. Of the $16 million in 2011 mark-to-market gains, $11 million related to positions that settled or will settle in 2011, and the remaining $5 million related to positions that will settle in 2012 and beyond; and

●

Increased operating expense – Operating expense, exclusive of a decrease in those expenses which were recovered through revenue under an RMR agreement in 2010, increased by $4 million, primarily as a result of an outage at our Moss Landing facility in 2011.

Depreciation expense increased from $16 million for the first quarter 2010 to $17 million for the first quarter 2011.

Power Generation—Northeast Segment. Operating loss for GEN-NE was $5 million for the three months ended March 31, 2011, compared to an operating income of $60 million for the three months ended March 31, 2010.

Revenues for the three months ended March 31, 2011 decreased by $66 million compared to the three months ended March 31, 2010, cost of sales and operating and maintenance expenses remained flat resulting in a net decrease of $66 million. The decrease was primarily driven by the following:

●

Mark-to-market losses – GEN-NE’s results for the three months ended March 31, 2011 included mark-to-market losses of $15 million related to forward sales and other derivative contracts, compared to gains of $51 million for the three months ended March 31, 2010. Of the $15 million in 2011 mark-to-market losses, $5 million related to positions that settled or will settle in 2011, and the remaining $10 million related to positions that will settle in 2012 and beyond; and

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●

Decreased capacity revenues of $7 million – Capacity revenues decreased primarily due to lower pricing.

●

Energy sales – GEN-NE’s results from energy sales, including both physical and financial transactions, increased from $16 million for the three months ended March 31, 2010 to $19 million for the three months ended March 31, 2011. The contribution from physical transactions increased primarily as a result of improved market spark spreads partially offset by an extended outage at our Casco Bay facility and reduced contribution from financial transactions; and

●

An emissions inventory write-down of approximately $2 million recorded during the three months ended March 31, 2010.

Depreciation expense decreased from $8 million for the first quarter 2010 to $7 million for the first quarter 2011 primarily due to the impairment of our Casco Bay facility which was recorded in the third quarter 2010.

Other. Dynegy’s other operating loss for the three months ended March 31, 2011 was $42 million, compared to an operating loss of $34 million for the three months ended March 31, 2010. DHI’s other operating loss for the three months ended March 31, 2011 was $43 million, compared to an operating loss of $34 million for the three months ended March 31, 2010. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses increased from $31 million for the three months ended March 31, 2010 to $40 million for the three months ended March 31, 2011. DHI’s consolidated general and administrative expenses increased from $31 million for the three months ended March 31, 2010 to $41 million for the three months ended March 31, 2011. The increases were primarily driven by $9 million of transaction expenses and $3 million of severance expenses, partially offset by lower salary and benefits costs as a result of ongoing cost savings initiatives.

Losses from Unconsolidated Investments

Dynegy’s and DHI’s losses from unconsolidated investments were $34 million for the three months ended March 31, 2010 related to the GEN-MW investment in PPEA Holding. The losses consisted of an impairment charge of approximately $37 million partially offset by $3 million in equity earnings primarily related to mark-to-market gains on interest rate swaps offset by financing expenses. Due to the uncertainty regarding PPEA’s financing structure, our investment in PPEA Holding was fully impaired at March 31, 2010. We sold our investment in PPEA Holding during the fourth quarter 2010.

Other Items, Net

Dynegy’s and DHI’s other items, net, were $1 million for the three months ended March 31, 2011 and 2010.

Interest Expense

Dynegy’s and DHI’s interest expense totaled $89 million for the three months ended March 31, 2011 and 2010.

Income Tax Benefit (Expense)

Dynegy reported an income tax benefit from continuing operations of $60 million for the three months ended March 31, 2011, compared to an income tax expense from continuing operations of $65 million for the three months ended March 31, 2010. The 2011 effective tax rate was 44 percent, compared to 31 percent in 2010.

DHI reported an income tax benefit from continuing operations of $58 million for the three months ended March 31, 2011, compared to an income tax expense of $72 million from continuing operations for the three months ended March 31, 2010. The 2011 effective tax rate was 42 percent, compared to 34 percent in 2010.

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For the period ended March 31, 2011, the difference between the effective rates of 44 percent and 42 percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted primarily from the impact of state taxes including the benefit of $9 million and $6 million for Dynegy and DHI, respectively, related to an increase in state NOLs due to the acceptance of amended returns, which were filed as a result of a change in a tax position, partially offset by an expense of $3 million and $2 million for Dynegy and DHI, respectively, related to an increase in the Illinois statutory rate. For the period ended March 31, 2010, the difference between the effective rates of 31 percent and 34 percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted primarily from the benefit of $16 million and $11 million for Dynegy and DHI, respectively, related to the release of a reserve for uncertain tax positions upon completion of an audit, partly offset by the impact of state taxes.

Discontinued Operations

Income From Discontinued Operations Before Taxes

During the three months ended March 31, 2010, our pre-tax income from discontinued operations was $1 million primarily related to the reversal of previously accrued operating and maintenance expenses related to the Arizona generation facilities.

Income Tax Expense From Discontinued Operations

We recorded an income tax expense from discontinued operations of zero during the three months ended March 31, 2010. The amounts reflect effective rates of zero. The detailed methodology of allocating income taxes between continuing and discontinued operations often results in an effective rate for discontinued operations significantly different from the statutory rate of 35 percent.

Outlook

In the absence of an amendment to or replacement of the Credit Facility, or a waiver of its terms, our cash on hand and short-term investments as of March 31, 2011 and our internally forecasted cash flows for the remainder of 2011, are not expected to be sufficient to fund our remaining planned capital expenditure program for 2011 and our debt service requirements for the year. As discussed above, we also project that it is likely that we will not be in compliance with our EBITDA to Consolidated Interest Expense covenant contained in our Credit Facility. Accordingly, we are discussing with lenders the terms upon which an amendment to the Credit Facility or a new credit facility could be implemented. Please read Note 1—Accounting Policies—Going Concern for further discussion.

We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. Please read Capital Structuring Transactions and Asset Dispositions above for more detail. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans. For additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see Item 1A—Risk Factors in our Form 10-K.

Our power generation portfolio currently consists of approximately 11,600 MW of generating capacity that is diversified by fuel source (i.e., coal, natural gas and fuel oil) and dispatch type (i.e., baseload, intermediate and peaking facilities).

We expect that our future financial results will continue to be sensitive to fuel and commodity prices, especially gas prices and the impact on such prices of shale gas proliferation. Other factors to which our future financial results will remain sensitive include market structure and prices for electric energy, capacity and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions and IMA. Further, there is a trend toward greater environmental regulation of all aspects of our business. As this trend continues, it is likely that we will experience additional costs and limitations.

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We have volumetrically hedged nearly 100 percent of our expected generation volumes for 2011 and approximately 38 percent for 2012. Based on specific market conditions, at any point in time we may enter into transactions that will increase or decrease the portion of our expected output that has been contracted. Even though we have largely contracted our expected output through 2011, our future operating cash flows during this period may vary based on a number of other factors, including the value of capacity and ancillary services, the operational performance of our generating facilities, the price differential between the locations where we deliver generated power and the liquid market hub, legal, environmental, and regulatory requirements, collateral requirements and other factors. Further, we may reduce the amount of our expected generation we have volumetrically hedged in order to reduce the collateral postings required to support our current level of hedging activity.

During January 2011, we performed an inspection of our Casco Bay steam turbine. As a result of this inspection, it was determined by the original equipment manufacturer and our operations personnel that certain steam turbine blades needed to be replaced. Initial repairs were completed and the unit was returned to service on March 22, 2011. Final repairs are expected to be completed at a later date. We plan to evaluate similar equipment at our Moss Landing and Kendall facilities later in 2011 to determine whether turbines at these facilities will need similar repairs. We expect the capital cost of replacement and repair to be approximately $20 million to $25 million to be incurred through the end of 2012, assuming similar repairs are required at both the Moss Landing and Kendall facilities.

GEN-MW. Our Midwest Consent Decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. We have achieved all emission reductions scheduled to date under the Midwest Consent Decree and are in the process of installing additional emission control equipment to meet future Midwest Consent Decree emission limits. We expect our costs associated with the remaining Midwest Consent Decree projects, which we have planned to incur through 2013, to be approximately $193 million. This estimate includes a number of assumptions about uncertainties beyond our control, such as costs associated with labor and materials. If the costs of these capital expenditures become great enough to render the operation of the affected power generation facility or facilities uneconomical, we could, at our option, cease to operate the power generation facility or facilities and forego these capital expenditures without incurring any further obligations under the Midwest Consent Decree.

Consistent with our announcement on December 28, 2010, we mothballed the 176-megawatt Vermilion power generation facility in Oakwood, Illinois, near the end of the first quarter 2011. The plant ceased generating electricity in the second half of March and now has a reduced staffing level. No decision has been made regarding whether to permanently retire, to extend the mothball state after 2013, or to restore operations at the plant before or after the end of the current period for which we have approval to mothball the plant, which is December 31, 2013. Factors influencing our decision on the ultimate outcome for the plant will include the relatively small size of the facility, older technologies and coal delivery challenges that lead to high production costs, as well as weak electricity demand, a low power pricing environment, and uncertainties over future regulatory requirements.

Our Midwest coal requirements are approximately 100 percent contracted in 2011 and 98 percent contracted in 2012. All forecast coal requirements are 96 percent priced through 2011 and 69 percent are priced through 2012. Committed volumes that are currently unpriced are subject to a price collar structure. Our Midwest coal transportation requirements are 100 percent contracted and priced through 2013. We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies. Our Midwest expected generation volumes are volumetrically 100 percent hedged through 2011 and approximately 28 percent hedged for 2012.

Recent moves by certain MISO market participants expressing their intentions to exit the MISO could mitigate earlier membership increases and impact system reserve margins favorably in the future. The impacts to MISO capacity market-clearing practices and the resulting prices are unclear at this time as the MISO continues to consult with market stakeholders regarding optimal capacity auction mechanics and product offerings. In addition, competing initiatives of increased market participation by demand response resources offset by potential retirement of marginal MISO coal capacity due to expected environmental mandates could also affect MISO capacity and energy markets in the future.

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GEN-WE. Approximately 70 percent of our power plant capacity in the West is contracted through 2011 under tolling agreements with load-serving entities and an RMR agreement with the CAISO. A significant portion of the remaining capacity is sold as a resource adequacy product in the California market, and much of the expected production associated with our plants without tolls or an RMR agreement has been financially hedged.

The estimated useful lives of our generation facilities consider environmental regulations currently in place. With respect to units 6 and 7 at our Moss Landing facility, we are continuing to review the potential impact of the California Water Intake Policy. We are currently depreciating these units through 2024; however, depending on the ultimate impact of the California Water Intake Policy, we may determine that we will be required to install cooling systems that would render operation of the units uneconomical. If such a determination were to be made, we could decide to reduce operations or cease to operate the units as early as December 31, 2017. A decision to cease operations at the end of 2017 would result in the acceleration of depreciation on the remaining net book values of the units, which was $355 million at March 31, 2011.

South Bay’s RMR designation was terminated at the end of 2010, and as a result, the South Bay power generation facility has been decommissioned. We have a contractual obligation to demolish the facility and remediate specific parcels of the property. Our cost estimates for the demolition of the facility have not been finalized, but our obligation is expected to be approximately $40 million, exclusive of certain rental payments that will be due the Port of San Diego. We expect to begin the demolition in 2012.

GEN-NE. A substantial portion of our physical coal supply and delivery requirements for 2011 are fully contracted and priced with the balance financially hedged. Having both marine and rail unloading capability at the Danskammer facility allows us to explore domestic and/or international coal supply and delivery options. In the near term, lower natural gas prices are expected to continue to compress dark spreads and alter the dispatch stack favoring natural gas-fired assets over coal-fired assets during off-peak periods in much of the Northeast. We continue to maximize revenue opportunities from our merchant plant operations in New York through active participation in the NYISO capacity auctions and ancillary services markets. Capacity prices have trended lower in New York due to surplus capacity and lower demand. As of the first quarter, we have contracted approximately 88 percent of our 2011 capacity in the NYISO. Looking forward, approximately 27 percent of our capacity for the 2012-2014 period has been contracted at a favorable premium to current market prices.

In New England, four forward capacity auctions have been held since the ISO-NE transitioned to a forward capacity auction market in June 2010. Capacity clearing prices have ranged from a high of $4.50 per kW-month for the 2010-2011 market period to a low of $2.95 per kW-month for the 2013-2014 market period. These capacity clearing prices represent the floor price, and the actual rate paid to Casco Bay (and other facilities) has been reduced due to oversupply conditions and pro-rationing. Efforts to implement prospective improvements in the forward capacity market design are currently underway in active proceedings at FERC and in discussions by the ISO and its stakeholders.

Environmental and Regulatory Matters

Please read Item 1. Business—Environmental Matters in our Form 10-K for a more detailed discussion.

Federal Regulation of Greenhouse Gases. The EPA final rule requiring mandatory reporting of GHG emissions from all sectors of the economy went into effect in January 2010 and requires that reports of GHG emissions be filed annually thereafter. We have implemented new processes and procedures to report these emissions as required. On March 18, 2011, the EPA extended the deadline for reporting 2010 GHG emissions data to September 30, 2011.

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State Regulation of Greenhouse Gases. Our assets in California are subject to the California Global Warming Solutions Act (“AB 32”), which became effective in January 2007. AB 32 requires the CARB to develop a GHG emission control program that will reduce emissions of GHG in the state to their 1990 levels by 2020 with a fully effective regulatory program to be in place by January 2012. The formal cap-and-trade rulemaking began with the release of the Staff Report: Initial Statement of Reasons on October 28, 2010. The CARB considered the Proposed Regulation to Implement the California Cap-and-Trade Program at its public hearing on December 16, 2010. At that hearing, the Board adopted a resolution to approve the rule with specified modifications that will be made through additional rulemakings in 2011, including a rulemaking to address allowance allocations. Initially, the program will apply to large stationary sources including power generation facilities beginning in 2012. GHG emission allowances are expected to be sold at auctions beginning in February 2012. On March 17, 2011, the San Francisco County Superior Court held that the CARB failed to comply with certain obligations under the California Environmental Quality Act and enjoined further implementation of the AB 32 cap-and-trade program until the Board achieves compliance. The impact of the court’s decision on the cap-and-trade program is uncertain. We will continue to evaluate the CARB’s response to the court’s decision.

On January 1, 2009, our assets in New York and Maine became subject to a state-driven GHG emission control program known as RGGI. RGGI was developed and implemented by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants. The participating RGGI states implemented rules regulating GHG emissions using a cap-and-trade program to reduce CO2 emissions by at least 10 percent of 2009 emission levels by the year 2018. Compliance with the allowance requirement under the RGGI cap-and-trade program can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. While allowances are sold by year, actual compliance is measured across a three year control period. The first control period is for the 2009-2011 timeframe.

In March 2011, RGGI held its eleventh auction, in which approximately 42 million allowances for the current control period, and 2.1 million allowances for future control periods, were sold at clearing prices of $1.89 per allowance. We have participated in each of the quarterly RGGI auctions (or in secondary markets, as appropriate) to secure some allowances for our affected assets. We expect that the increased operating costs resulting from purchase of CO2 allowances will be at least partially reflected in market prices. The RGGI states plan to continue to conduct quarterly auctions in 2011.

Multi-Pollutant Air Emission Initiatives—Mercury/HAPs. In March 2005, the EPA issued the CAMR for control of mercury emissions from coal-fired power plants and established a cap and trade program requiring states to promulgate rules at least as stringent as CAMR. In December 2006, the Illinois Pollution Control Board approved a state rule for the control of mercury emissions from coal-fired power plants that required additional capital and O&M expenditures at each of our Illinois coal-fired plants beginning in 2007. The State of New York has also approved a mercury rule that will likely require us to incur additional capital and operating costs for our Danskammer power generating facility by January 1, 2015.

In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR; however, the Illinois and New York mercury regulations remain in effect. In December 2009, the EPA issued information requests under Section 114 of the CAA to many coal- and oil-fired steam electric generating companies, including certain of our operating companies. These requests required stack tests to develop information on emissions of mercury and other HAPs that will be used by the EPA to develop emission standards for HAPs under Section 112 of the CAA. On March 16, 2011, the EPA released a proposed rule to establish MACT emission standards for HAPs at coal- and oil-fired electric generating units. The proposed rule would establish numeric emission limits for mercury, non-mercury metals (total particulate may be used as a surrogate), and acid gases (hydrogen chloride used as a surrogate, with sulfur dioxide as an optional surrogate for coal-fired units using flue gas desulfurization; oil-fired units also would be subject to a hydrogen fluoride limit), and work practice standards for organic HAPs. Compliance would be required within three years after the effective date of the final rule, unless an extension is granted in accordance with the CAA. Under a consent decree, the EPA is required to issue final standards by November 16, 2011. We are evaluating the proposed rule and its potential impacts on our operations.

The Clean Water Act. Our water withdrawals and wastewater discharges are permitted under the CWA and analogous state laws. The cooling water intake structures at several of our facilities are regulated under Section 316(b) of the CWA. This provision generally directs that standards set for facilities require that the location, design, construction and capacity of cooling water intake structures reflect BTA for minimizing adverse environmental impact. These standards are developed and implemented for power generating facilities through NPDES permits or SPDES permits. Historically, standards for minimizing adverse environmental impacts of cooling water intakes have been made by permitting agencies on a case-by-case basis considering the best professional judgment of the permitting agency.

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In 2004, the EPA issued the Cooling Water Intake Structures Phase II Rules (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 2nd Circuit in Riverkeeper, Inc. v. EPA. The Court’s decision remanded several provisions of the rules to the EPA for further rulemaking. Several parties sought review of the decision before the U.S. Supreme Court. In April 2009, the U.S. Supreme Court ruled that the 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.

In July 2007, following remand of the rules by the U.S. Court of Appeals, the EPA suspended its Phase II Rules and advised that permit requirements for cooling water intake structures at existing facilities should once more be established on a case-by-case best professional judgment basis until replacement rules are issued. On March 28, 2011, the EPA released a proposed rule for cooling water intake structures at existing facilities. The proposed rule would (i) establish impingement mortality standards that would give affected facilities the option of either achieving impingement mortality of no more than 12 percent (annual average) and 31 percent (monthly average) or maintaining intake velocity at no more than 0.5 feet per second under all conditions; and (ii) require the permitting authority to establish case-by-case entrainment mortality standards based on a site-specific assessment of technology feasibility and performance, energy and environmental impacts, benefits, social costs, and other factors. We are analyzing the proposed rule and its potential impacts at our affected power generation facilities. Under a settlement agreement, the EPA will finalize the rule in July 2012. The scope of requirements, timing for compliance and the compliance methodologies that will ultimately be allowed potentially may result in significantly increased costs.

California Water Intake Policy. The California State Water Board adopted its Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (the “Policy”) at its meeting on May 4, 2010, introducing and adopting several amendments making it more stringent than the proposed draft Policy. The approved Policy requires that existing power plants: (i) reduce their water intake flow rate to a level commensurate with that which can be achieved by a closed cycle cooling system; or (ii) if it is not feasible to reduce the water intake flow rate to this level, reduce impingement mortality and entrainment to a level comparable to that achieved by such a reduced water intake flow rate using operational or structural controls, or both. The Policy became effective October 1, 2010. Compliance with the Policy would be required at our Morro Bay power generation facility by December 31, 2015 and at our Moss Landing power generation facility by December 31, 2017. On October 27, 2010, Dynegy Morro Bay, LLC and Dynegy Moss Landing, LLC joined with other California power plant owners in filing a lawsuit in the Sacramento County Superior Court challenging the Policy.

On September 29, 2010, the State Water Board proposed to amend the Policy to allow an owner or operator of a power plant with previously installed combined-cycle power generating units to continue to use once-through cooling at combined-cycle units until the unit reaches the end of its useful life under certain circumstances. A hearing to receive comment and to take action on the proposed amendment was held on December 14, 2010; however, the State Water Board declined to approve the amendment and instead tabled it for consideration until after the Statewide Advisory Committee on Cooling Water Intake Structures has reviewed facility compliance plans and made recommendations to the Board.

In accordance with the Policy, on April 1, 2011, we submitted proposed compliance plans for our Morro Bay and Moss Landing facilities. For Morro Bay and Moss Landing Units 6 and 7, we proposed to continue our ongoing review of potential compliance options taking into account the facility’s applicable final compliance deadline. For Moss Landing Units 1 and 2, we proposed to continue current once-through cooling operations through the end of 2032, at which time we would evaluate repowering or installation of feasible control measures.

It may not be possible to meet the requirements of the Policy in its final form without installing closed cycle cooling systems. Given the numerous variables and factors involved in calculating the potential costs of closed cycle cooling systems, any decision to install such a system would be made on a case-by-case basis considering all relevant factors at the time. If capital expenditure requirements related to cooling water systems become great enough to render the continued operation of a particular plant uneconomical, we could at our option, and subject to any applicable financing agreements and other obligations, reduce operations or cease to operate the plant and forego such capital expenditures.

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Coal Combustion Residuals. The combustion of coal to generate electric power creates large quantities of ash that are managed at power generation facilities in dry form in landfills and in liquid or slurry form in surface impoundments. Each of our coal-fired plants has at least one CCR management unit. At present, CCR management is regulated by the states as solid waste. The EPA has considered whether CCR should be regulated as a hazardous waste on two separate occasions, including most recently in 2000, and both times has declined to do so. The December 2008 failure of a CCR surface impoundment dike at the Tennessee Valley Authority’s Kingston Plant in Tennessee accompanied by a very large release of ash slurry has resulted in renewed scrutiny of CCR management.

In response to the Kingston ash slurry release, the EPA initiated an investigation of the structural integrity of certain CCR surface impoundment dams including those at our GEN-MW facilities. We responded to EPA requests for information, and our surface impoundment dams that the EPA has assessed to date were found to be in fair to satisfactory condition.

In addition, on June 21, 2010, the EPA proposed two alternative rules under RCRA for federal regulation of the management and disposal of CCR from electric utilities and independent power producers. One proposal would regulate CCR as a special waste under RCRA subtitle C rules when those wastes are destined for disposal in a landfill or surface impoundment. The subtitle C proposal would subject persons who generate, transport, treat, store or dispose of such CCR to many of the existing RCRA regulations applicable to hazardous waste. While certain types of beneficial use of CCR would be exempt from regulation under the subtitle C proposal, the impact of subtitle C regulation on the continued viability of beneficial use is debated. Regulation under subtitle C would effectively phase out the use of ash ponds for disposal of CCR.

The second alternative proposal would regulate CCR disposed in landfills or surface impoundments as a solid waste under subtitle D of RCRA. The subtitle D proposal would establish national criteria for disposal of CCR in landfills and surface impoundments, requiring new units to install composite liners. The subtitle D proposal might also require existing surface impoundments without liners to close or be retrofitted with composite liners within five years.

Certain environmental organizations have advocated designation of CCR as a hazardous waste; however, many state environmental agencies have expressed strong opposition to such designation. The EPA accepted comments on its proposals through November 19, 2010 and is expected to issue final regulations governing CCR management in 2012. In April 2011, a bill was introduced in Congress that would prohibit the EPA from regulating CCR under RCRA subtitle C as hazardous waste. The nature and scope of these potential future requirements cannot be predicted with confidence at this time, but could have a material adverse effect on our financial condition, results of operations and cash flows. Further, public perceptions of new regulations regarding the reuse of coal ash may limit or eliminate the market that currently exists for coal ash reuse, which could have material adverse effects on our financial condition, results of operations and cash flows.

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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, 2011
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at December 31, 2010	$	34
Risk-management gains recognized through the income statement in the period, net		31
Cash received related to risk-management contracts settled in the period, net		(29	)
Changes in fair value as a result of a change in valuation technique (1)		—
Non-cash adjustments and other		1

Fair value of portfolio at March 31, 2011	$	37

(1)

Our modeling methodology has been consistently applied.

The net risk management asset of $37 million is the aggregate of the following line items on our unaudited condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of March 31, 2011, based on our valuation methodology:

Net Fair Value of Risk-Management Portfolio

	Total		2011		2012			2013		2014		2015		Thereafter
	(in millions)
Market quotations (1)	$	10	$	48	$	(38	)	$	—	$	—	$	—	$	—
Prices based on models		27		15		(6	)		15		1		1		1

Total	$	37	$	63	$	(44	)	$	15	$	1	$	1	$	1

(1)

Prices obtained from actively traded, liquid markets for commodities.

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

●

beliefs and assumptions regarding our ability to continue as a going concern;

●

the impact of the turnover in our executive team and Dynegy’s Board of Directors on our ability to execute our business plan and/or our ability to execute any new or revised business plan approved by Dynegy’s new directors;

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●

beliefs and assumptions relating to our liquidity, available borrowing capacity and capital resources generally, including the extent to which such liquidity could be affected by poor economic and financial market conditions or new regulations and any resulting impacts on financial institutions and other current and potential counterparties;

●

effectiveness of our restructuring activities and strategies to address our liquidity and our capital resources including accessing the capital markets;

●

limitations on our ability to utilize Dynegy’s previously incurred federal net operating losses or alternative minimum tax credits;

●

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

●

expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations to which we are, or could become, subject;

●

beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the impact on such prices from shale gas proliferation and the timing of a recovery in natural gas prices, if any;

●

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

●

beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale power generation market, including the anticipation of higher market pricing over the longer term;

●

the possibility of further consolidation in the power generation industry and the impact of any such activity on Dynegy;

●

beliefs and assumptions regarding our ability to enhance or protect long-term value for stockholders;

●

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

●

beliefs and assumptions about weather and general economic conditions;

●

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

●

expectations regarding our revolver capacity, credit facility compliance, financial covenants, collateral demands, capital expenditures, interest expense and other payments;

●

beliefs or expectations regarding the potential amendment or refinancing of our Credit Facility, or the timing thereof;

●

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

●

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

●

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

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.

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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, 2011.

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. Please read “Value at Risk” in our Form 10-K for a complete description of our valuation methodology. The decrease in the March 31, 2011 VaR was primarily due to decreased forward sales as compared to December 31, 2010.

Daily and Average VaR for Risk-Management Portfolios

	March 31, 2011		December 31, 2010
	(in millions)
One day VaR—95 percent confidence level	$	9	$	14
One day VaR—99 percent confidence level	$	13	$	20
Average VaR for the year-to-date period—95 percent confidence level	$	12	$	22

Credit Risk. The following table represents our credit exposure at March 31, 2011 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	$	11	$	—	$	11
Oil and gas producers		8		—		8
Utility and power generators		34		—		34
Total	$	53	$	—	$	53

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of March 31, 2011, the amount owed under our fixed rate debt instruments, as a percentage of the total amount owed under all of our debt instruments, was 80 percent. Adjusted for interest rate swaps, net notional fixed rate debt, as a percentage of total debt, was approximately 80 percent. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of March 31, 2011, 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, 2011 would either decrease or increase interest expense by approximately $9 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 adjust the variable rate exposure in our debt portfolio through the use of swaps or other financial instruments.

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The absolute notional financial contract amounts associated with our interest rate contracts were as follows at March 31, 2011 and December 31, 2010, respectively:

	March 31, 2011		December 31, 2010
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 contracts (in millions of U.S. dollars)	$	231	$	231
Fixed interest rate paid (percent)		5.35		5.35
Interest rate risk-management contracts (in millions of U.S. dollars)	$	206	$	206
Fixed interest rate received (percent)		5.28		5.28

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

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of 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, 2011.

Changes in Internal Controls Over Financial Reporting

Because Charles C. Cook now serves as our interim Chief Financial Officer and our Executive Vice President, Commercial Operations and Market Analytics, we have implemented the following enhancements to our internal controls: (i) our Internal Audit function now reports directly to our Executive Vice President and General Counsel, and is independent of the Chief Financial Officer; and (ii) our Commodity Risk Control group, which monitors compliance with our policy governing the use of commodity derivative instruments, now reports to our Internal Audit department, and is independent of the Chief Financial Officer.

Other than as noted above in this Item 4, 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, 2011.

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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 9—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		1,209	$	5.59		—		N/A
February 1-28		10,016	$	6.10		—		N/A
March 1-31		88,507	$	5.59		—		N/A

Total		99,732	$	5.64		—		N/A

These were the only purchases of equity securities made by us during the three months ended March 31, 2011. Dynegy does not have a stock repurchase program.

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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		Form of Phantom Stock Unit Award Agreement – Vice President and above, dated March 7, 2011.
**10.2		Form of Phantom Stock Unit Award Agreement – Managing Director, dated March 7, 2011.
10.3		Letter Agreement dated March 8, 2011 by and between Dynegy Inc. and IEH Merger Sub LLC, Icahn Enterprises Holdings L.P., IEP Merger Sub Inc., Icahn Partners LP, Icahn Partners Master Fund LP, Icahn Partners Master Fund II LP, Icahn Partners Master Fund III LP, High River Limited Partnership, Hopper Investments LLC, Barberry Corp., Icahn Onshore LP, Icahn Offshore LP, Icahn Capital LP, IPH GP LLC, Icahn Enterprises L.P., Icahn Enterprises G.P. Inc., Beckton Corp., and Carl C. Icahn. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 10, 2011, File No. 1-33443).
10.4		Consulting Agreement and Release dated March 8, 2011between Dynegy Inc. and Holli C. Nichols. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K/A of Dynegy Inc. filed on March 10, 2011, File No. 1-33443).
10.5		Third Amendment to the Dynegy Inc. Executive Severance Pay Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 22, 2011, File No. 1-33443).
**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.
*101.INS		XBRL Instance Document
*101.SCH		XBRL Taxonomy Extension Schema Document
*101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
*101.LAB		XBRL Taxonomy Extension Label Linkbase Document
*101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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** 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 9, 2011	By:	/s/ Charles C. Cook
		Charles C. Cook Interim Chief Financial Officer and Executive Vice President, Commercial Operations and Market Analytics (Duly Authorized Officer and Principal Financial Officer)

		DYNEGY HOLDINGS INC.

Date: May 9, 2011	By:	/s/ Charles C. Cook
		Charles C. Cook Interim Chief Financial Officer and Executive Vice President, Commercial Operations and Market Analytics (Duly Authorized Officer and Principal Financial Officer)