Edgar Filing: DYNEGY HOLDINGS INC

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 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 x No o
Dynegy Holdings Inc.			Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See 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.

Dynegy Holdings Inc.

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, 122,435,022 shares outstanding as of August 1, 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.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

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

Condensed Consolidated Balance Sheets—Dynegy Inc.:
June 30, 2011 and December 31, 2010		4
Condensed Consolidated Statements of Operations—Dynegy Inc.:
For the three and six months ended June 30, 2011 and 2010		5
Condensed Consolidated Statements of Cash Flows—Dynegy Inc.:
For the three and six months ended June 30, 2011 and 2010		6
Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Inc.:
For the three and six months ended June 30, 2011 and 2010		7
Condensed Consolidated Balance Sheets—Dynegy Holdings Inc.:
June 30, 2011 and December 31, 2010		8
Condensed Consolidated Statements of Operations—Dynegy Holdings Inc.:
For the three and six months ended June 30, 2011 and 2010		9
Condensed Consolidated Statements of Cash Flows—Dynegy Holdings Inc.:
For the three and six months ended June 30, 2011 and 2010		10
Condensed Consolidated Statements of Comprehensive Income (Loss)—Dynegy Holdings Inc.:
For the three and six months ended June 30, 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.	48
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK — DYNEGY INC. AND DYNEGY HOLDINGS INC.	76
Item 4.	CONTROLS AND PROCEDURES — DYNEGY INC. AND DYNEGY HOLDINGS INC.	77

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS — DYNEGY INC. AND DYNEGY HOLDINGS INC.	79
Item 1A.	RISK FACTORS — DYNEGY INC. AND DYNEGY HOLDINGS INC.	79
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS — DYNEGY INC.	81
Item 5.	OTHER INFORMATION — DYNEGY INC.	81
Item 6.	EXHIBITS — DYNEGY INC. AND DYNEGY HOLDINGS INC.	82

EXPLANATORY NOTE

This report includes the combined filing of Dynegy Inc. (“Dynegy”) and Dynegy Holdings Inc. (“DHI”). DHI is the principal subsidiary of Dynegy, providing nearly 100 percent of Dynegy’s total consolidated revenue for the six-month period ended June 30, 2011 and constituting nearly 100 percent of Dynegy’s total consolidated asset base as of June 30, 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, DHI or specific subsidiaries 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
CEQA		California Environmental Quality Act
CERCLA		The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CO2		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
DHI		Dynegy Holdings Inc.
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)

	June 30, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	399		$	291
Restricted cash and investments	878			81
Short-term investments	106			106
Accounts receivable, net of allowance for doubtful accounts of $31 and $32, respectively	169			230
Accounts receivable, affiliates	—			1
Inventory	125			121
Assets from risk-management activities	989			1,199
Deferred income taxes	12			12
Broker margin account	202			80
Prepayments and other current assets	137			123
Total Current Assets	3,017			2,244
Property, Plant and Equipment	8,700			8,593
Accumulated depreciation	(2,499		)	(2,320		)
Property, Plant and Equipment, Net	6,201			6,273
Other Assets
Restricted cash and investments	9			859
Assets from risk-management activities	84			72
Intangible assets	116			141
Other long-term assets	436			424
Total Assets	$	9,863		$	10,013

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	111		$	134
Accrued interest	51			36
Accrued liabilities and other current liabilities	86			109
Liabilities from risk-management activities	1,043			1,138
Notes payable and current portion of long-term debt	1,008			148
Total Current Liabilities	2,299			1,565
Long-term debt	3,852			4,426
Long-term debt, affiliates	200			200
Long-Term Debt	4,052			4,626
Other Liabilities
Liabilities from risk-management activities	123			99
Deferred income taxes	509			641
Other long-term liabilities	321			336
Total Liabilities	7,304			7,267
Commitments and Contingencies (Note 7)
Stockholders’ Equity
Common Stock, $0.01 par value, 420,000,000 shares authorized at June 30, 2011 and December 31, 2010; 123,009,079 and 121,687,198 shares issued and outstanding at June 30, 2011 and December 31, 2010, respectively	1			1
Additional paid-in capital	6,071			6,067
Subscriptions receivable	(2		)	(2		)
Accumulated other comprehensive loss, net of tax	(51		)	(53		)
Accumulated deficit	(3,389		)	(3,196		)
Treasury stock, at cost, 728,408 and 628,014 shares at June 30, 2011 and December 31, 2010, respectively	(71		)	(71		)
Total Stockholders’ Equity	2,559			2,746
Total Liabilities and Stockholders’ Equity	$	9,863		$	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 June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues	$	326		$	239		$	831		$	1,097
Cost of sales	(225		)	(231		)	(503		)	(539		)
Operating and maintenance expense, exclusive of depreciation shown separately below	(106		)	(118		)	(216		)	(231		)
Depreciation and amortization expense	(75		)	(90		)	(201		)	(165		)
Impairment and other charges	(1		)	(1		)	(1		)	(1		)
General and administrative expenses	(25		)	(28		)	(65		)	(59		)

Operating income (loss)	(106		)	(229		)	(155		)	102
Losses from unconsolidated investments	—			—			—			(34		)
Interest expense	(89		)	(91		)	(178		)	(180		)
Other income and expense, net	3			1			4			2

Loss from continuing operations before income taxes	(192		)	(319		)	(329		)	(110		)
Income tax benefit (Note 10)	76			128			136			63

Loss from continuing operations	(116		)	(191		)	(193		)	(47		)
Income from discontinued operations, net of taxes	—			—			—			1

Net loss	$	(116	)	$	(191	)	$	(193	)	$	(46	)

Loss Per Share (Note 11):
Basic loss per share:
Loss from continuing operations	$	(0.95	)	$	(1.59	)	$	(1.58	)	$	(0.39	)
Income from discontinued operations	—			—			—			0.01

Basic loss per share	$	(0.95	)	$	(1.59	)	$	(1.58	)	$	(0.38	)

Diluted loss per share:
Loss from continuing operations	$	(0.95	)	$	(1.59	)	$	(1.58	)	$	(0.39	)
Income from discontinued operations	—			—			—			0.01

Diluted loss per share	$	(0.95	)	$	(1.59	)	$	(1.58	)	$	(0.38	)

Basic shares outstanding	122			120			122			120
Diluted shares outstanding	122			121			122			121

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(193	)	$	(46	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization	209			172
Impairment and other charges	1			1
Losses from unconsolidated investments, net of cash distributions	—			34
Risk-management activities	127			8
Deferred income taxes	(135		)	(62		)
Other	24			30
Changes in working capital:
Accounts receivable	60			14
Inventory	(4		)	3
Broker margin account	(92		)	255
Prepayments and other assets	1			8
Accounts payable and accrued liabilities	(55		)	(36		)
Changes in non-current assets	(33		)	(17		)
Changes in non-current liabilities	4			4

Net cash provided by (used in) operating activities	(86		)	368

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(128		)	(201		)
Unconsolidated investments	—			(15		)
Maturities of short-term investments	217			27
Purchases of short-term investments	(247		)	(331		)
Decrease (increase) in restricted cash and investments	53			(10		)
Other investing	10			9

Net cash used in investing activities	(95		)	(521		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs	399			(5		)
Repayments of borrowings	(113		)	(31		)
Net proceeds from issuance of capital stock	3			—

Net cash provided by (used in) financing activities	289			(36		)

Net increase (decrease) in cash and cash equivalents	108			(189		)
Cash and cash equivalents, beginning of period	291			471

Cash and cash equivalents, end of period	$	399		$	282

Other non-cash investing activity:
Non-cash capital expenditures	$	(7	)	$	6

Other non-cash financing activity:
Deferred financing fees	$	(4	)		—

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 June 30,
	2011			2010

Net loss	$	(116	)	$	(191	)
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $1 and $1)	1			—

Other comprehensive income, net of tax	1			—

Comprehensive loss	$	(115	)	$	(191	)

	Six Months Ended June 30,
	2011			2010

Net loss	$	(193	)	$	(46	)
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $1 and $1)	2			2

Other comprehensive income, net of tax	2			2

Comprehensive loss	$	(191	)	$	(44	)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)

	June 30, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	354		$	253
Restricted cash and investments	878			81
Short-term investments	94			90
Accounts receivable, net of allowance for doubtful accounts of $12 and $13, respectively	168			229
Accounts receivable, affiliates	—			1
Inventory	125			121
Assets from risk-management activities	989			1,199
Deferred income taxes	4			3
Broker margin account	202			80
Prepayments and other current assets	136			123
Total Current Assets	2,950			2,180
Property, Plant and Equipment	8,700			8,593
Accumulated depreciation	(2,499		)	(2,320		)
Property, Plant and Equipment, Net	6,201			6,273
Other Assets
Restricted cash and investments	9			859
Assets from risk-management activities	84			72
Intangible assets	116			141
Other long-term assets	436			424
Total Assets	$	9,796		$	9,949

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	111		$	134
Accrued interest	51			36
Accrued liabilities and other current liabilities	85			106
Liabilities from risk-management activities	1,043			1,138
Notes payable and current portion of long-term debt	1,008			148
Total Current Liabilities	2,298			1,562
Long-term debt	3,852			4,426
Long-term debt, affiliates	200			200
Long-Term Debt	4,052			4,626
Other Liabilities
Liabilities from risk-management activities	123			99
Deferred income taxes	474			606
Other long-term liabilities	321			337
Total Liabilities	7,268			7,230
Commitments and Contingencies (Note 7)
Stockholder’s Equity
Capital Stock, $1 par value, 1,000 shares authorized at June 30, 2011 and December 31, 2010	—			—
Additional paid-in capital	5,135			5,135
Affiliate receivable	(812		)	(814		)
Accumulated other comprehensive loss, net of tax	(51		)	(53		)
Accumulated deficit	(1,744		)	(1,549		)
Total Stockholder’s Equity	2,528			2,719
Total Liabilities and Stockholder’s Equity	$	9,796		$	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 June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues	$	326		$	239		$	831		$	1,097
Cost of sales	(225		)	(231		)	(503		)	(539		)
Operating and maintenance expense, exclusive of depreciation shown separately below	(106		)	(118		)	(216		)	(231		)
Depreciation and amortization expense	(75		)	(90		)	(201		)	(165		)
Impairment and other charges	(1		)	(1		)	(1		)	(1		)
General and administrative expenses	(23		)	(28		)	(64		)	(59		)

Operating income (loss)	(104		)	(229		)	(154		)	102
Losses from unconsolidated investments	—			—			—			(34		)
Interest expense	(89		)	(91		)	(178		)	(180		)
Other income and expense, net	3			1			4			2

Loss from continuing operations before income taxes	(190		)	(319		)	(328		)	(110		)
Income tax benefit (Note 10)	75			128			133			56

Loss from continuing operations	(115		)	(191		)	(195		)	(54		)
Income from discontinued operations, net of taxes	—			—			—			1

Net loss	$	(115	)	$	(191	)	$	(195	)	$	(53	)

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(195	)	$	(53	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization	209			172
Impairment and other charges	1			1
Losses from unconsolidated investments, net of cash distributions	—			34
Risk-management activities	127			8
Deferred income taxes	(132		)	(55		)
Other	22			27
Changes in working capital:
Accounts receivable	60			19
Inventory	(4		)	3
Broker margin account	(92		)	255
Prepayments and other assets	1			8
Accounts payable and accrued liabilities	(54		)	(37		)
Changes in non-current assets	(33		)	(17		)
Changes in non-current liabilities	4			4

Net cash provided by (used in) operating activities	(86		)	369

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(128		)	(201		)
Unconsolidated investments	—			(15		)
Maturities of short-term investments	201			28
Purchases of short-term investments	(235		)	(316		)
Decrease (increase) in restricted cash and investments	53			(10		)
Affiliate transactions	—			(2		)
Other investing	10			8

Net cash used in investing activities	(99		)	(508		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs	399			(5		)
Repayments of borrowings	(113		)	(31		)

Net cash provided by (used in) financing activities	286			(36		)

Net increase (decrease) in cash and cash equivalents	101			(175		)
Cash and cash equivalents, beginning of period	253			419

Cash and cash equivalents, end of period	$	354		$	244

Other non-cash investing activity:
Non-cash capital expenditures	$	(7	)	$	6

Other non-cash financing activity:
Deferred financing fees	$	(4	)		—

See the notes to condensed consolidated financial statements.

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DYNEGY HOLDINGS INC.

CONDENSED CONSOLIDATED OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended June 30,
	2011			2010

Net loss	$	(115	)	$	(191	)
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $1 and $1)	1			—

Other comprehensive income, net of tax	1			—
Comprehensive loss	$	(114	)	$	(191	)

	Six Months Ended June 30,
	2011			2010

Net loss	$	(195	)	$	(53	)
Amortization of unrecognized prior service cost and actuarial gain (net of tax expense of $1 and $1)	2			2

Other comprehensive income, net of tax	2			2
Comprehensive loss	$	(193	)	$	(51	)

See the notes to condensed consolidated financial statements.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 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 report 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 presentation 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 and continue to negatively impact our projected future liquidity.

We recently completed a reorganization of our subsidiaries and in connection therewith, certain of our subsidiaries (GasCo and CoalCo, as defined in Note 13—Subsequent Events) entered into two new credit facilities on August 5, 2011 which resulted in the repayment in full and termination of commitments under DHI’s Fifth Amended and Restated Credit Agreement. However, these new credit facilities contain certain restrictions related to distributions to their respective parent companies, including Dynegy and DHI (please read Note 13—Subsequent Events for further discussion). Although these new credit facilities are designed to provide sufficient operating liquidity for GasCo and CoalCo for the foreseeable future, there still remain significant debt service requirements for the unsecured notes and debentures at DHI as well as the operating lease payment obligations related to the Danskammer and Roseton operating leases at a wholly-owned subsidiary of DHI. We currently project that we will have minimal liquidity at DHI subsequent to funding of the debt service requirements and operating lease payment obligations beyond the next eighteen months absent a significant positive change in the forecasted operating results of the Roseton and Danskammer facilities.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

The August 2011 reorganization represents our first step in addressing our liquidity concerns. Over the next eighteen months, under the strategic direction of the Finance and Restructuring Committee of Dynegy’s Board of Directors, we may participate in additional debt restructuring activities, which may include direct or indirect transfers of our subsidiaries’ equity interests, refinancing of existing debt and lease obligations, and/or further reorganizations of our subsidiaries as well as other similar initiatives. However, we cannot provide any assurances that we will be successful in accomplishing any such activities.

Our ability to continue as a going concern is dependent on many factors, including, among other things, GasCo and CoalCo generating sufficient positive operating results to enable GasCo and CoalCo to make certain restricted distributions to their parents (as described in Note 13—Subsequent Events), Roseton and Danskammer producing positive operating results, successfully executing any further restructuring strategies, and continuing 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.

Accounting Principles Not Yet Adopted

Fair Value Measurement Disclosures. In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04—Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU No. 2011-04”). This authoritative guidance changes the wording used to describe the requirements in GAAP for measuring fair value and for disclosing information about fair value measurements. ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We do not expect the implementation of this guidance to have a significant impact on our financial condition, results of operations or cash flows.

Presentation of Comprehensive Income. In June 2011, the FASB issued ASU 2011-05—Comprehensive Income (Topic 220): Presentation of Comprehensive Income (“ASU No. 2011-05”). The FASB’s objective in issuing this guidance is to improve the comparability, consistency, and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. ASU No. 2011-05 eliminates the option of presenting components of other comprehensive income as part of the statement of changes in stockholders’ equity. The standard requires that all nonowner changes in stockholders’ equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. ASU 2011-05 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We do not expect the implementation of this guidance to have a significant impact on our financial condition, results of operations or cash flows.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Note 2—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 June 30, 2011
	Cost Basis		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(in millions)
Available for Sale investments:
Commercial Paper	$	45	$	—	$	—	$	45
Certificates of Deposit	13		—		—		13
U.S. Treasury and Government Securities (1)	151		—		—		151

Total—DHI	$	209	$	—	$	—	$	209
Commercial Paper	2		—		—		2
Certificates of Deposit	8		—		—		8
Corporate Securities	2		—		—		2

Total—Dynegy	$	221	$	—	$	—	$	221

(1) Includes $115 million in Broker margin account on our unaudited condensed consolidated balance sheets in support of transactions with our futures clearing manager.

	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 and six months ended June 30, 2011, we received proceeds of $36 million from the sale of available for sale securities for which we realized less than $1 million of gains for the three and six months ended June 30, 2011.

Note 3—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.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

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. Increasing collateral requirements and our liquidity position 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.

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. As of June 30, 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 June 30, 2011, we had net long/(short) commodity derivative contracts 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	(39	)	MW	$	109
Natural gas (1)	Not designated	227		MMBtu	$	(187	)
Heat rate derivatives	Not designated	(4)/39		MW/MMBtu	$	(22	)
Other (2)	Not designated	3		Misc.	$	7

(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 June 30, 2011, of the approximately $202 million included in the Broker margin account on our unaudited condensed consolidated balance sheets, approximately $137 million represents Collateral and approximately $61 million represents Daily Cash Settlements. 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 offset by approximately $5 million of Daily Cash Settlements. We use short-term investments to collateralize a portion of our collateral requirements. The broker requires that we post approximately 103 percent of any collateral requirement collateralized with short-term investments. Accordingly, our Broker margin account includes approximately $3 million related to this requirement at June 30, 2011 and December 31, 2010. Additionally, we posted $1 million and $7 million of short-term investments which were not utilized as collateral at June 30, 2011 and December 31, 2010, respectively.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 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 June 30, 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	June 30, 2011			December 31, 2010
		(in millions)
Derivatives designated as hedging instruments:
Derivative Assets:
Interest rate contracts	Assets from risk management activities	$	—		$	1

Total derivatives designated as hedging instruments		—			1

Derivatives not designated as hedging instruments:
Derivative Assets:
Commodity contracts	Assets from risk management activities	1,073			1,265
Interest rate contracts	Assets from risk management activities	—			5
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities	(1,166		)	(1,231		)
Interest rate contracts	Liabilities from risk management activities	—			(6		)

Total derivatives not designated as hedging instruments		(93		)	33

Total derivatives, net		$	(93	)	$	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 and six months ended June 30, 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 and six months ended June 30, 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 derivatives and the corresponding hedged debt matured April 1, 2011. During the three and six months ended June 30, 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 the three and six months ended June 30, 2011 and 2010, there were no gains or losses related to the recognition of firm commitments that no longer qualified as fair value hedges.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

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 and six months ended June 30, 2011 and 2010 was immaterial.

Financial Instruments Not Designated as Hedges. We elect not to designate derivatives related to our power generation business and certain interest rate instruments as cash flow or fair value hedges. Thus, we account for changes in the fair value of these derivatives within the 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 June 30, 2011, our revenues included approximately $129 million of mark-to-market losses related to this activity compared to $258 million of mark-to-market losses in the same period in the prior year. For the six months ended June 30, 2011, our revenues included approximately $127 million of mark-to-market losses related to this activity compared to $5 million of mark-to-market losses in the same period in the prior year.

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the three months ended June 30, 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 margin we expect to realize when the underlying physical transactions settle.

Derivatives Not Designated as	Location of Loss Recognized in Income on	Amount of Loss Recognized in Income on Derivatives for the Three Months Ended June 30,
Hedging Instruments	Derivatives	2011			2010
		(in millions)
Commodity contracts	Revenues	$	(89	)	$	(185	)

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statement of operations for the six months ended June 30, 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 margin we expect to realize when the underlying physical transactions settle.

Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in Income on	Amount of Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended June 30,
Instruments	Derivatives	2011			2010
		(in millions)
Commodity contracts	Revenues	$	(70	)	$	140

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Note 4—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 June 30, 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 June 30, 2011
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—	$	325		$	48		$	373
Natural gas derivatives	—		658			—			658
Other derivatives	—		42			—			42

Total assets from commodity risk management activities		—		1,025			48			1,073
DHI Short-term investments:
Commercial paper	—		45			—			45
Certificates of deposit	—		13			—			13
U.S. Treasury and government securities (1)	—		151			—			151

Total—DHI short-term investments	—		209			—			209

Total—DHI	—		1,234			48			1,282

Dynegy Short-term investments:
Commercial paper	—		2			—			2
Corporate Securities	—		2			—			2
Certificates of deposit	—		8			—			8

Total—Dynegy	$	—	$	1,246		$	48		$	1,294

Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(250	)	$	(13	)	$	(263	)
Natural gas derivatives	—		(845		)	—			(845		)
Heat rate derivatives	—		—			(23		)	(23		)
Other derivatives	—		(35		)	—			(35		)

Total—Dynegy and DHI	$	—	$	(1,130	)	$	(36	)	$	(1,166	)

(1) Includes $115 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 June 30, 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
DHI 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

Dynegy 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—Dynegy and DHI	$	—	$	(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 June 30, 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 June 30, 2011
	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Total
	(in millions)
Balance at March 31, 2011	$	48		$	5		$	(26	)	$	27
Total losses included in earnings	(12		)	(5		)	(1		)	(18		)
Settlements	(1		)	—			4			3

Balance at June 30, 2011	$	35		$	—		$	(23	)	$	12

Unrealized losses relating to instruments held as of June 30, 2011	$	(5	)	$	(4	)	$	(2	)	$	(11	)

	Six Months Ended June 30, 2011
	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Total
	(in millions)
Balance at December 31, 2010	$	49		$	5		$	(31	)	$	23
Total losses included in earnings	(8		)	(5		)	—			(13		)
Settlements	(6		)	—			8			2

Balance at June 30, 2011	$	35		$	—		$	(23	)	$	12

Unrealized gains (losses) relating to instruments held as of June 30, 2011	$	2		$	(3	)	$	—		$	(1	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

	Three Months Ended June 30, 2010
	Electricity Derivatives			Natural Gas Derivatives		Heat Rate Derivatives			Total
	(in millions)
Balance at March 31, 2010	$	70		$	5	$	20		$	95
Total losses included in earnings	(35		)	—		(7		)	(42		)
Sales and settlements:
Sales	(3		)	—		(20		)	(23		)
Settlements	(9		)	—		(16		)	(25		)

Balance at June 30, 2010	$	23		$	5	$	(23	)	$	5

Unrealized losses relating to instruments still held as of June 30, 2010	$	(40	)	$	—	$	(11	)	$	(51	)

	Six Months Ended June 30, 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	43			—		11			—			54
Purchases, sales and settlements:
Purchases	1			—		1			—			2
Sales	(13		)	—		(21		)	—			(34		)
Settlements	(14		)	—		(31		)	—			(45		)

Balance at June 30, 2010	$	23		$	5	$	(23	)	$	—		$	5

Unrealized gains relating to instruments still held as of June 30, 2010	$	33		$	—	$	2		$	—		$	35

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 and six months ended June 30, 2011 and 2010.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 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 June 30, 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 reflected 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 because 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 were 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 June 30, 2011 and 2010

The carrying values of financial assets and liabilities (cash, accounts receivable, restricted cash, 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 June 30, 2011 and December 31, 2010, respectively.

	June 30, 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
Interest rate derivatives not designated as accounting hedges (1)	—			—			(1		)	(1		)
Commodity-based derivative contracts not designated as accounting hedges (1)	(93		)	(93		)	34			34
Term Loan B, due 2013	(68		)	(66		)	(68		)	(67		)
Term Facility, floating rate due 2013	(850		)	(832		)	(850		)	(845		)
Revolver Facility	(400		)	(392		)	—			—
Senior Notes and Debentures:
6.875 percent due 2011 (2)	—			—			(80		)	(79		)
8.75 percent due 2012	(89		)	(88		)	(89		)	(87		)
7.5 percent due 2015 (3)	(770		)	(633		)	(768		)	(592		)
8.375 percent due 2016 (4)	(1,043		)	(835		)	(1,043		)	(777		)
7.125 percent due 2018	(173		)	(120		)	(172		)	(116		)
7.75 percent due 2019	(1,100		)	(799		)	(1,100		)	(728		)
7.625 percent due 2026	(171		)	(112		)	(171		)	(107		)
Subordinated Debentures payable to affiliates, 8.316 percent, due 2027	(200		)	(101		)	(200		)	(83		)
Sithe Senior Notes, 9.0 percent due 2013 (5)	(197		)	(195		)	(233		)	(233		)
Other—DHI (6)	209			209			175			175
Other—Dynegy (7)	12			12			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 $15 million and $17 million at June 30, 2011 and December 31, 2010, respectively.

(4) Includes unamortized discounts of $3 million and $4 million at June 30, 2011 and December 31, 2010, respectively.

(5) Includes unamortized premiums of $6 million and $8 million at June 30, 2011 and December 31, 2010, respectively.

(6) Other represents short-term investments, including $115 million and $85 million of short-term investments included in the Broker margin account at June 30, 2011 and December 31, 2010, respectively.

(7) Other represents short-term investments at June 30, 2011 and December 31, 2010.

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For the Interim Periods Ended June 30, 2011 and 2010

Note 5—Accumulated Other Comprehensive Loss

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

	June 30, 2011			December 31, 2010
	(in millions)
Cash flow hedging activities, net	$	3		$	3
Unrecognized prior service cost and actuarial loss, net	(54		)	(56		)

Accumulated other comprehensive loss, net of tax	$	(51	)	$	(53	)

Note 6—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 4—Fair Value Measurements for further discussion.

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

	Three Months Ended June 30, 2010
	Total			Equity Share
	(in millions)
Revenues	$	—		$	—
Operating loss	(1		)	—
Net loss	(42		)	—

	Six Months Ended June 30, 2010
	Total			Equity Share
	(in millions)
Revenues	$	—		$	—
Operating loss	(2		)	—
Net income (loss)	(33		)	3

During the second quarter of 2010, we did not recognize our share of losses from our investment in PPEA Holding as our investment in PPEA Holding was valued at zero at June 30, 2010, and we did not have an obligation to provide further financial support.

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For the Interim Periods Ended June 30, 2011 and 2010

Losses from unconsolidated investments for the six months ended June 30, 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.

Note 7—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.

Restructuring Litigation. On July 21, 2011, certain holders of obligations with potential recourse rights to DHI initiated legal proceedings seeking to enjoin Dynegy Inc.’s restructuring efforts previously disclosed on July 10, 2011. The lawsuits, Libertyview Credit Opportunities Fund, L.P. et al v. Dynegy Holdings, Inc., (Index No. 651998/11) in the Supreme Court of the State of New York (the “New York Action”) and Roseton OL, LLC and Danskammer OL, LLC v. Dynegy Holdings, Inc., (C.A. No. 6689-VCP) in the Court of Chancery of the State of Delaware (the “Delaware Action”), seek to enjoin the proposed reorganization based on purported breaches of guarantees issued by DHI in connection with two sale lease back transactions in which DHI’s subsidiaries, Dynegy Roseton, L.L.C. and Dynegy Danskammer, L.L.C., leased certain power-generating facilities located in Newburgh, New York. Shortly after filing, the New York Action was stayed pending resolution of the Delaware Action. The plaintiffs in the Delaware Action filed a motion for a temporary restraining order (“TRO”) to enjoin the Reorganization on July 21, 2011. DHI opposed the motion by arguing, among other things, that the unambiguous language of the Guaranties expressly permits the reorganization. On July 29, 2011, the Delaware court denied the TRO in the Delaware Action, finding that plaintiffs had failed to show a likelihood of success on the merits, irreparable harm or that the balancing of the equities weighed in their favor. Thereafter, plaintiffs sought certification of an interlocutory appeal, which was denied by the Delaware Chancery Court on August 4, 2011 and subsequently denied by the Delaware Supreme Court on August 5, 2011. Absent any injunction, the Company closed its restructuring and refinancing on August 5, 2011. We believe plaintiffs’ claims in the New York Action and Delaware Action are without merit and we will continue to oppose any further efforts to challenge the restructuring.

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.

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For the Interim Periods Ended June 30, 2011 and 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 July 2011, the Court granted the motion and awarded approximately $1.6 million in fees and expenses. Dynegy intends to appeal the decision.

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. All of the pending 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.

On July 18, 2011, the Court granted defendants’ motions for summary judgment, thereby dismissing all of plaintiffs’ state law claims. Plaintiffs recently filed notices of appeal.

Plaintiff in one of the pending actions, Multiut Corporation v. Dynegy, Inc. et al, had previously filed similar claims under federal law, which are not subject to the Court’s July 18, 2011 order. Multiut Corporation is presently proceeding before the United States Bankruptcy Court for the Northern District of Illinois, Eastern Division having petitioned for Chapter 11 in May 2009. In April 2011, the bankruptcy court denied confirmation of Multiut’s proposed plan of reorganization and entered an order converting the case under Chapter 7 of the bankruptcy code and appointed a Trustee to oversee the liquidation of Mulitut’s assets, one of which is Multiut’s claim against Dynegy in the gas index litigation. Dynegy is the largest creditor in that proceeding and intends to discuss the Nevada court’s July 18 order with the Trustee. We believe Multiut’s remaining federal claims lack merit and we will continue to oppose plaintiff’s claims vigorously.

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.

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· 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. The Supreme Court of California held oral argument in this case on May 24, 2011, and we await a ruling from the court. 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.

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 the United States Supreme Court’s ruling in Connecticut v. AEP. On June 20, 2011, the Supreme Court issued its decision in Connecticut v. AEP. The Court was equally divided by a vote of 4-4 on the question of whether the plaintiffs had standing to bring the suit and, therefore, affirmed the court’s exercise of jurisdiction. On the merits the Court ruled by a vote of 8-0 that the CAA and EPA action authorized by the Act displace any federal common law right to seek abatement of carbon dioxide emissions from fossil fuel-fired power plants. In response to the Supreme Court’s decision, a motion has been filed in Kivalina to allow supplemental briefing addressing the effect of the Connecticut v. AEP decision. 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 June 30, 2011.

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(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

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 $1 million as of June 30, 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.

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 and ultimately remanded back to FERC for further review. On May 24, 2011 and May 26, 2011, FERC issued two orders in these dockets. The first order denied the request of the California Parties for consolidation of various dockets and denied their request for summary disposition on market manipulation issues. The second order addressed treatment of settled parties and the scope of hearing issues in the ongoing proceedings.

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For the Interim Periods Ended June 30, 2011 and 2010

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 June 30, 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 June 30, 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.

Note 8—Debt

DHI’s Credit Facility

During the second quarter 2011, we borrowed $400 million under DHI’s Fifth Amended and Restated Credit Agreement. This borrowing was repaid on August 5, 2011 in connection with the closing of the two new credit facilities entered into as part of the August 2011 Reorganization as defined in Note 13—Subsequent Events. In addition, DHI’s term facility of $850 million was repaid with current restricted cash and the term loan of $68 million was repaid using proceeds from the GasCo Term Loan Facility. The $400 million and $68 million were classified as long-term debt on our unaudited condensed consolidated balance sheets as these amounts were refinanced on a long-term basis. Please read Note 13—Subsequent Events for further discussion.

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(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Senior Notes and Debentures

We made scheduled repayments of $80 million during the second quarter 2011.

Subordinated Debentures

As permitted under the indenture, we have deferred our $8 million June 2011 payment of interest on the Subordinated Debentures.

Sithe Senior Notes

We made scheduled repayments of $33 million during the second quarter 2011.

Note 9—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 June 30,
	2011			2010			2011		2010
	(in millions)
Service cost benefits earned during period	$	3		$	3		$	—	$	—
Interest cost on projected benefit obligation	3			4			1		1
Expected return on plan assets	(4		)	(4		)	—		—
Recognized net actuarial loss	2			1			—		—

Net periodic benefit cost	$	4		$	4		$	1	$	1

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(Unaudited)

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	Pension Benefits						Other Benefits
	Six Months Ended June 30,
	2011			2010			2011		2010
	(in millions)
Service cost benefits earned during period	$	6		$	6		$	1	$	1
Interest cost on projected benefit obligation	7			7			2		2
Expected return on plan assets	(8		)	(8		)	—		—
Recognized net actuarial loss	3			2			—		—

Net periodic benefit cost	$	8		$	7		$	3	$	3

Contributions. During the six months ended June 30, 2011 and 2010, we made $6 million in contributions to our pension plans or other postretirement benefit plans. We expect to make contributions of approximately $12 million to our pension plans and $2 million to other benefit plans during 2011.

Note 10—Income Taxes

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions, except rates)
Income tax benefit	$	76		$	128		$	136		$	63

Effective tax rate	40		%	40		%	41		%	57		%

For the three months ended June 30, 2011 and 2010, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to the impact of state taxes.

For the six months ended June 30, 2011, Dynegy’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to the impact of state taxes which included a benefit of $9 million related to an increase in state NOLs due to the acceptance of amended returns, partially offset by an expense of $3 million related to an increase in the Illinois statutory rate. For the six months ended June 30, 2010, the overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to a benefit of $18 million related to the release of reserves for uncertain tax positions, partially offset by the impact of state taxes.

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For the Interim Periods Ended June 30, 2011 and 2010

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions, except rates)
Income tax benefit	$	75		$	128		$	133		$	56

Effective tax rate	39		%	40		%	41		%	51		%

For the three months ended June 30, 2011 and 2010, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to the impact of state taxes.

For the six months ended June 30, 2011, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to the impact of state taxes which included a benefit of $6 million related to an increase in state NOLs due to the acceptance of amended returns, partially offset by an expense of $2 million related to an increase in the Illinois statutory rate. For the six months ended June 30, 2010, DHI’s overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to a benefit of $12 million related to the release of reserves for uncertain tax positions, partly offset by the impact of state taxes.

Note 11—Dynegy’s Loss Per Share

Basic loss per share represents the amount of losses for the period available to each share of our common stock outstanding during the period. Diluted loss per share represents the amount of losses for the period available to each share of our 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.

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(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions, except per share amounts)
Loss from continuing operations for basic and diluted loss per share	$	(116	)	$	(191	)	$	(193	)	$	(47	)

Basic weighted-average shares	122			120			122			120
Effect of dilutive securities:
Stock options and restricted stock	—			1			—			1
Diluted weighted-average shares	122			121			122			121

Loss per share from continuing operations:

Basic	$	(0.95	)	$	(1.59	)	$	(1.58	)	$	(0.39	)
Diluted (1)	$	(0.95	)	$	(1.59	)	$	(1.58	)	$	(0.39	)

(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, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and six months ended June 30, 2011 and 2010.

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For the Interim Periods Ended June 30, 2011 and 2010

Note 12—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 and six months ended June 30, 2011 and 2010 is presented below:

Dynegy’s Segment Data as of and for the Three Months Ended June 30, 2011

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	195		$	19		$	112		$	—		$	326
Total revenues	$	195		$	19		$	112		$	—		$	326
Depreciation and amortization	$	(50	)	$	(16	)	$	(7	)	$	(2	)	$	(75	)
Impairment and other charges	—			—			(1		)	—			(1		)
Operating loss	$	(37	)	$	(19	)	$	(21	)	$	(29	)	$	(106	)
Other items, net	2			1			—			—			3
Interest expense													(89		)
Loss from continuing operations before income taxes													(192		)
Income tax benefit													76
Net loss													$	(116	)
Identifiable assets:
Domestic	$	5,026		$	1,803		$	1,575		$	1,459		$	9,863
Total	$	5,026		$	1,803		$	1,575		$	1,459		$	9,863
Capital expenditures	$	(49	)	$	(9	)	$	(4	)	$	—		$	(62	)

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Dynegy’s Segment Data as of and for the Three Months Ended June 30, 2010

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	63		$	71		$	105		$	—		$	239

Total revenues	$	63		$	71		$	105		$	—		$	239

Depreciation and amortization	$	(63	)	$	(17	)	$	(8	)	$	(2	)	$	(90	)
Impairment and other charges	—			—			(1		)	—			(1		)

Operating loss	$	(165	)	$	(9	)	$	(26	)	$	(29	)	$	(229	)

Other items, net	—			—			—			1			1
Interest expense													(91		)

Loss from continuing operations before income taxes													(319		)
Income tax benefit													128

Net loss													$	(191	)

Identifiable assets:
Domestic	$	5,282		$	2,112		$	1,768		$	1,410		$	10,572
Other	—			—			—			24			24

Total	$	5,282		$	2,112		$	1,768		$	1,434		$	10,596

Capital expenditures and investments in unconsolidated affiliates	$	(108	)	$	(2	)	$	(2	)	$	(3	)	$	(115	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Dynegy’s Segment Data as of and for the Six Months Ended June 30, 2011

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	475		$	81		$	275		$	—		$	831
Total revenues	$	475		$	81		$	275		$	—		$	831
Depreciation and amortization	$	(150	)	$	(33	)	$	(14	)	$	(4	)	$	(201	)
Impairment and other charges	—			—			(1		)	—			(1		)
Operating loss	$	(40	)	$	(18	)	$	(26	)	$	(71	)	$	(155	)
Other items, net	2			1			—			1			4
Interest expense													(178		)
Loss from continuing operations before income taxes													(329		)
Income tax benefit													136
Net loss													$	(193	)
Identifiable assets:
Domestic	$	5,026		$	1,803		$	1,575		$	1,459		$	9,863
Total	$	5,026		$	1,803		$	1,575		$	1,459		$	9,863
Capital expenditures	$	(93	)	$	(14	)	$	(21	)	$	—		$	(128	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Dynegy’s Segment Data as of and for the Six Months Ended June 30, 2010

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	549		$	214		$	334		$	—		$	1,097

Total revenues	$	549		$	214		$	334		$	—		$	1,097

Depreciation and amortization	$	(113	)	$	(33	)	$	(16	)	$	(3	)	$	(165	)
Impairment and other charges	—			—			(1		)	—			(1		)

Operating income (loss)	$	95		$	36		$	34		$	(63	)	$	102

Losses from unconsolidated investments	(34		)	—			—			—			(34		)
Other items, net	—			—			1			1			2
Interest expense													(180		)

Loss from continuing operations before income taxes													(110		)
Income tax benefit													63

Loss from continuing operations													(47		)
Income from discontinued operations, net of taxes													1

Net loss													$	(46	)

Identifiable assets:
Domestic	$	5,282		$	2,112		$	1,768		$	1,410		$	10,572
Other	—			—			—			24			24

Total	$	5,282		$	2,112		$	1,768		$	1,434		$	10,596

Capital expenditures and investments in unconsolidated affiliates	$	(197	)	$	(10	)	$	(5	)	$	(4	)	$	(216	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Reportable segment information for DHI, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2011 and 2010 is presented below:

DHI’s Segment Data as of and for the Three Months Ended June 30, 2011

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	195		$	19		$	112		$	—		$	326

Total revenues	$	195		$	19		$	112		$	—		$	326

Depreciation and amortization	$	(50	)	$	(16	)	$	(7	)	$	(2	)	$	(75	)
Impairment and other charges	$	—		$	—		$	(1	)	$	—		$	(1	)

Operating loss	$	(37	)	$	(19	)	$	(21	)	$	(27	)	$	(104	)

Other items, net	2			1			—			—			3
Interest expense													(89		)

Loss from continuing operations before income taxes													(190		)
Income tax benefit													75
Net loss													$	(115	)

Identifiable assets:
Domestic	$	5,026		$	1,803		$	1,575		$	1,392		$	9,796

Total	$	5,026		$	1,803		$	1,575		$	1,392		$	9,796

Capital expenditures	$	(49	)	$	(9	)	$	(4	)	$	—		$	(62	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

DHI’s Segment Data as of and for the Three Months Ended June 30, 2010

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	63		$	71		$	105		$	—		$	239

Total revenues	$	63		$	71		$	105		$	—		$	239

Depreciation and amortization	$	(63	)	$	(17	)	$	(8	)	$	(2	)	$	(90	)
Impairment and other charges	—			—			(1		)	—			(1		)

Operating loss	$	(165	)	$	(9	)	$	(26	)	$	(29	)	$	(229	)

Other items, net	—			—			—			1			1
Interest expense													(91		)

Loss from continuing operations before income taxes													(319		)
Income tax benefit													128

Net loss													$	(191	)

Identifiable assets:
Domestic	$	5,282		$	2,112		$	1,768		$	1,353		$	10,515
Other	—			—			—			24			24

Total	$	5,282		$	2,112		$	1,768		$	1,377		$	10,539

Capital expenditures and investments in unconsolidated affiliates	$	(108	)	$	(2	)	$	(2	)	$	(3	)	$	(115	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

DHI’s Segment Data as of and for the Six Months Ended June 30, 2011

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	475		$	81		$	275		$	—		$	831

Total revenues	$	475		$	81		$	275		$	—		$	831

Depreciation and amortization	$	(150	)	$	(33	)	$	(14	)	$	(4	)	$	(201	)
Impairment and other charges	$	—		$	—		$	(1	)	$	—		$	(1	)

Operating loss	$	(40	)	$	(18	)	$	(26	)	$	(70	)	$	(154	)

Other items, net	2			1			—			1			4
Interest expense													(178		)

Loss from continuing operations before income taxes													(328		)
Income tax benefit													133
Net loss													$	(195	)

Identifiable assets:
Domestic	$	5,026		$	1,803		$	1,575		$	1,392		$	9,796

Total	$	5,026		$	1,803		$	1,575		$	1,392		$	9,796

Capital expenditures	$	(93	)	$	(14	)	$	(21	)	$	—		$	(128	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

DHI’s Segment Data as of and for the Six Months Ended June 30, 2010

(in millions)

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
Unaffiliated revenues:
Domestic	$	549		$	214		$	334		$	—		$	1,097

Total revenues	$	549		$	214		$	334		$	—		$	1,097

Depreciation and amortization	$	(113	)	$	(33	)	$	(16	)	$	(3	)	$	(165	)
Impairment and other charges	—			—			(1		)	—			(1		)

Operating income (loss)	$	95		$	36		$	34		$	(63	)	$	102

Losses from unconsolidated investments	(34		)	—			—			—			(34		)
Other items, net	—			—			1			1			2
Interest expense													(180		)

Loss from continuing operations before income taxes													(110		)
Income tax benefit													56

Loss from continuing operations													(54		)
Income from discontinued operations, net of taxes													1

Net loss													$	(53	)

Identifiable assets:
Domestic	$	5,282		$	2,112		$	1,768		$	1,353		$	10,515
Other	—			—			—			24			24

Total	$	5,282		$	2,112		$	1,768		$	1,377		$	10,539

Capital expenditures and investments in unconsolidated affiliates	$	(197	)	$	(10	)	$	(5	)	$	(4	)	$	(216	)

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Note 13—Subsequent Events

Reorganization

In August 2011, we completed a reorganization of our subsidiaries (the “Reorganization”), whereby, (i) substantially all of our coal-fired power generation facilities are held by Dynegy Midwest Generation, LLC (“DMG” or “CoalCo”), (ii) substantially all of our natural gas-fired power generation facilities are held by Dynegy Power, LLC (“DPC” or “GasCo”) and (iii) 100 percent of the ownership interests of Dynegy Northeast Generation (“DNE”), the entity that indirectly holds the equity interest in the subsidiaries that operate the Roseton and Danskammer power generation facilities, are held by DHI. As a result of the Reorganization, GasCo owns a portfolio of eight primarily natural gas-fired intermediate (combined cycle) and peaking (combustion and steam turbines) power generation facilities diversified across the West, Midwest and Northeast regions of the United States, totaling 6,771 MW of generating capacity. CoalCo owns a portfolio of six primarily coal-fired baseload power generation facilities located in the Midwest, totaling 3,132 MW of generating capacity. GasCo and CoalCo are indirect wholly owned subsidiaries of DHI and were designed to be separately financeable. GasCo and CoalCo are bankruptcy remote in order to accommodate the financings reflected by the credit facilities (as described below) and to provide us with greater flexibility in our efforts to address leverage and liquidity issues and to realize value of our assets. Our remaining assets (including our leasehold interests in the Danskammer and Roseton facilities) are not a part of either GasCo or CoalCo.

New Credit Facilities

We completed the Reorganization of our legal entity structures, as noted above, to facilitate the execution of two new credit facilities. The new credit facilities, which were entered into on August 5, 2011, consist of a $1,100 million, five year senior secured term loan facility available to GasCo and a $600 million, five year senior secured term loan facility available to CoalCo.

GasCo Term Loan Facility. On August 5, 2011, Dynegy Power, LLC, (defined above as DPC or GasCo), entered into a $1,100 million senior secured term loan facility (the “GasCo Term Loan Facility”) with Credit Suisse AG, Cayman Islands Branch, as Administrative Agent and as Collateral Trustee, Credit Suisse Securities (USA) LLC and Goldman Sachs Lending Partners LLC, as Joint Bookrunners and Joint Lead Arrangers, Barclays Capital, the investment banking division of Barclays Bank PLC, as Co-Manager, other agents named therein and other financial institutions party thereto as lenders.

The GasCo Term Loan Facility is a senior secured term loan facility with an aggregate principal amount of $1,100 million, which was available in a single drawing on the closing date. Amounts borrowed under the GasCo Term Loan Facility that are repaid or prepaid may not be re-borrowed. The GasCo Term Loan Facility will mature on August 5, 2016 and will amortize in equal quarterly installments in aggregate annual amounts equal to 1.00 percent of the original principal amount of the GasCo Term Loan Facility with the balance payable on the fifth anniversary of the closing date.

The proceeds of borrowings under the GasCo Term Loan Facility were or will be used by GasCo to (i) repay an intercompany obligation of a GasCo subsidiary to DHI and ultimately to repay certain outstanding indebtedness under DHI’s Fifth Amended and Restated Credit Agreement, (ii) fund cash collateralized letters of credit and provide cash collateral for existing and future collateral requirements, (iii) at the option of GasCo, repay up to approximately $192 million of debt relating to Sithe Energies, Inc. (the intermediate project holding company that indirectly holds the Independence facility in New York), (iv) make a $200 million restricted payment to a parent holding company of GasCo, (v) pay related transaction fees and expenses and (vi) fund additional cash to the balance sheet to provide the GasCo portfolio with liquidity for general working capital and liquidity purposes. Proceeds of borrowings under the GasCo Term Loan Facility, to the extent in excess of the immediate needs described in the preceding sentence, may be held as cash or cash equivalents until used by GasCo for the purposes described above (including cash collateralizing letters of credit, the payment of dividends or other restricted payments in accordance with, and subject to the limitations in the terms of, the GasCo Term Loan Facility or other general corporate purposes of GasCo).

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

All obligations of GasCo under (i) the GasCo Term Loan Facility (the “GasCo Borrower Obligations”) and (ii) at the election of GasCo, (x) cash management arrangements and (y) interest rate protection, commodity trading or hedging or other permitted hedging or swap arrangements (the “Hedging/Cash Management Arrangements”) will be unconditionally guaranteed jointly and severally on a senior secured basis (the “GasCo Guarantees”) by each existing and subsequently acquired or organized direct or indirect material domestic subsidiary of GasCo (the “GasCo Guarantors”), in each case, as otherwise permitted by applicable law, regulation and contractual provision and to the extent such guarantee would not result in adverse tax consequences as reasonably determined by GasCo. None of GasCo’s parent companies is obligated to repay the GasCo Borrower Obligations.

The GasCo Borrower Obligations, the GasCo Guarantees and any Hedging/Cash Management Arrangements will be secured by first priority liens on and security interests in 100 percent of the capital stock of GasCo (as discussed below) and substantially all of the present and after-acquired assets of GasCo and each GasCo Guarantor (collectively, the “GasCo Collateral”). Accordingly, such assets are only available for the creditors of GasCo Intermediate Holdings and its subsidiaries. The GasCo Collateral excludes certain assets, including, so long as any Sithe debt remains outstanding, the equity and assets of Sithe/Independence Power Partners, L.P. and Sithe/Independence Funding Corp. (such equity and assets to be subject to the lien in favor of GasCo secured parties as soon as the Sithe debt is repaid and any necessary consents are obtained).

The GasCo Term Loan Facility bears interest, at GasCo’s option, at either (a) 7.75 percent per annum plus LIBOR, subject to a LIBOR floor of 1.50 percent, with respect to any Eurodollar Term Loan or (b) 6.75 percent per annum plus the alternate base rate with respect to any ABR Term Loan. GasCo may elect from time to time to convert all or a portion of the Term Loan from any ABR Borrowing into a Eurodollar Borrowing or vice versa. With some exceptions, the GasCo Term Loan Facility is non-callable for the first two years and is subject to a prepayment premium.

The GasCo Term Loan Facility contains mandatory prepayment provisions. The GasCo Term Loan Facility shall be prepaid (a) with 100 percent of the net cash proceeds of all asset sales by GasCo and its subsidiaries and subject to the right of GasCo to reinvest such proceeds if such proceeds are reinvested (or committed to be reinvested) within 12 months and, if so committed to reinvestment, reinvested within six months after such initial 12 month period, (b) 50 percent of the net cash proceeds of issuance of equity securities of GasCo and its subsidiaries (except to the extent used for permitted capital expenditures), (c) commencing with the first full fiscal year of GasCo to occur after the closing date, 100 percent of the excess cash flow; provided that (i) excess cash flow shall be determined after reduction for amounts used for capital expenditures and restricted payments and (ii) any voluntary prepayments of the term loans shall be credited against excess cash flow prepayment obligations, (d) 100 percent of the net cash proceeds of issuances, offerings or placements of debt obligations of GasCo and its subsidiaries (other than all permitted debt), and (e) 100 percent of the principal amount of Sithe Debt which remains outstanding on the six-month anniversary of the closing date. Notwithstanding the above, the proceeds of the sale of 20 percent of the membership interests in GasCo are not required to be used to prepay the GasCo Term Loan Facility.

The GasCo Term Loan Facility contains customary events of default and affirmative and negative covenants including, subject to certain specified exceptions, limitations on amendments to constitutive documents, liens, capital expenditures, acquisitions, subsidiaries and joint ventures, investments, the incurrence of debt, fundamental changes, asset sales, sale-leaseback transactions, hedging arrangements, restricted payments, changes in nature of business, transactions with affiliates, burdensome agreements, amendments of debt and other material agreements, accounting changes and prepayment of indebtedness or repurchases of equity interests.

The GasCo Term Loan Facility limits distributions to $135 million per year provided the distributing entity maintains at least $50 million of liquidity immediately after giving effect to the distribution.

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

CoalCo Term Loan Facility. Also, on August 5, 2011, Dynegy Midwest Generation, LLC, (defined above as DMG or CoalCo), entered into a $600 million senior secured term loan facility (the “CoalCo Term Loan Facility”) with Credit Suisse AG, Cayman Islands Branch as Administrative Agent and as Collateral Trustee, Credit Suisse Securities (USA) LLC and Goldman Sachs Lending Partners LLC, as Joint Bookrunners and Joint Lead Arrangers, Barclays Capital, the investment banking division of Barclays Bank PLC, as Co-Manager, other agents named therein and other financial institutions party thereto as lenders.

The CoalCo Term Loan Facility is a senior secured term loan facility with an aggregate principal amount of $600 million, which was available in a single drawing on the closing date. Amounts borrowed under the CoalCo Term Loan Facility that are repaid or prepaid may not be re-borrowed. The CoalCo Term Loan Facility will mature on August 5, 2016 and will amortize in equal quarterly installments in aggregate annual amounts equal to 1.00 percent of the original principal amount of the CoalCo Term Loan Facility with the balance payable on the fifth anniversary of the closing date.

The proceeds of borrowings under the CoalCo Term Loan Facility were or will be used by CoalCo, to (i) fund cash collateralized letters of credit and provide cash collateral for existing and future collateral requirements, (ii) make a $200 million restricted payment to a parent holding company of CoalCo, (iii) pay related transaction fees and expenses and (iv) fund additional cash to the balance sheet to provide the CoalCo portfolio with cash to be used for general working capital and general corporate purposes. Proceeds of borrowings under the CoalCo Term Loan Facility, to the extent in excess of the immediate needs described in the preceding sentence, may be held as cash or cash equivalents until used by CoalCo for the purposes described above (including cash collateralizing letters of credit, the payment of dividends in amounts to be agreed or other restricted payments in accordance with, and subject to the limitations in the terms of, the CoalCo Term Loan Facility or other general corporate purposes for CoalCo).

All obligations of CoalCo under (i) the CoalCo Term Loan Facility (the “CoalCo Borrower Obligations”) and (ii) at the election of CoalCo, Hedging/Cash Management Arrangements will be unconditionally guaranteed jointly and severally on a senior secured basis (the “CoalCo Guarantees”) by each existing and subsequently acquired or organized direct or indirect material domestic subsidiary of CoalCo (the “CoalCo Guarantors”), in each case, as otherwise permitted by applicable law, regulation and contractual provision and to the extent such guarantee would not result in adverse tax consequences as reasonably determined by CoalCo. None of CoalCo’s parent companies is obligated to repay the CoalCo Borrower Obligations.

The CoalCo Borrower Obligations, the CoalCo Guarantees and any Hedging/Cash Management Arrangements will be secured by first priority liens on and security interests in 100 percent of the capital stock of CoalCo and substantially all of the present and after-acquired assets of CoalCo and each CoalCo Guarantor. Accordingly, such assets are only available for the creditors of CoalCo Intermediate Holdings and its subsidiaries.

The CoalCo Term Loan Facility bears interest, at CoalCo’s option, at either (a) 7.75 percent per annum plus LIBOR, subject to a LIBOR floor of 1.50 percent, with respect to any Eurodollar Term Loan or (b) 6.75 percent per annum plus the alternate base rate with respect to any ABR Term Loan. CoalCo may elect from time to time to convert all or a portion of the Term Loan from any ABR Borrowing into a Eurodollar Borrowing or vice versa. With some exceptions, the CoalCo Term Loan Facility is non-callable for the first two years and is subject to a prepayment premium.

The CoalCo Term Loan Facility contains mandatory prepayment provisions. The Term Loans shall be prepaid (a) with 100 percent of the net cash proceeds of all asset sales by CoalCo and its subsidiaries and subject to the right of CoalCo to reinvest such proceeds if such proceeds are reinvested (or committed to be reinvested) within 12 months and, if so committed to reinvestment, reinvested within six months after such initial 12 month period, (b) 50 percent of the net cash proceeds of issuance of equity securities of CoalCo and its subsidiaries (except to the extent used (x) to prepay the Loans, (y) for capital expenditures and (z) for permitted acquisitions), (c) commencing with the first full fiscal year of CoalCo to occur after the closing date, 100 percent of the excess cash flow; provided that (i) excess cash flow shall be determined after reduction for amounts used for capital expenditures, and restricted payments made and (ii) any voluntary prepayments of the term loans shall be credited against excess cash flow prepayment obligations and (d) 100 percent of the net cash proceeds of issuances, offerings or placements of debt obligations of CoalCo and its subsidiaries (other than all permitted debt).

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

The CoalCo Term Loan Facility contains customary events of default and affirmative and negative covenants including, subject to certain specified exceptions, limitations on amendments to constitutive documents, liens, capital expenditures, acquisitions, subsidiaries and joint ventures, investments, the incurrence of debt, fundamental changes, asset sales, sale-leaseback transactions, hedging arrangements, restricted payments, changes in nature of business, transactions with affiliates, burdensome agreements, amendments of debt and other material agreements, accounting changes and prepayment of indebtedness or repurchases of equity interests.

The CoalCo Term Loan Facility limits distributions to $90 million per year provided the distributing entity maintains at least $50 million of liquidity immediately after giving effect to the distribution.

LC Facilities. GasCo entered into a fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with Barclays Bank PLC (“Barclays”) pursuant to which Barclays agrees to issue letters of credit at GasCo’s request provided that GasCo deposits in an account controlled by Barclays an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereon.

GasCo also entered into a fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with Credit Suisse AG, Cayman Islands Branch (“CS”) pursuant to which CS agreed to issue letters of credit at GasCo’s request provided that GasCo deposits in an account controlled by CS an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereon.

CoalCo entered into a fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with CS pursuant to which CS agreed to issue letters of credit at CoalCo’s request provided that CoalCo deposits in an account controlled by CS an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereon.

DHI entered into a fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with CS pursuant to which CS agreed to issue letters of credit at DHI's request provided that DHI deposits in an account controlled by CS an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereon.

Overview of Bankruptcy Remote and Ring-Fencing Measures

Pursuant to the Reorganization, we have created, directly or indirectly, special-purpose bankruptcy remote entities. These bankruptcy remote entities will have at least one independent manager and shall have certain “separateness” provisions, including without limitation, separately appointed boards of managers, separate books and records, separately appointed officers, separate bank accounts, holding themselves out as separate legal entities and not divisions of Dynegy, payment of liabilities from their own funds, conducting business in their own names (other than any business relating to the trading activities of Dynegy and its subsidiaries), observing entity level formalities, and not pledging their assets for the benefit of certain other persons. In addition, GasCo has the option to sell a 20 percent ownership interest to a third party.

Further, these bankruptcy remote entities each have at least one independent manager. Unanimous consent of the board of managers, including the independent manager, is required for filing any bankruptcy proceeding, seeking or consenting to the appointment of any receiver, making or consenting to any assignment for the benefit of creditors, admitting in writing the inability to pay the applicable bankruptcy remote entity’s debts, consenting to substantive consolidation, dissolving or liquidating, engaging in any business beyond those set forth in the applicable bankruptcy remote entity’s organizational documents, amending the bankruptcy remoteness provisions in such entity’s organizational documents and, at any time following execution of the applicable credit agreement, amending, terminating or entering material intercompany relationships with other entities.

Relationships with Third Parties

Each ringfenced entity will bill its customers on invoices clearly referencing solely such ringfenced entity. Other than in the limited context of Services (defined and described below), when transacting business with third parties, including vendors and customers, employees of the ringfenced entities will not hold themselves out as agents or representatives of non-ringfenced entities. Similarly, other than in the limited context of Services, when transacting business with third parties, employees of non-ringfenced entities will not hold themselves out as agents or representatives of ringfenced entities.

Intercompany Transactions

Service Agreements. Service Agreements between Dynegy, and each of GasCo Intermediate Holdings, CoalCo Intermediate Holdings, DNE and certain other subsidiaries of Dynegy, govern the terms under which identified services (the “Services”) are provided. Under the Service Agreements, Dynegy and certain of its subsidiaries (the “Providers”) provide Services to GasCo Intermediate Holdings, CoalCo Intermediate Holdings, DNE, their respective subsidiaries and certain of the subsidiaries of Dynegy (the “Recipients”).

Table of Contents

DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

The Providers act as agents for the Recipients for the limited purpose of providing the Services set forth in the Service Agreement. The Providers may perform additional services at the request of the Recipients, and will be reimbursed for all costs and expenses related to such additional services. Prior to the beginning of each fiscal year in which Services are to be provided pursuant to the Service Agreement, the Providers and the Recipients must agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing each Service. The Recipients will pay the Providers an annual management fee as agreed in the budget, which shall include, reimbursement of out-of pocket costs and expenses related to the provision of the Services and will provide reasonable assistance, such as information, services and materials, to the Providers.

Energy Management Agreements. Each subsidiary owning one or more power plants (each a “Customer”) has entered into an Energy Management Agency Services Agreement (an “EMA”) with Dynegy Power Marketing, LLC (“DPM”). Pursuant to each EMA, DPM will provide power management services to the Customers, consisting of marketing power and capacity, capturing pricing arbitrage, scheduling dispatch of power, communicating with ISOs or RTOs, purchasing replacement power, and reconciling and settling ISO or RTO invoices. In addition, through Dynegy Marketing and Trade, LLC, DPM will provide fuel management services, consisting of procuring the requisite quantities of fuel, assisting with storage and transportation, scheduling delivery of fuel, assisting Customers with development and implementation of fuel procurement strategies, marketing and selling excess fuel and assisting with the evaluation of present and long-term fuel purchase and transportation options. Through Dynegy Coal Trading & Transportation, LLC, DPM will also provide fuel management services to one or more Customers that require services related to coal. DPM will also assist the Customer with risk management by entering into one or more risk management transactions, the purpose of which is to fix the price or value any commodity or to mitigate or offset any change in the price or value of any commodity. DPM may from time to time provide other services as the parties may agree.

Tax Sharing Agreement. Under the U.S. federal income tax law, Dynegy is responsible for the tax liabilities of its entities, because Dynegy will file consolidated income tax returns, which will necessarily include the income and business activities of the ringfenced entities and Dynegy’s other affiliates. To properly allocate taxes among Dynegy and each of its entities, Dynegy and certain of its entities have entered into a Tax Sharing Agreement under which Dynegy agrees to prepare consolidated returns on behalf of itself and its entities and make all required payments to relevant revenue collection authorities as required by law. Additionally, GasCo and CoalCo agree to make payments to Dynegy of the tax amounts for which GasCo or CoalCo and their respective entities would have been liable if each group of such entities began business on the restructuring date and were eligible to, and elected to, file a consolidated return on a stand-alone basis beginning on the restructuring date. Further, each of Dynegy GasCo Holdings, LLC, Dynegy Gas Holdco, LLC, GasCo Intermediate Holdings, Dynegy Coal Holdco, LLC, and CoalCo Intermediate Holdings agrees to make payments to Dynegy of amounts representing the tax that each such entity would have paid if each began business on the restructuring date and filed a separate corporate income tax return (excluding from income any subsidiary distributions) on a stand-alone basis beginning on the restructuring date.

Cash Management. Dynegy’s ringfenced entities maintain cash accounts separate from those of Dynegy’s non-ringfenced entities. As such, cash collected by a ringfenced entity is not swept into accounts held in the name of any non-ringfenced entity and cash collected by a non-ringfenced entity is not swept into accounts held in the name of any ringfenced entity. The cash in deposit accounts owned by a ringfenced entity is not used to pay the debts and/or operating expenses of any non-ringfenced Entity, and the cash in deposit accounts owned by a non-ringfenced entity is not used to pay the debts and/or operating expenses of any ringfenced entity.

Reportable Segments

In conjunction with the Reorganization, we have reevaluated our reportable segments and expect to report results in the following segments: (i) Gas, (ii) Coal and (iii) Other commencing with the quarter ended September 30, 2011. Accordingly, we will recast the corresponding items for all periods presented concurrent with the filing of our third quarter Form 10-Q.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended June 30, 2011 and 2010

Litigation

Reorganization Litigation. On July 21, 2011, certain holders of obligations with potential recourse rights to DHI initiated legal proceedings seeking to enjoin Dynegy’s restructuring efforts previously disclosed on July 10, 2011. On July 29, 2011, the Delaware court denied the plaintiff motion. On July 31, 2011, the plaintiffs filed an appeal which was denied on August 4, 2011 and subsequently denied by the Delaware Supreme Court on August 5, 2011. Please read Note 7—Commitments and Contingencies—Reorganization Litigation for further discussion.

Stockholder Litigation. On July 19, 2011, the Court granted plaintiff’s counsel’s motion seeking the award of fees and expenses of approximately $1.6 million. The impact of this decision has been reflected in Dynegy’s unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2011. Please read Note 7—Commitments and Contingencies—Stockholder Litigation Relating to the Blackstone and Icahn Merger Agreements for further discussion.

Gas Index Pricing Litigation. On July 18, 2011, the Court granted defendants’ motions for summary judgment, thereby dismissing all of plaintiffs’ state law claims. The impact of this decision has been reflected in our unaudited condensed consolidated statements of operations for the three and six months ended June 30, 2011. Please read Note 7—Commitments and Contingencies—Gas Index Pricing Litigation for further discussion.

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DYNEGY INC. and DYNEGY HOLDINGS INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 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.

New Management Team. On July 11, 2011, Robert C. Flexon, a director of Dynegy, was appointed as our President and Chief Executive Officer. Mr. Flexon replaced E. Hunter Harrison, who served as interim President and Chief Executive Officer since April 2011. Mr. Harrison resumed his role as an independent director and serves as non-executive Chairman of our Board of Directors. Additionally, on July 5, 2011, Clint C. Freeland was appointed as our Executive Vice President and Chief Financial Officer and Kevin T. Howell was appointed as our Executive Vice President and Chief Operating Officer. In July 2011, we announced the appointment of Carolyn J. Burke as Executive Vice President and Chief Administrative Officer, effective August 30, 2011.

Reorganization Activity. In August 2011, we completed the Reorganization of our subsidiaries, whereby (i) substantially all of our coal-fired power generation facilities are held by DMG, (ii) substantially all of our natural gas-fired power generation facilities are held by DPC and (iii) 100 percent of the ownership interests of DNE, the entity that indirectly holds the equity interests in the subsidiaries that operate the Roseton and Danskammer power generation facilities, are held by DHI. We completed the Reorganization of our legal entity structure to facilitate the execution of two new credit facilities. The new credit facilities, which were entered into August 5, 2011, consist of the GasCo Term Loan Facility, a $1,100 million, five year senior secured term loan facility available to GasCo, and the CoalCo Term Loan Facility, a $600 million, five year senior secured term loan facility available to CoalCo. Please read Note 13—Subsequent Events for further discussion.

The proceeds of borrowings under the CoalCo Term Loan Facility were or will be used by CoalCo, to (i) fund cash collateralized letters of credit and cash collateral for existing and future collateral requirements, (ii) make a $200 million restricted payment to a parent holding company of CoalCo, (iii) pay related transaction fees and expenses and (iv) fund additional cash to the balance sheet to provide the CoalCo portfolio with cash to be used for general working capital and general corporate purposes.

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We recently completed a reorganization of our subsidiaries and in connection therewith, certain of our subsidiaries (GasCo and CoalCo, as defined in Note 13—Subsequent Events) entered into two new credit facilities on August 5, 2011 which resulted in the repayment in full and termination of commitments under DHI’s Fifth Amended and Restated Credit Agreement. However, these new credit facilities contain certain restrictions related to distributions to their respective parent companies, including Dynegy and DHI (please read Note 13—Subsequent Events for further discussion). Although these new credit facilities are designed to provide sufficient operating liquidity for GasCo and CoalCo for the foreseeable future, there still remain significant debt service requirements for the unsecured notes and debentures at DHI as well as the operating lease payment obligations related to the Danskammer and Roseton operating leases at a wholly-owned subsidiary of DHI. We currently project that we will have minimal liquidity at DHI subsequent funding of the debt service requirements and operating lease payment obligations beyond the next eighteen months absent a significant positive change in the forecasted operating results of the Roseton and Danskammer facilities.

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.

Upon the completion of the Reorganization, our primary sources of internal liquidity are cash flows from operations, cash on hand and short-term investments. Please read Note 13—Subsequent Events for further information. Cash on hand includes cash proceeds from the GasCo Term Loan Facility and the CoalCo Term Loan Facility.

Our primary sources of external liquidity are proceeds from capital market transactions to the extent we engage in such transactions. Please read Capital-Structuring Transactions and Asset Dispositions below for more detail.

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Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at August 5, 2011, June 30, 2011 and December 31, 2010:

	August 5, 2011 (1)			June 30, 2011			December 31, 2010
	(in millions)
DHI Revolver capacity (2)	$	—		$	589		$	954
Borrowings against revolver capacity (3)	—			(400		)	—
Term letter of credit capacity, net of required reserves	—			825			825
Available contingent letter of credit facility capacity (4)	—			—			—
LC Facilities (5)	641			—			—
Outstanding letters of credit (5)	(608		)	(595		)	(375		)

Unused capacity	33			419			1,404

Cash—DHI (6)	956			354			253
Short-term investments—DHI (7)	—			94			90

Total available liquidity—DHI consolidated	$	989		$	867		$	1,747
Cash—Dynegy	58			45			38
Short-term investments—Dynegy (7)	—			12			16

Total available liquidity—Dynegy consolidated	$	1,047		$	924		$	1,801

(1) On August 5, 2011, we entered into the GasCo Term Loan Facility and the CoalCo Term Loan Facility, which replaced DHI’s Fifth Amended and Restated Credit Agreement. Please read Note13—Subsequent Events—Reorganization for further discussion.

(2) As of June 30, 2011 and December 31, 2010, our available liquidity under the Fifth Amended and Restated Credit Agreement was reduced by $491 million and $126 million, respectively, as a result of borrowing limitations under a financial covenant. On August 5, 2011, we repaid the Fifth Amended and Restated Credit Agreement. Please read Note13—Subsequent Events for further discussion.

(3) During the second quarter 2011, we borrowed $400 million under DHI’s Fifth Amended and Restated Credit Agreement. This borrowing was repaid on August 5, 2011 in connection with closing the two new credit facilities entered into as part of the August 2011 Reorganization. Please read Note13—Subsequent Events for further discussion.

(4) 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.

(5) GasCo and CoalCo had $9 million and $24 million of letter of credit capacity, respectively, at August 5, 2011.

(6) On August 5, 2011, we entered into the GasCo Term Loan Facility for $1,100 million and the CoalCo Term Loan Facility for $600 million resulting in the repayment and termination of DHI’s Fifth Amended and Restated Credit Agreement. A portion of the proceeds from the GasCo Term Loan Facility were used to make a $200 million restricted payment to a parent holding company of GasCo and a portion of the proceeds from the CoalCo Term Loan Facility were used to make a $200 million restricted payment to a parent holding company of CoalCo. After giving effect to the $400 million, in the aggregate, of proceeds from the GasCo Term Loan Facility and the CoalCo Term Loan Facility that was distributed, the GasCo Term Loan Facility and the CoalCo Term Loan Facility limit distributions by GasCo and CoalCo to their parents to $135 million and $90 million per year, respectively, provided the distributing entity maintains at least $50 million of liquidity immediately after giving effect to the distribution. Please read Note13—Subsequent Events for further discussion.

(7) We invest our available cash balances in certain investments permitted by our internal policies and external financing agreements. Please read Note 2—Investments for further discussion.

Cash on Hand. At August 5, 2011 and June 30, 2011, Dynegy had cash on hand of $1,014 million and $399 million, as compared to $291 million at December 31, 2010. At August 5, 2011 and June 30, 2011, DHI had cash on hand of $956 million and $354 million, as compared to $253 million at December 31, 2010. The increase in cash on hand at August 5, 2011 as compared to June 30, 2011 is due to the completion of the Reorganization. GasCo and CoalCo had $283 million and $268 million of cash on hand, respectively, at August 5, 2011, which is included in Dynegy’s and DHI’s consolidated cash on hand. Please read Note 13—Subsequent Events for further discussion. The increase in cash on hand at June 30, 2011 as compared to the end of 2010 is primarily due to the $400 million borrowed under the revolver capacity and the expiration of a security and deposit agreement and the subsequent release of $50 million of restricted cash, partially offset by net purchases of short-term investments, collateral posted with our clearing manager, capital expenditures and debt repayments.

Revolver Capacity. Our available liquidity under the Fifth Amended and Restated Credit Agreement was reduced by $491 million and $126 million as of June 30, 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 Fifth Amended and Restated Credit Agreement). The effect of reduced availability was less available liquidity to us. In the second quarter 2011, we borrowed $400 million under the Fifth Amended and Restated Credit Agreement. On August 5, 2011, the Fifth Amended and Restated Credit Agreement, including the $400 million borrowing, was repaid and terminated. Please read Note 8—Debt and Note 13—Subsequent Events for further discussion.

Capital-Structuring Transactions. We believe the Reorganization facilitated by the new credit facilities aligned our asset base and increased our flexibility to address additional potential debt restructuring activities. On August 5, 2011, we completed the Reorganization, repaid the Fifth Amended and Restated Credit Agreement and completed the GasCo Term Loan Facility and the CoalCo Term Loan Facility. We may participate in additional debt restructuring activities, which may include direct or indirect transfers of our subsidiaries’ equity interests, and/or further reorganizations of our subsidiaries. We will continue to focus on a capital structure that is closely aligned with the cash-generating potential of our assets, which is subject to cyclical changes in commodity prices. In addition to the above, we may explore additional sources of external liquidity, which could include 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 interest payments, restrictions imposed by the bankruptcy remote structure, the GasCo Term Loan Facility and CoalCo Term Loan Facility, and debt 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, our non-investment grade credit ratings, significant debt maturities, business prospects and other factors beyond our control, including current and projected market conditions.

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GasCo and CoalCo Restricted Payments. After giving effect to the $400 million, in the aggregate, of proceeds from the GasCo Term Loan Facility and the CoalCo Term Loan Facility that was distributed to Dynegy Gas Holdco, LLC and Dynegy Coal Holdco, LLC, respectively, the GasCo Term Loan Facility and the CoalCo Term Loan Facility limit distributions by GasCo and CoalCo to their parents to $135 million and $90 million per year, respectively, provided the distributing entity maintains at least $50 million of liquidity immediately after giving effect to the distribution. Please read Note 13—Subsequent Events—Reorganization for further discussion.

Operating Activities

Historical Operating Cash Flows. Dynegy’s and DHI’s cash flow used in operations totaled $86 million for the six months ended June 30, 2011. During the period, our power generation business provided positive cash flow from operations of $178 million from the operation of our power generation facilities after $92 million of cash outflows to our clearing manager. Corporate and other operations used approximately $264 million of cash primarily for interest payments to service debt and general and administrative expenses.

Dynegy’s cash flow provided by operations totaled $368 million for the six months ended June 30, 2010. DHI’s cash flow provided by operations totaled $369 million for the six months ended June 30, 2010. During the period, our power generation business provided positive cash flow from operations of $635 million from the operation of our power generation facilities, primarily reflecting positive earnings for the period and approximately $255 million of cash returned from our futures clearing manager. The return of this cash is partly the result of a $126 million decrease in our collateral requirements for the period; the remaining cash was returned as a result of the posting of short-term investments and a letter of credit in substitute of cash. Corporate and other operations included a use of approximately $267 million and $266 million in cash by Dynegy and DHI, respectively, primarily for interest payments to service debt and general and administrative expenses.

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 our ability to capture value associated with commodity price volatility.

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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 June 30, 2011, we had approximately $137 million of cash collateral postings and $101 million of 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 August 5, 2011, June 30, 2011 and December 31, 2010:

	August 5, 2011		June 30, 2011		December 31, 2010
	(in millions)
By Business:
Generation business	$	654	$	640	$	377
Other	97		97		85

Total	$	751	$	737	$	462
By Type:
Cash and marketable securities (1)	$	143	$	142	$	87
Letters of credit	608		595		375

Total	$	751	$	737	$	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 June 30, 2011 is primarily due to higher initial margin posting requirements, reduced use of bilateral first lien collateral arrangements and contractual obligations under certain operational agreements. Collateral postings increased from June 30, 2011 to August 5, 2011 primarily due to contractual obligations under certain operational agreements.

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. Our ability to use forward economic hedging instruments could be limited, due to the collateral requirements the use of such instruments entails.

Investing Activities

Capital Expenditures. We had approximately $128 million and $201 million in capital expenditures during the six months ended June 30, 2011 and 2010, respectively. Our capital spending by reportable segment was as follows:

	For the Six Months Ended
	June 30,
	2011		2010
	(in millions)
GEN-MW	$	93	$	182
GEN-WE	14		10
GEN-NE	21		5
Other	—		4

Total	$	128	$	201

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

Other Investing Activities. Cash outflow for purchases of short-term investments during the six months ended June 30, 2011 totaled $247 million and $235 million for Dynegy and DHI, respectively. Cash inflow related to maturities of short-term investments for the six months ended June 30, 2011 were $217 million and $201 million for Dynegy and DHI, respectively. There was a $53 million cash inflow related to restricted cash balances during the six months ended June 30, 2011 from the release of $50 million related to the expiration of a security and deposit agreement and a decrease of $3 million in the restricted cash balance related to the Sithe senior notes. Other included $10 million of property insurance claim proceeds.

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Cash outflow related to purchases of short-term investments during the six months ended June 30, 2010 totaled $331 million and $316 million for Dynegy and DHI, respectively, and cash inflow related to distributions from short-term investments for the six months ended June 30, 2010 was $27 million and $28 million for Dynegy and DHI, respectively. There was a $10 million cash outflow related to restricted cash balances during the six months ended June 30, 2010 due to an increase in the Independence restricted cash balance and a $15 million cash outflow related to our funding commitment obligation under the PPEA Sponsor Support Agreement. 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. Cash flow provided by financing activities totaled $289 million and $286 million for Dynegy and DHI, respectively, for the six months ended June 30, 2011 due to $400 million in proceeds from long-term borrowing against the revolver capacity. This was offset by an $80 million repayment of our 6.875 percent senior notes, $33 million of repayments of borrowings on Sithe senior debt and $1 million in fees associated with the GasCo Term Loan Facility and the CoalCo Term Loan Facility. Dynegy’s financing activities also included $3 million from proceeds of stock option exercises.

Cash flow used in financing activities totaled $36 million for Dynegy and DHI, for six months ended June 30, 2010 related to $31 million of repayments of borrowings on Sithe senior debt and $5 million of financing fees.

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

Financial Covenants. Following the termination of the Fifth Amended and Restated Credit Agreement on August xx, 2011, we are not subject to any financial covenants.

Dividends on Common Stock. Dividend payments on our common stock are authorized at the discretion of our Board of Directors and applicable law. We did not declare or pay a cash dividend on common stock during the quarter ended June 30, 2011.

Credit Ratings

Our credit rating status is currently “non-investment grade” and our current ratings are as follows:

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	Standard & Poor	Moody’s	Fitch

Dyengy Inc.:
Corporate Family Rating	CC	Caa3	CC
Senior Unsecured Shelf	—	C	—
Subordinated Shelf	—	C	—
Preferred Shelf	—	C	—

DHI:
Secured Bank Credit Facility	CCC	B2	B
Senior Unsecured	CC	Ca	CC
Senior Unsecured Shelf	CC	Ca	—
Subordinated Shelf	—	C	—
Preferred Shelf	C	—	—

Dynegy Power LLC:
Corporate Credit Rating	CCC+	—	—
GasCo Term Loan	B	B2	—

Sithe Independence:
Senior Secured	CC	B2	B

Additional downgrades could occur in the future based on the ratings agencies’ views of near-term risk of bankruptcy and our ability to continue operating as a going concern. 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 and six month periods ended June 30, 2011 and 2010. We have included our outlook for each segment at the end of this section.

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 June 30, 2011 and 2010, respectively:

Dynegy’s Results of Operations for the Three Months Ended June 30, 2011

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

Revenues	$	195		$	19		$	112		$	—		$	326
Cost of sales	(137		)	(2		)	(86		)	—			(225		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(45		)	(20		)	(39		)	(2		)	(106		)
Depreciation and amortization expense	(50		)	(16		)	(7		)	(2		)	(75		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(25		)	(25		)
Operating loss	$	(37	)	$	(19	)	$	(21	)	$	(29	)	$	(106	)
Other items, net	2			1			—			—			3
Interest expense													(89		)

Loss from continuing operations before income taxes													(192		)
Income tax benefit													76

Net loss													$	(116	)

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Dynegy’s Results of Operations for the Three Months Ended June 30, 2010

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

Revenues	$	63		$	71		$	105		$	—		$	239
Cost of sales	(110		)	(37		)	(84		)	—			(231		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(55		)	(26		)	(38		)	1			(118		)
Depreciation and amortization expense	(63		)	(17		)	(8		)	(2		)	(90		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(28		)	(28		)
Operating loss	$	(165	)	$	(9	)	$	(26	)	$	(29	)	$	(229	)
Other items, net	—			—			—			1			1
Interest expense													(91		)

Loss from continuing operations before income taxes													(319		)
Income tax benefit													128

Net loss													$	(191	)

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.

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 our ability to fund capital expenditures, assess performance against our 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 our financial and operating performance. By definition, non-GAAP measures do not give a full understanding of Dynegy’s financial results; 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 by definition provide an incomplete understanding of Dynegy’s financial results and must be considered in conjunction with GAAP measures.

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 our Board of Directors, stockholders, creditors, analysts and investors concerning our financial performance.

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As prescribed by the SEC, 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). 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 loss on a segment basis and to net loss on a consolidated basis for the three month periods ended June 30, 2011 and 2010, respectively.

Dynegy’s Adjusted EBITDA for Three Months Ended June 30, 2011

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Net loss													$	(116	)
Income tax benefit													(76		)
Interest expense													89
Other items, net													(3		)

Operating loss	$	(37	)	$	(19	)	$	(21	)	$	(29	)	$	(106	)
Depreciation and amortization expense	50			16			7			2			75
Other items, net	2			1			—			—			3

EBITDA	15			(2		)	(14		)	(27		)	(28		)

Mark-to-market losses, net	83			24			23			—			130

Adjusted EBITDA	$	98		$	22		$	9		$	(27	)	$	102

Dynegy’s Adjusted EBITDA for the Three Months Ended June 30, 2010

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Net loss													$	(191	)
Income tax benefit													(128		)
Interest expense													91
Other items, net													(1		)

Operating loss	$	(165	)	$	(9	)	$	(26	)	$	(29	)	$	(229	)
Other items, net	—			—			—			1			1
Depreciation and amortization expense	63			17			8			2			90

EBITDA	(102		)	8			(18		)	(26		)	(138		)
Mark-to-market losses, net	183			24			55			—			262

Adjusted EBITDA	$	81		$	32		$	37		$	(26	)	$	124

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The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the three month periods ended June 30, 2011 and 2010, respectively:

DHI’s Results of Operations for the Three Months Ended June 30, 2011

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

Revenues	$	195		$	19		$	112		$	—		$	326
Cost of sales	(137		)	(2		)	(86		)	—			(225		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(45		)	(20		)	(39		)	(2		)	(106		)
Depreciation and amortization expense	(50		)	(16		)	(7		)	(2		)	(75		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(23		)	(23		)
Operating loss	$	(37	)	$	(19	)	$	(21	)	$	(27	)	$	(104	)
Other items, net	2			1			—			—			3
Interest expense													(89		)

Loss from continuing operations before income taxes													(190		)
Income tax benefit													75

Net loss													$	(115	)

DHI’s Results of Operations for the Three Months Ended June 30, 2010

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

Revenues	$	63		$	71		$	105		$	—		$	239
Cost of sales	(110		)	(37		)	(84		)	—			(231		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(55		)	(26		)	(38		)	1			(118		)
Depreciation and amortization expense	(63		)	(17		)	(8		)	(2		)	(90		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(28		)	(28		)
Operating loss	$	(165	)	$	(9	)	$	(26	)	$	(29	)	$	(229	)
Other items, net	—			—			—			1			1
Interest expense													(91		)

Loss from continuing operations before income taxes													(319		)
Income tax benefit													128

Net loss													$	(191	)

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The following table provides summary segmented operating statistics for the three months ended June 30, 2011 and 2010, respectively:

	Three Months Ended June 30,
	2011			2010
GEN-MW
Million Megawatt Hours Generated	7.2			5.6
In Market Availability for Coal Fired Facilities (1)	94		%	83		%
Average Capacity Factor for Combined Cycle Facilities (2)	39		%	25		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	44		$	41
Commonwealth Edison (NI Hub)	$	44		$	40
PJM West	$	56		$	52
Average Market Spark Spreads ($/MWh) (4):
PJM West	$	24		$	19

GEN-WE
Million Megawatt Hours Generated (5)	0.2			0.5
Average Capacity Factor for Combined Cycle Facilities (2)	2		%	17		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
North Path 15 (NP 15)	$	34		$	36
Average Market Spark Spreads ($/MWh) (4):
North Path 15 (NP 15)	$	—		$	2

GEN-NE
Million Megawatt Hours Generated	1.2			1.6
In Market Availability for Coal Fired Facilities (1)	97		%	96		%
Average Capacity Factor for Combined Cycle Facilities (2)	31		%	38		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	56		$	53
New York—Zone A	$	42		$	41
Mass Hub	$	49		$	49
Average Market Spark Spreads ($/MWh) (4):
New York—Zone A	$	7		$	7
Mass Hub	$	16		$	17
Fuel Oil	$	(131	)	$	(77	)

Average natural gas price—Henry Hub ($/MMBtu) (6)	$	4.35		$	4.30

(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 June 30, 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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Operating Loss

Operating loss for Dynegy was $106 million for the three months ended June 30, 2011, compared to operating loss of $229 million for the three months ended June 30, 2010. Operating loss for DHI was $104 million for the three months ended June 30, 2011, compared to operating loss of $229 million for the three months ended June 30, 2010.

Mark-to market losses 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 losses totaled $129 million for the three months ended June 30, 2011, compared to $258 million of mark-to-market losses for the three months ended June 30, 2010. The losses in both periods were primarily the result of decreases in the forward value of open positions and losses related to the expiration 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 3—Risk Management Activities, Derivatives and Financial Instruments for further discussion. This 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 periods 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 $37 million for the three months ended June 30, 2011, compared to operating loss of $165 million for the three months ended June 30, 2010.

Revenues for the three months ended June 30, 2011 increased by $132 million compared to the three months ended June 30, 2010, cost of sales increased by $27 million and operating and maintenance expense decreased by $10 million, resulting in a net increase of $115 million. The increase was primarily driven by the following:

· Mark-to-market losses — GEN-MW’s results for the three months ended June 30, 2011 included mark-to-market losses of $82 million related to forward sales and other derivative contracts, compared to $183 million of mark-to-market losses for the three months ended June 30, 2010. Of the $82 million in 2011 mark-to-market losses, $46 million of losses related to positions that settled or will settle in 2011, and $36 million of losses related to positions that will settle in 2012 and beyond;

· Energy sales — GEN-MW’s results from energy sales, including both physical and financial transactions, increased from $109 million for the three months ended June 30, 2010 to $117 million for the three months ended June 30, 2011. The contribution from physical transactions increased primarily as a result of fewer outages, higher prices at our coal-fired facilities and improved spark spreads for our combined-cycle facilities. The increase from physical transactions was partially offset by reduced contributions from financial transactions; and

· Operating expense — Operating expense decreased $10 million primarily as a result of lower planned outage expenses and the mothballing of our Vermilion facility.

These items were partly offset by tolling and capacity revenues, which decreased due to lower capacity prices in MISO partially offset by higher PJM capacity prices.

Depreciation expense decreased from $63 million for the second quarter 2010 to $50 million for the second quarter 2011, as a result of fully depreciating the value of our Wood River Units 1-3 and Havana Units 1-5 in June 2010, as well as the Havana 6 Precipitator Rebuild retirement. The Vermilion facility was mothballed during the first quarter 2011.

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Power Generation—West Segment. Operating loss for GEN-WE was $19 million for three months ended June 30, 2011, compared to operating loss of $9 million for the three months ended June 30, 2010.

Revenues for the three months ended June 30, 2011 decreased by $52 million compared to the three months ended June 30, 2010, cost of sales decreased by $35 million and operating and maintenance expense decreased by $6 million, resulting in a net decrease of $11 million. The decrease was primarily driven by:

· Energy sales — GEN-WE’s results from energy sales, including both physical and financial transactions, decreased from $26 million for the three months ended June 30, 2010 to $17 million for the three months ended June 30, 2011 largely as a result of reduced contributions from financial transactions; and

· Decreased tolling/RMR revenues — Tolling/RMR decreased $10 million due to the retirement of South Bay at the end of 2010 and change in the timing of earnings under the new tolling agreement for Moss Landing compared to the timing of earnings under the previous agreement.

· Operating expense — Operating expense decreased $6 million primarily due to the retirement of South Bay at the end of 2010.

These items were partly offset by mark-to-market losses of $22 million related to forward sales and other derivative contracts for the three months ended June 30, 2011, compared to $27 million of mark-to-market losses for the three months ended June 30, 2010. Of the $22 million in 2011 mark-to-market losses, $16 million related to positions that settled or will settle in 2011, and the remaining $6 million related to positions that will settle in 2012 and beyond.

Depreciation expense decreased from $17 million for the second quarter 2010 to $16 million for the second quarter 2011.

Power Generation—Northeast Segment. Operating loss for GEN-NE was $21 million for the three months ended June 30, 2011, compared to an operating loss of $26 million for the three months ended June 30, 2010.

Revenues for the three months ended June 30, 2011 increased by $7 million compared to the three months ended June 30, 2010, cost of sales increased by $2 million and operating and maintenance expenses increased by $1 million resulting in a net increase of $4 million. The increase was primarily driven by the following:

· Mark-to-market losses — GEN-NE’s results for the three months ended June 30, 2011 included mark-to-market losses of $25 million for forward sales and other derivative contracts, compared to losses of $48 million for the three months ended June 30, 2010. Of the $25 million in 2011 mark-to-market losses, $13 million related to positions that settled or will settle in 2011, and the remaining $12 million related to positions that will settle in 2012 and beyond.

This item was partly offset by the following:

· Energy sales — GEN-NE’s results from energy sales, including both physical and financial transactions, decreased from $25 million for the three months ended June 30, 2010 to $16 million for the three months ended June 30, 2011. The contribution from physical transactions decreased primarily as a result of reduced market spark spreads. The contribution from financial transactions also decreased due to compressed spreads and reduced option sales in future years; and

· Capacity revenues — Capacity revenues decreased $9 million primarily due to lower pricing.

Depreciation expense decreased from $8 million for the second quarter 2010 to $7 million for the second quarter 2011.

Other. Dynegy’s other operating loss for the three months ended June 30, 2011 was $29 million, compared to an operating loss of $29 million for the three months ended June 30, 2010. DHI’s other operating loss for the three months ended June 30, 2011 was $27 million, compared to an operating loss of $29 million for the three months ended June 30, 2010. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses decreased from $28 million for the three months ended June 30, 2010 to $25 million for the three months ended June 30, 2011. DHI’s consolidated general and administrative expenses decreased from $28 million for the three months ended June 30, 2010 to $23 million for the three months ended June 30, 2011. The decreases were primarily driven by lower salary and benefits costs as a result of ongoing cost savings initiatives.

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Other Items, Net

Other items, net, were $3 million and $1 million for the three months ended June 30, 2011 and 2010, respectively.

Interest Expense

Interest expense totaled $89 million and $91 million for the three months ended June 30, 2011 and 2010, respectively.

Income Tax Benefit

Dynegy reported an income tax benefit from continuing operations of $76 million for the three month period ended June 30, 2011, compared to an income tax benefit from continuing operations of $128 million for the three months ended June 30, 2010. The effective tax rate in both periods was 40 percent.

DHI reported an income tax benefit from continuing operations of $75 million for the three month period ended June 30, 2011, compared to an income tax benefit from continuing operations of $128 million for the three months ended June 30, 2010. The 2011 effective tax rate was 39 percent compared to 40 percent in 2010.

For the period ended June 30, 2011, the difference between the effective rates of 40 percent and 39 percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted primarily from the impact of state taxes. For the period ended June 30, 2010, the difference between the effective rates of 40 percent and the statutory rate of 35 percent resulted primarily from the impact of state taxes.

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Six Months Ended June 30, 2011 and 2010

Summary Financial Information. The following tables provide summary financial data regarding Dynegy’s consolidated and segmented results of operations for the six month periods ended June 30, 2011 and 2010, respectively:

Dynegy’s Results of Operations for the Six Months Ended June 30, 2011

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

Revenues	$	475		$	81		$	275		$	—		$	831
Cost of sales	(273		)	(22		)	(208		)	—			(503		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(92		)	(44		)	(78		)	(2		)	(216		)
Depreciation and amortization expense	(150		)	(33		)	(14		)	(4		)	(201		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(65		)	(65		)
Operating loss	$	(40	)	$	(18	)	$	(26	)	$	(71	)	$	(155	)
Other items, net	2			1			—			1			4
Interest expense													(178		)

Loss from continuing operations before income taxes													(329		)
Income tax benefit													136

Net loss													$	(193	)

Dynegy’s Results of Operations for the Six Months Ended June 30, 2010

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

Revenues	$	549		$	214		$	334		$	—		$	1,097
Cost of sales	(237		)	(96		)	(206		)	—			(539		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(104		)	(49		)	(77		)	(1		)	(231		)
Depreciation and amortization expense	(113		)	(33		)	(16		)	(3		)	(165		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(59		)	(59		)
Operating income (loss)	$	95		$	36		$	34		$	(63	)	$	102
Losses from unconsolidated investments	(34		)	—			—			—			(34		)
Other items, net	—			—			1			1			2
Interest expense													(180		)

Loss from continuing operations before income taxes													(110		)
Income tax benefit													63

Loss from continuing operations													(47		)
Income from discontinued operations, net of taxes													1

Net loss													$	(46	)

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EBITDA and Adjusted EBITDA-Dynegy. Please read EBITDA and Adjusted EBITDA-Dynegy above for definitions for EBITDA and Adjusted EBITDA.

The tables below provide a reconciliation of Adjusted EBITDA to our operating income (loss) on a segment basis and to net loss on a consolidated basis for the six month periods ended June 30, 2011 and 2010, respectively.

Dynegy’s Adjusted EBITDA for Six Months Ended June 30, 2011

	Power Generation
	GEN-MW			GEN-WE			GEN-NE			Other			Total
	(in millions)
Net loss													$	(193	)
Income tax benefit													(136		)
Interest expense													178
Other items, net													(4		)

Operating loss	$	(40	)	$	(18	)	$	(26	)	$	(71	)	$	(155	)
Depreciation and amortization expense	150			33			14			4			201
Other items, net	2			1			—			1			4

EBITDA	112			16			(12		)	(66		)	50

Merger agreement termination fee and other legal expenses	—			—			—			9			9
Executive separation agreement expenses	—			—			—			3			3
Mark-to-market losses, net	82			9			36			—			127

Adjusted EBITDA	$	194		$	25		$	24		$	(54	)	$	189

Dynegy’s Adjusted EBITDA for the Six Months Ended June 30, 2010

	Power Generation
	GEN-MW			GEN-WE		GEN-NE		Other			Total
	(in millions)
Net loss											$	(46	)
Income tax benefit											(63		)
Interest expense											180
Losses from unconsolidated investments											34
Income from discontinued operations, net of taxes											(1		)
Other items, net											(2		)

Operating income (loss)	$	95		$	36	$	34	$	(63	)	$	102
Other items, net	—			—		1		1			2
Depreciation and amortization expense	113			33		16		3			165
Losses from unconsolidated investments	(34		)	—		—		—			(34		)

EBITDA from continuing operations	174			69		51		(59		)	235
EBITDA from discontinued operations	—			1		—		—			1

EBITDA	174			70		51		(59		)	236
Asset impairment	37			—		—		—			37
Plum Point mark-to-market gains	(6		)	—		—		—			(6		)
Mark-to-market losses, net	4			1		4		—			9

Adjusted EBITDA	$	209		$	71	$	55	$	(59	)	$	276

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The following tables provide summary financial data regarding DHI’s consolidated and segmented results of operations for the six month periods ended June 30, 2011 and 2010, respectively:

DHI’s Results of Operations for the Six Months Ended June 30, 2011

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

Revenues	$	475		$	81		$	275		$	—		$	831
Cost of sales	(273		)	(22		)	(208		)	—			(503		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(92		)	(44		)	(78		)	(2		)	(216		)
Depreciation and amortization expense	(150		)	(33		)	(14		)	(4		)	(201		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(64		)	(64		)
Operating loss	$	(40	)	$	(18	)	$	(26	)	$	(70	)	$	(154	)
Other items, net	2			1			—			1			4
Interest expense													(178		)

Loss from continuing operations before income taxes													(328		)
Income tax benefit													133

Net loss													$	(195	)

DHI’s Results of Operations for the Six Months Ended June 30, 2010

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

Revenues	$	549		$	214		$	334		$	—		$	1,097
Cost of sales	(237		)	(96		)	(206		)	—			(539		)
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(104		)	(49		)	(77		)	(1		)	(231		)
Depreciation and amortization expense	(113		)	(33		)	(16		)	(3		)	(165		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			(59		)	(59		)
Operating income (loss)	$	95		$	36		$	34		$	(63	)	$	102
Losses from unconsolidated investments	(34		)	—			—			—			(34		)
Other items, net	—			—			1			1			2
Interest expense													(180		)

Loss from continuing operations before income taxes													(110		)
Income tax benefit													56

Loss from continuing operations													(54		)
Income from discontinued operations, net of taxes													1

Net loss													$	(53	)

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The following table provides summary segmented operating statistics for the six months ended June 30, 2011 and 2010, respectively:

	Six Months Ended June 30,
	2011			2010
GEN-MW
Million Megawatt Hours Generated	14.4			12.0
In Market Availability for Coal Fired Facilities (1)	93		%	89		%
Average Capacity Factor for Combined Cycle Facilities (2)	34		%	20		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3)
Cinergy (CIN Hub)	$	42		$	42
Commonwealth Edison (NI Hub)	$	42		$	41
PJM West	$	54		$	52
Average Market Spark Spreads ($/MWh) (4)
PJM West	$	18		$	14

GEN-WE
Million Megawatt Hours Generated (5)	0.6			1.9
Average Capacity Factor for Combined Cycle Facilities (2)	8		%	38		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3)
North Path 15 (NP 15)	$	35		$	41
Average Market Spark Spreads ($/MWh) (4)
North Path 15 (NP 15)	$	2		$	5

GEN-NE
Million Megawatt Hours Generated	2.7			3.1
In Market Availability for Coal Fired Facilities (1)	95		%	94		%
Average Capacity Factor for Combined Cycle Facilities (2)	31		%	33		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3)
New York—Zone G	$	60		$	55
New York—Zone A	$	42		$	40
Mass Hub	$	57		$	52
Average Market Spark Spreads ($/MWh) (4)
New York—Zone A	$	7		$	3
Mass Hub	$	16		$	13
Fuel Oil	$	(115	)	$	(74	)

Average natural gas price—Henry Hub ($/MMBtu) (6)	$	4.26		$	4.73

(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 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 six months ended June 30, 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 loss for the period presented:

	Six Months Ended June 30, 2010
	Power Generation
	GEN-MW			GEN-WE		GEN-NE		Other		Total
	(in millions)
Asset 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 six months ended June 30, 2011.

Operating Income (Loss)

Operating loss for Dynegy was $155 million for the six months ended June 30, 2011, compared to operating income of $102 million for the six months ended June 30, 2010. Operating loss for DHI was $154 million for the six months ended June 30, 2011, compared to operating income of $102 million for the six months ended June 30, 2010.

Mark-to-market losses on derivatives associated with our generating assets are included in Revenues in the unaudited condensed consolidated statements of operations. Such losses totaled $127 million for the six months ended June 30, 2011 compared to $4 million of mark-to-market losses for the six months ended June 30, 2010. The losses in the six months ended June 30, 2011 were primarily the result of a decrease in the forward value of open positions and losses related to the expiration of certain risk management positions for which mark to market gains were recognized in previous periods. The losses for the six months ended June 30, 2010 were primarily from the expiration of certain risk management positions for which mark-to-market gains were already recognized in previous periods, largely offset by an increase in the value of open positions.

Power Generation—Midwest Segment. Operating loss for GEN-MW was $40 million for the six months ended June 30, 2011, compared to operating income of $95 million for the six months ended June 30, 2010.

Revenues for the six months ended June 30, 2011 decreased by $74 million compared to the six months ended June 30, 2010, cost of sales increased by $36 million and operating and maintenance expense decreased by $12 million, resulting in a net decrease of $98 million. The decrease was primarily driven by the following:

· Energy sales — GEN-MW’s results from energy sales, including both physical and financial transactions, decreased from $241 million for the six months ended June 30, 2010 to $234 million for the six months ended June 30, 2011. The contribution from physical transactions increased primarily as a result of higher power prices at our coal fired facilities and improved spark spreads at our combined cycle facilities, partially offset by more unplanned outages; however, these increases were more than offset by reduced contribution from financial transactions;

· Mark-to-market losses — GEN-MW’s results for the six months ended June 30, 2011 included mark-to-market losses of $82 million related to forward sales and other derivative contracts, compared to mark-to-market losses of $4 million for the six months ended June 30, 2010. Of the $82 million in 2011 mark-to-market losses, $51 million of losses related to positions that settled or will settle in 2011 and $31 million of losses related to positions that will settle in 2012 and beyond; and

· Decreased tolling/capacity revenues — 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 $8 million due to lower capacity prices in MISO. These decreases were partially offset by a $7 million increase attributable to higher PJM capacity prices and the additional capacity made available by the termination of the previous Kendall tolling agreement.

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These items were partly offset by operating and maintenance expenses, which decreased from $104 million for the six months ended June 30, 2010 to $92 million for the six months ended June 30, 2011, primarily as a result of lower planned outage expenses and the mothballing of our Vermilion facility in the first quarter 2011.

Depreciation expense increased from $113 million for the six months ended June 30, 2010 to $150 million for the six months ended June 30, 2011, primarily as a result of fully depreciating the value of our Vermilion facility, which was mothballed during the first quarter 2011, partially offset by fully depreciating the value of Wood River Units 1-3 and Havana Units 1-5 in June 2010.

Power Generation—West Segment. Operating loss for GEN-WE was $18 million for six months ended June 30, 2011, compared to operating income of $36 million for the six months ended June 30, 2010.

Revenues for the six months ended June 30, 2011 decreased by $133 million compared to the six months ended June 30, 2010, cost of sales decreased by $74 million and operating and maintenance expense decreased by $5 million, resulting in a net decrease of $54 million. The decrease was primarily driven by the following:

· Energy sales — GEN-WE’s results from energy sales, including both physical and financial transactions, decreased from $55 million for the six months ended June 30, 2010 to $23 million for the six months ended June 30, 2011. The contribution from physical transactions decreased primarily as a result of reduced spark spreads. The contribution from financial transactions also decreased;

· RMR revenues decreased $16 million due to the retirement of South Bay at the end of 2010;

· Tolling revenues — Tolling revenues decreased by $7 million primarily as a result of the timing of earnings under our new tolling agreement for the Moss Landing facility compared to the previous agreement partially offset by fewer forced outages in 2011;

· Mark-to-market losses — GEN-WE’s results for the six months ended June 30, 2011 included mark-to-market losses of $6 million related to forward sales and other derivative contracts, compared to $4 million of mark-to-market losses for the six months ended June 30, 2010. Of the $6 million in 2011 mark-to-market losses, $4 million in losses related to positions that settled or will settle in 2011, and $2 million in losses related to positions that will settle in 2012 and beyond; and

· Operating expense — Operating expense decreased $5 million primarily due to the retirement of South Bay at the end of 2010 partially offset by an outage at our Moss Landing facility in 2011.

Depreciation expense remained flat at $33 million for both the six months ended June 30, 2010 and the six months ended June 30, 2011.

Power Generation—Northeast Segment. Operating loss for GEN-NE was $26 million for the six months ended June 30, 2011, compared to operating income of $34 million for the six months ended June 30, 2010.

Revenues for the six months ended June 30, 2011 decreased by $59 million compared to the six months ended June 30, 2010, cost of sales increased by $2 million and operating and maintenance expense increased by $1 million, resulting in a net decrease of $62 million. The decrease was primarily driven by the following:

· Mark-to-market losses — GEN-NE’s results for the six months ended June 30, 2011 included mark-to-market losses of $39 million related to forward sales and other derivative contracts, compared to gains of $3 million for the six months ended June 30, 2010. Of the $39 million in 2011 mark-to-market losses, $19 million in losses related to positions that settled or will settle in 2011, and $20 million in losses related to positions that will settle in 2012 and beyond;

· Energy sales — GEN-NE’s results from energy sales, including both physical and financial transactions, decreased from $41 million for the six months ended June 30, 2010 to $35 million for the six months ended June 30, 2011. The contribution from physical transactions increased primarily as a result of improved market spark spreads in the first quarter of the year and cycling units during low load, off-peak periods which were partially offset by an extended outage at our Casco Bay facility in the first quarter 2011. The increase from physical transactions was more than offset by reduced contributions from financial transactions; and

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· Capacity revenues — Capacity revenues decreased by $16 million primarily due to lower pricing from surplus demand.

Depreciation expense decreased from $16 million for the six months ended June 30, 2010 to $14 million for the six months ended June 30, 2011.

Other. Dynegy’s other operating loss for the six months ended June 30, 2011 was $71 million, compared to $63 million for the six months ended June 30, 2010. DHI’s other operating loss for the six months ended June 30, 2011 was $70 million, compared to $63 million for the six months ended June 30, 2010. Operating losses in both periods were comprised primarily of general and administrative expenses.

Dynegy’s consolidated general and administrative expenses increased from $59 million from the six months ended June 30, 2010 to $65 million for the six months ended June 30, 2011. DHI’s consolidated general and administrative expenses increased from $59 million from the six months ended June 30, 2010 to $64 million for the six months ended June 30, 2011. General and administrative expenses for the six months ending June 30, 2011 are higher when compared to the six months ended June 30, 2010 due to $9 million of merger related expenses and $3 million of severance expenses, partially offset by lower salary and benefit costs resulting from ongoing cost savings initiatives.

Losses from Unconsolidated Investments

Losses from unconsolidated investments of $34 million for the six months ended June 30, 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. Please see Note 6—Variable Interest Entities—PPEA Holding Company LLC for further discussion.

Other Items, Net

Other items, net, totaled $4 million of income for the six months ended June 30, 2011, compared to $2 million of income for the six months ended June 30, 2010.

Interest Expense

Interest expense totaled $178 million for the six months ended June 30, 2011, compared to $180 million for the six months ended June 30, 2010.

Income Tax Benefit

Dynegy reported an income tax benefit from continuing operations of $136 million for the six months ended June 30, 2011, compared to $63 million for the six months ended June 30, 2010. The 2011 effective tax rate was 41 percent, compared to 57 percent in 2010.

DHI reported an income tax benefit from continuing operations of $133 million for the six months ended June 30, 2011, compared to $56 million for the six months ended June 30, 2010. The 2011 effective tax rate was 41 percent, compared to 51 percent in 2010.

For the six months ended June 30, 2011, the primary difference between the effective rates of 41 percent for Dynegy and DHI 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. This was 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 six months ended June 30, 2010, the primary difference between the effective rates of 57 and 51 percent for Dynegy and DHI, respectively, and the statutory rate of 35 percent resulted primarily from the benefit of $18 million and $12 million for Dynegy and DHI, respectively, related to the release of reserves for uncertain tax positions, partly offset by the impact of state taxes.

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Outlook

In August 2011, we completed the Reorganization. As a result, GasCo owns a portfolio of eight primarily natural gas-fired intermediate (combined cycle) and peaking (combustion and steam turbines) power generation facilities diversified across the West, Midwest and Northeast regions of the United States, totaling 6,771 MW of generating capacity. CoalCo owns a portfolio of six primarily coal-fired baseload power generation facilities located in the Midwest, totaling 3,132 MW of generating capacity. GasCo and CoalCo are bankruptcy remote. Our remaining assets (including leasehold interests in the Danskammer and Roseton facilities) are not a part of either GasCo or CoalCo. We completed the Reorganization of our legal entity structure to facilitate the execution of two new credit facilities, the GasCo Term Loan Facility and the CoalCo Term Loan Facility. Please read Note 13—Subsequent Events for further discussion.

As described above, we implemented a modification of our asset ownership structure which eliminated the regional organizational structure. We are focused on reducing and consolidating non-plant support activities and focused on cost efficiencies at both operating facilities and corporate support functions. Going forward, we have an operating fleet supported by Dynegy service contracts, which has resulted in adjusting corporate functions to support the new operational model. As a result of the Reorganization, we have reevaluated our reportable segments and expect to report results in the following segments: (i) Gas, (ii) Coal and (iii) Other commencing with the quarter ended September 30, 2011.

Over the next eighteen months, under the strategic direction of the Finance and Restructuring Committee of Dynegy’s Board of Directors, we may participate in additional debt restructuring activities, which may include direct or indirect transfers of our subsidiaries’ equity interests, refinancing of existing debt and lease obligations, and/or further reorganizations of our subsidiaries as well as other similar initiatives. However, we cannot provide any assurances that we will be successful in accomplishing any such activities.

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 production. 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.

Coal. The newly formed CoalCo will consist of six plants, all located in the MISO region, and totaling 3,132 MW. 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, and the facility is not included among the six CoalCo units. The Vermilion plant ceased generating electricity in the second half of March and now has reduced staffing.

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 $157 million. This estimate includes a number of assumptions about uncertainties beyond our control, such as costs associated with labor and materials.

Our Midwest coal requirements are approximately 99 percent contracted in 2011 and 97 percent contracted in 2012. All of our forecast coal requirements are 99 percent priced through 2011 and 67 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 ourselves stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies. Our CoalCo expected generation volumes are volumetrically 86 percent hedged through 2011 and approximately 20 percent hedged for 2012.

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Recent moves by various market participants expressing their intentions to either join or exit the MISO could impact system reserve margins in the future. The Midwest ISO filed proposed Resource Adequacy Enhancements with FERC on July 20, 2011. The proposed tariff revisions require capacity to be procured on a zonal basis for full planning year (June 1 — May 31) versus the current monthly requirement, with procurement occurring two months ahead of the planning year. If approved, the new construct would be in place for the 2013-14 Planning Year. While the proposed new construct is an incremental improvement over the status quo it is unlikely to have an influence on capacity prices in the near future due to excess capacity in the MISO market. In addition, 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.

Currently, CoalCo is significantly hedged volumetrically for 2011. Beyond that, the portfolio is positioned for CoalCo to benefit from possible future power market pricing improvements.

Gas. The newly formed GasCo will consist of eight plants, geographically diverse in five markets, totaling 6,771 MW. Approximately 70 percent of our power plant capacity associated in the CAISO is contracted through 2011 under tolling agreements with load-serving entities and an RMR agreement. A significant portion of the remaining capacity is sold as a resource adequacy product in the CAISO market, and much of our remaining expected production in the CAISO market has been financially hedged.

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.

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 $349 million at June 30, 2011.

In New England, five 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. During the most recent forward capacity market auction for the 2014-2015 market period, held in June of 2011, capacity cleared at $3.21 per kW-month. These capacity clearing prices represent the floor price, although the actual rate paid to Casco Bay (and other facilities) can be reduced due to oversupply conditions and/or regional export limits. 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.

In PJM, where the Kendall and Ontelaunee combined-cycle plants are located, eight forward capacity auctions (known as RPM or Reliability Pricing Model) have been held since the transition from a daily capacity market in June 2007. RPM clearing prices have ranged from $0.50/kW-month (Kendall, PY2012-13) and $1.24/kW-month (Ontelaunee, PY2007-8) to $5.30/kW-month (Kendall, PY2010-11) and $6.88/kW-month (Ontelaunee, PY2013-14). The latest RPM auction was for the 2014-2015 Planning Year, which cleared $3.83/kW-month (Kendall) and $4.15/kW-month (Ontelaunee).

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In New York, capacity prices continue to trend downward due to surplus capacity and lower demand, however, approximately 70 percent of the capacity revenue for our Independence facility has been contracted at a favorable premium compared to current market prices.

In early 2011, we were advised by one of our equipment manufacturers that several of the turbine blades at our steam turbine units at our combined cycle facilities may be defective and require replacement. During the 2011 spring maintenance overhaul of the Moss Landing facility, the steam turbine blades on units one and two were inspected and it was determined that the blades did not require replacement; however, repairs by the original equipment manufacturer were required. The repairs were completed and the units were returned to full service. The initial inspections at Kendall in the Spring of 2011 did not identify any issues with the steam turbine blades. The affected steam turbine blades at the Casco Bay facility were removed and replaced with temporary repairs pending receipt of new blades. The facility has been returned to service and has not experienced any concerns with the temporary repairs. Permanent repairs will be scheduled in the near future.

Our GasCo expected generation volumes are volumetrically 92 percent hedged through 2011 and approximately 55 percent hedged for 2012.

We plan to continue our hedging program for GasCo over a rolling 12-36 month period using various forward sale instruments. Beyond 2013, the portfolio is largely open, positioning GasCo to benefit from possible future power market pricing improvements.

Other. Other consists of the leased Roseton and Danskammer facilities in New York totaling 1,693 MW. 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 has afforded us the opportunity to further explore domestic supply and delivery options as costs of international coal supplies have increased. 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 shoulder months in much of the Northeast. The promulgation of the CSAPR is expected to further strain margins in the Northeast beginning in 2012 as more stringent pollution control requirements go into effect.

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. However, capacity prices continue to trend lower in New York due to surplus capacity and lower demand.

Our expected generation volumes are volumetrically 91 percent hedged through 2011 and approximately 40 percent hedged for 2012.

Other also includes traditional corporate support functions, including intercompany transactions and those services contemplated in the various service agreements, including the Service Agreement, Energy Management Agreements, Tax Sharing Agreement and the Cash Management Agreement, which were entered into in conjunction with the Reorganization. We have also initiated actions to further reduce costs and to improve operating performance by implementing a comprehensive improvement effort. This cost and performance improvement initiative, to be known as Dynegy PRIDE (“Producing Results through Innovation by Dynegy Employees”), will drive bottom line benefits by reducing cost structure, implementing operating improvements and increasing cash flow through balance sheet efficiencies. As we enter the balance of this year and going forward, we will review plant-level margin for additional opportunities to improve cost and performance. By year end, we expect general and administrative expense annual run rate to be below $105 million and operating expense run rate to be approximately $420 million. This compares to $163 million and $450 million respectively in 2010. We anticipate a further improvement of approximately $50 million through 2012. Please read Note 13—Subsequent Events for further discussion.

Environmental and Regulatory Matters

Please read Item 1. Business—Environmental Matters in our Form 10-K and Outlook—Environmental and Regulatory Matters in our Form 10-Q for the quarter ended March 31, 2011 for a more detailed discussion.

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. 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 (“CEQA”) and enjoined further implementation of the AB 32 cap-and-trade program until the Board achieves compliance. In response to the court’s decision, on June 13, 2011, the CARB released for public comment a supplement to its CEQA analysis. In late June 2011, the California Court of Appeal stayed the trial court’s injunction, clearing the way for the CARB to proceed with cap-and-trade program rulemaking activities while it appeals the trial court’s ruling. On July 25, 2011, the CARB released proposed revisions to certain elements of the cap-and-trade program, including a delay in the start of the cap-and-trade rule’s compliance obligations until 2013. We will continue to monitor the CARB’s cap-and-trade program rulemaking activities, including its response to the court’s decision, and evaluate any potential impacts on our operations.

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On January 1, 2009, our assets in New York and Maine became subject to a state-driven GHG emission control program known as RGGI. In June 2011, RGGI held its twelfth auction, in which approximately 12.5 million allowances for the current control period, and 943,000 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.

Cross-State Air Pollution Rule. On July 6, 2011, the EPA issued its final rule on Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (the “Cross-State Air Pollution Rule”, formerly known as the Transport Rule). The CSAPR, which in response to a court decision replaces EPA’s 2005 CAIR, is intended to reduce emissions of SO2 and NOx from large electric generating units in 27 states in the eastern half of the United States. The rule imposes cap and trade programs within each affected state that cap emissions of SO2 and NOx at levels predicted to eliminate that state’s contribution to nonattainment in, or interference with maintenance of attainment status by, down-wind areas with respect to the National Ambient Air Quality Standards for particulate matter (PM2.5) and ozone. The rule will be implemented initially through federal implementation plans that are effective in each affected state 60 days after the rule is published in the Federal Register. Our generating facilities in Illinois, New York and Pennsylvania will be subject to the rule.

Under the CSAPR, Illinois, New York and Pennsylvania will be subject to new cap and trade programs capping emissions of NOx from May 1 through September 30 and capping emissions of SO2 and NOx, respectively, on an annual basis. Requirements applicable to NOx emissions require compliance with the annual NOx reductions beginning January 1, 2012 and ozone season NOx reductions beginning May 1, 2012. The requirements applicable to SO2 emissions from electric generating units in Illinois, New York and Pennsylvania will be implemented in two stages with compliance dates of January 1, 2012 and January 1, 2014. The SO2 emission budgets will be reduced in 2014, and existing electric generating units in these states will be allocated fewer SO2 emission allowances beginning in 2014. The EPA will initially allocate NOx and SO2 emission allowances to existing electric generating units based on historic heat input (i.e., the highest three-year average in the period 2006-2010), subject to a maximum allocation limit to any individual unit based on that unit’s maximum historic baseline emissions during the period 2003-2010. States submitting a SIP to achieve the required reductions in place of the federal implementation plan would be allowed to use different allowance allocation methodologies beginning with vintage year 2013.

Electric generating units are required to hold one emission allowance for every ton of SO2 and/or NOx emitted during the applicable compliance period. Electric generating units can comply with the required emission reductions by any combination of (i) installing emission control technologies, (ii) operating existing controls more often, (iii) switching fuels, or (iv) curtailing or ceasing operation. Allowance trading is generally allowed under the CSAPR among sources within the same state with limited interstate allowance trading.

Based on the allowance allocations in the final rule and our current projections of emissions in 2012, we anticipate that our coal facilities located in the Midwest will have an adequate number of allowances in 2012 under each of the three applicable CSAPR cap-and-trade programs (SO2, NOx annual, and NOx ozone season). For our Danskammer and Roseton facilities, we anticipate a shortfall of allocated allowances in 2012 under each of the three programs. We continue to review the CSAPR and to evaluate any potential impacts it might have on our operations.

New York Water Intake Policy. On July 10, 2011, the NYSDEC issued its final policy on “Best Technology Available (BTA) for Cooling Water Intake Structures” (the “NYSDEC Policy”). The NYSDEC Policy establishes wet closed-cycle cooling or its equivalent (i.e., reductions in impingement mortality and entrainment from calculation baseline that are 90 percent or greater of that which would be achieved by wet closed-cycle cooling) as the performance goal for existing power plants. The NYSDEC Policy exempts existing power generation facilities operated at less than 15 percent of capacity over a current five-year averaging period from the entrainment performance goal, provided that the facility is operated in a manner that minimizes the potential for entrainment. For these low capacity facilities, NYSDEC will determine site-specific performance goals for entrainment on a best professional judgment basis. For facilities for which a BTA determination was issued prior to adoption of the policy and which are in compliance with an existing BTA compliance schedule and verification monitoring, the NYSDEC Policy does not apply unless and until the results of verification monitoring demonstrate the necessity of more stringent BTA requirements. At this time we do not believe that the NYSDEC Policy will have a material impact on operations of our subject power generation facilities given the prior BTA determination for Danskammer and the entrainment exemption for low capacity facilities.

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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. 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 is expected to issue final regulations governing CCR management in 2012 or later. Federal legislation to address CCR also has been introduced in Congress. On July 13, 2011, the House Energy and Commerce Committee approved H.R. 2273, the Coal Residuals Reuse and Management Act, which would authorize the states to implement a subtitle D permit program for CCR disposal units. The permit requirements would include structural integrity standards and certain elements of the subtitle D criteria for municipal solid waste landfills, including location restrictions, design standards, ground water monitoring, financial assurance, corrective action, closure and post-closure care. The EPA would be authorized to administer and enforce the subtitle D criteria for CCR disposal units only if a state chooses not to do so or if the EPA finds that the state program is deficient.

The nature and scope of potential future requirements for CCR 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.

RISK-MANAGEMENT DISCLOSURES

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

	As of and for the Six Months Ended June 30, 2011
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at December 31, 2010	$	34
Risk-management losses recognized through the income statement in the period, net	(78		)
Cash received related to risk-management contracts settled in the period, net	(48		)
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 June 30, 2011	$	(93	)

(1) Our modeling methodology has been consistently applied.

The net risk management liability of $93 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.

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Risk-Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of June 30, 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)	$	(105	)	$	(14	)	$	(91	)	$	—	$	—	$	—	$	—
Prices based on models	12			4			(5		)	13		—		—		—

Total	$	(93	)	$	(10	)	$	(96	)	$	13	$	—	$	—	$	—

(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;

· 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;

· the anticipated effectiveness of the overall restructuring activities and any additional strategies to address our liquidity and our capital resources including accessing the capital markets;

· limitations on our ability to utilize 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;

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· 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 credit facility compliance, collateral demands, capital expenditures, interest expense and other payments;

· 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.

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 June 30, 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 June 30, 2011 VaR was primarily due to decreased forward sales as compared to December 31, 2010.

Daily and Average VaR for Risk-Management Portfolios

	June 30, 2011		December 31, 2010
	(in millions)
One day VaR—95 percent confidence level	$	10	$	14
One day VaR—99 percent confidence level	$	15	$	20
Average VaR for the year-to-date period—95 percent confidence level	$	11	$	22

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Credit Risk. The following table represents our credit exposure at June 30, 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	$	10	$	—	$	10
Oil and gas producers	6		—		6
Utility and power generators	37		—		37
Commercial / Industrial /End Users	4		1		5
Other	1		—		1

Total	$	58	$	1	$	59

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of June 30, 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 74 percent. Adjusted for interest rate swaps, net notional fixed rate debt, as a percentage of total debt, was approximately 74 percent. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of June 30, 2011, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the twelve months ended June 30, 2012 would either decrease or increase interest expense by approximately $13 million. This exposure would have been partially offset by an approximate $9 million increase or decrease in interest income related to the restricted cash balance of $850 million posted as collateral to support DHI’s former term letter of credit facility. On August 5, 2011, we entered into the GasCo Term Loan Facility and the CoalCo Term Loan Facility which replaced DHI’s term letter of credit facility. Please read Note13—Subsequent Events for further discussion. Over time, we may seek to adjust the variable rate exposure in our debt portfolio through the use of swaps or other financial instruments.

The absolute notional financial contract amounts associated with our interest rate contracts were as follows at June 30, 2011 and December 31, 2010, respectively:

	June 30, 2011		December 31, 2010
Fair value hedge interest rate swaps (in millions of U.S. dollars)	$	—	$	25
Fixed interest rate received on swaps (percent)	—		5.70
Interest rate risk-management contracts (in millions of U.S. dollars)	$	—	$	231
Fixed interest rate paid (percent)	—		5.35
Interest rate risk-management contracts (in millions of U.S. dollars)	$	—	$	206
Fixed interest rate received (percent)	—		5.28

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

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of Dynegy’s and DHI’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended). This evaluation included consideration of the various processes carried out under the direction of Dynegy’s and DHI’s disclosure committee. This evaluation also considered the work completed relating to Dynegy’s and DHI’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, Dynegy’s and DHI’s CEO and CFO concluded that Dynegy’s and DHI’s disclosure controls and procedures were effective as of June 30, 2011.

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Changes in Internal Controls Over Financial Reporting

There were no changes in Dynegy’s and DHI’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect Dynegy’s and DHI’s internal control over financial reporting during the quarter ended June 30, 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 7—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.

In addition to the risk factors below, please read Item 1A—Risk Factors, of our Form 10-K for factors, risks and uncertainties that may affect future results.

In the absence of successful debt restructuring and/or refinancing, there can be no assurance that DHI or its subsidiaries responsible for the Roseton and Danskammer lease obligations will have sufficient resources to pay existing indebtedness.

DHI remains highly leveraged following the closing of the GasCo Term Loan Facility and CoalCo Term Loan Facility (together, the “New Credit Facilities”) as the issuer of $3.5 billion of senior unsecured notes and as a guarantor of the lease obligations associated with the Roseton and Danskammer facilities. In the absence of successful debt restructuring and/or refinancing, there can be no assurance that DHI or its subsidiaries responsible for the Roseton and Danskammer lease obligations (i.e., Dynegy Roseton, LLC and Dynegy Danskammer, LLC) will have sufficient resources to pay existing indebtedness. The New Credit Facilities will restrict the ability of GasCo and CoalCo to pay dividends or make other restricted payments after giving effect to the distributions for the repayment of the existing DHI senior secured credit facilities and the payment by each of GasCo and CoalCo of an additional dividend of up to $200 million each at closing. Further, the secured assets are only available for GasCo Intermediate Holdings or CoalCo Intermediate Holdings and their subsidiaries’ respective creditors (not to Dynegy or any of its other subsidiaries).

A plaintiff’s successful challenge to the Reorganization could adversely affect the Company’s future restructuring efforts.

While the Reorganization has been completed and the two New Credit Facilities have closed, post-closing challenges to the Reorganization may come from creditors who believe they have been disadvantaged by the Reorganization or from creditors otherwise seeking to enhance their negotiating leverage through legal process in any of Dynegy’s future restructuring efforts. While we cannot predict the exact effects of any successful challenge to the Reorganization, a successful challenge to the Reorganization could have a material adverse effect on the Company’s ability in the future to restructure its outstanding indebtedness.

The outcome of ongoing and future legal proceedings may have a material adverse effect on our business operations, financial condition, results of operations and cash flows.

We are subject to certain ongoing legal proceedings for which management believes a material loss is at least reasonably possible. These legal proceedings include the matters set forth in Note 7—Commitments and Contingencies to our unaudited condensed consolidated financial statements for the interim period ended June 30, 2011.

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In addition, on July 21, 2011, complaints were filed in New York state court and the Court of Chancery for the State of Delaware (“Delaware Court”), including one by the owner/lessor of the Danskammer and Roseton facilities. The plaintiffs allege breach of contract and violation of prohibitions on fraudulent transfers and sought permanent injunctive relief seeking to prevent our Restructuring announced on July 10, 2011, a declaratory judgment and damages. The Delaware plaintiffs also sought to temporarily enjoin the consummation of the debt restructuring (the “TRO Motion”). The proceedings in New York were stayed pending the disposition of the proceedings in Delaware. The Delaware Court denied the TRO Motion and a preliminary injunction, and the Supreme Court of Delaware denied plaintiffs’ request for an interlocutory appeal and an injunction pending appeal.

We believe the allegations made by the plaintiffs in both of these recent lawsuits lack merit and intend to defend vigorously our position in these and any other proceedings that may arise as a result of any proceedings involving the Reorganization and the New Credit Facilities or any future restructuring activities. It might be alleged that the Reorganization and the New Credit Facilities, together with any future restructuring activity, constitutes an integrated scheme involving fraudulent transfers, and seek in some manner to unwind all of the transactions in an effort to return the various transferred property to its original owners. Any such extraordinary remedy may have a material adverse effect on our business operation, financial condition, results of operations and cash flows.

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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 to employees, shares are withheld to cover the employees’ withholding taxes. Information on our purchases of equity securities during the quarter follows:

Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
April 1-30	662	$	5.72	—	N/A
May 1-31	—	$	—	—	N/A
June 1-30	—	$	—	—	N/A

Total	662	$	5.72	—	N/A

These were the only purchases of equity securities made by us during the three months ended June 30, 2011. We do not have a stock repurchase program.

Item 5—OTHER INFORMATION—DYNEGY INC.

On June 15, 2011, Dynegy held its 2011 Annual Meeting of Stockholders. A majority of the votes present in person or represented by proxy and entitled to vote at the annual meeting voted, on an advisory basis, to hold an advisory vote to approve executive compensation annually. In line with this recommendation by our stockholders, Dynegy will include an advisory stockholder vote on executive compensation in its proxy materials every year until the next required advisory vote on the frequency of stockholder votes on executive compensation, which will occur no later than our annual meeting of stockholders in 2017.

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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		Phantom Stock Unit Award Agreement between Dynegy Inc. and E. Hunter Harrison dated June 30, 2011.

**10.2		First Amendment to the Dynegy Inc. 2009 Phantom Stock Plan, dated as of July 8, 2011.

**10.3		Employment Agreement between Dynegy Inc. and Robert Flexon dated June 22, 2011.

**10.4		Employment Agreement between Dynegy Inc. and Kevin Howell dated June 22, 2011.

**10.5		Employment Agreement between Dynegy Inc. and Clint C. Freeland dated June 23, 2011.

**10.6		Employment Agreement between Dynegy Inc. and Carolyn J. Burke dated July 5, 2011.

**10.7		Non-Qualified Stock Option Award Agreement between Dynegy Inc. and Robert C. Flexon date July 11, 2011.

**10.8		Stock Appreciation Right Award Agreement between Dynegy Inc. and Robert C. Flexon dated July 11, 2011.

**10.9		Non-Qualified Stock Option Award Agreement between Dynegy Inc. and Kevin T. Howell date July 5, 2011.

**10.10		Non-Qualified Stock Option Award Agreement between Dynegy Inc. and Clint C. Freeland date July 5, 2011.

**10.11		Transition Services Agreement between Dynegy Inc. and Lynn Lednicky dated June 28, 2011.

10.12		Credit Agreement, dated as of August 5, 2011, among Dynegy Midwest Generation, LLC, as borrower and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

10.13		Credit Agreement dated as of August 5, 2011 among Dynegy Power, LLC and the guarantors, lenders and other parties thereto (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

10.14		Guarantee and Collateral Agreement, dated as of August 5, 2011 among Dynegy Midwest Generation, LLC, the subsidiaries of the borrower from time to time party thereto and other parties thereto (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

10.15		Guarantee and Collateral Agreement, dated as of August 5, 2011 among Dynegy Power, LLC, the subsidiaries of the borrower from time to time party thereto and other parties thereto (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

10.16		Letter of Credit Reimbursement and Collateral Agreement, dated as of August 5, 2011 among Dynegy Midwest Generation, LLC and Credit Suisse AG, Cayman Islands Branch (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

10.17		Collateral Trust and Intercreditor Agreement, dated as of August 5, 2011 among Dynegy Coal Investments Holdings, LLC, Dynegy Midwest Generation, LLC, the guarantors and the other parties thereto (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

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Exhibit Number		Description

10.18		Collateral Trust and Intercreditor Agreement, dated as of August 5, 2011 among Dynegy Gas Investment Holdings, LLC, Dynegy Power LLC, the guarantors and the other parties thereto (incorporated by reference to Exhibit 10.7 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

10.19		Letter of Credit Reimbursement and Collateral Agreement, dated as of August 5, 2011 between Dynegy Power LLC and Credit Suisse AG, Cayman Islands Branch (incorporated by reference to Exhibit 10.8 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

10.20		Letter of Credit Reimbursement and Collateral Agreement, dated as of August 5, 2011 between Dynegy Holdings Inc. and Credit Suisse AG, Cayman Islands Branch (incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K of Dynegy Inc and Dynegy Holdings Inc. filed on August 8, 2011, File No. 001-33443).

**10.21		Letter of Credit Reimbursement and Collateral Agreement, dated as of August 5, 2011 among Dynegy Power LLC and Barclays Bank PLC

**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.

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Exhibit Number		Description

†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		Dynegy and Dynegy Holdings XBRL Instance Document

**101.SCH		Dynegy and Dynegy Holdings XBRL Taxonomy Extension Schema Document

**101.CAL		Dynegy and Dynegy Holdings XBRL Taxonomy Extension Calculation Linkbase Document

**101.DEF		Dynegy and Dynegy Holdings XBRL Taxonomy Extension Definition Linkbase Document

**101.LAB		Dynegy and Dynegy Holdings XBRL Taxonomy Extension Label Linkbase Document

**101.PRE		Dynegy and Dynegy Holdings XBRL Taxonomy Extension Presentation Linkbase Document

** Filed herewith.

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

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DYNEGY INC. and DYNEGY HOLDINGS INC.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		DYNEGY INC.

Date: August 8, 2011	By:	/s/ CLINT C. FREELAND
		Clint C. Freeland Executive Vice President and Chief Financial Officer


		DYNEGY HOLDINGS INC.

Date: August 8, 2011	By:	/s/ CLINT C. FREELAND
		Clint C. Freeland Executive Vice President and Chief Financial Officer