Edgar Filing: DYNEGY INC.

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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, 2012

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

For the transition period from to

Commission file number: 001-33443

DYNEGY INC.

(Exact name of registrant as specified in its charter)

State of Incorporation		I.R.S. Employer Identification No.
Delaware		20-5653152

601 Travis, Suite 1400
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. 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). 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 o

Accelerated filer x

Non-accelerated filer o

(Do not check if a smaller reporting company)

Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

Indicate the number of shares outstanding of our classes of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 122,889,323 shares outstanding as of July 30, 2012.

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DYNEGY INC.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets: June 30, 2012 and December 31, 2011		5
Condensed Consolidated Statements of Operations: For the three and six months ended June 30, 2012 and 2011		6
Condensed Consolidated Statements of Comprehensive Loss: For the three and six months ended June 30, 2012 and 2011		7
Condensed Consolidated Statements of Cash Flows: For the three and six months ended June 30, 2012 and 2011		8
Notes to Condensed Consolidated Financial Statements		9

Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	35
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	67
Item 4.	CONTROLS AND PROCEDURES	68

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS	69
Item 1A.	RISK FACTORS	69
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	72
Item 6.	EXHIBITS	73

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DEFINITIONS

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

ASC		Accounting Standards Codification
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
CFTC		Commodity Futures Trading Commission
CO2		Carbon Dioxide
CRCG		Commodity Risk Control Group
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
DCIH		Dynegy Coal Intermediate Holdings, LLC
DGIH		Dynegy Gas Investment Holdings, LLC
DGIN		Dynegy Gas Investments, LLC
DH		Dynegy Holdings, LLC (formerly known as Dynegy Holdings Inc.)
DMG		Dynegy Midwest Generation, LLC
DMSLP		Dynegy Midstream Services L.P.
DPC		Dynegy Power, LLC
DPM		Dynegy Power Marketing, LLC
EBITDA		Earnings before interest, taxes, depreciation and amortization
EGU		Electric generating unit
EMA		Energy Management Agreement
EMT		Executive Management Team
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
GAAP		Generally Accepted Accounting Principles of the United States of America
GEN Finance		Dynegy Gen Finance Company, LLC
GHG		Greenhouse Gas
HAPs		Hazardous air pollutants, as defined by the Clean Air Act
ICC		Illinois Commerce Commission
IMA		In-market asset availability
IFRS		International Financial Reporting Standards

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ISO		Independent System Operator
ISO-NE		Independent System Operator New England
LC		Letter of credit
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
NODA		Notice of Data Availability
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
PSD		Prevention of significant deterioration
RACT		Reasonably available control technology
RCRA		Resource Conservation and Recovery Act
RCM		Resources Capital Management Corporation
RFO		Request for offers
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must Run
RTO		Regional Transmission Organization
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
VLGC		Very Large Gas Carrier
WCI		Western Climate Initiative

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PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

	June 30, 2012			December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	51		$	396
Restricted cash and investments	—			69
Accounts receivable, net of allowance for doubtful accounts of $19 and $19, respectively	—			6
Accounts receivable, affiliates	1			47
Inventory	—			57
Assets from risk-management activities	—			65
Assets from risk-management activities, affiliates	—			4
Deferred income taxes	—			5
Broker margin account	—			10
Prepayments and other current assets	1			13
Total Current Assets	53			672
Property, Plant and Equipment	—			4,878
Accumulated depreciation	—			(1,544		)
Property, Plant and Equipment, Net	—			3,334
Other Assets
Investment in DH	63			—
Restricted cash and investments	3			103
Assets from risk-management activities	—			1
Assets from risk-management activities, affiliates	—			3
Other long-term assets	—			14
Total Assets	$	119		$	4,127
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities
Accounts payable	$	—		$	15
Accounts payable, affiliates	—			26
Accrued interest, affiliates	—			8
Accrued liabilities and other current liabilities	24			40
Liabilities from risk-management activities	—			64
Liabilities from risk-management activities, affiliates	—			2
Current portion of long-term debt	—			4
Total Current Liabilities	24			159
Long-term debt	—			584
Long-term debt to affiliates	—			1,250
Long-Term Debt	—			1,834
Other Liabilities
Accounts payable, affiliates	—			870
Liabilities from risk-management activities	—			2
Deferred income taxes	—			5
Other long-term liabilities	97			145
Total Liabilities	121			3,015
Commitments and Contingencies (Note 8)
Stockholders’ Equity (Deficit)
Common Stock, $0.01 par value, 420,000,000 shares authorized at June 30, 2012 and December 31, 2011; 123,630,089 shares and 123,585,877 shares issued and outstanding at June 30, 2012 and December 31, 2011, respectively	1			1
Additional paid-in capital	6,080			6,077
Subscriptions receivable	(2		)	(2		)
Accumulated other comprehensive loss, net of tax	(48		)	(53		)
Accumulated deficit	(5,963		)	(4,841		)
Treasury stock, at cost, 740,766 shares and 731,407 shares at June 30, 2012 and December 31, 2011, respectively	(70		)	(70		)
Total Stockholders’ Equity (Deficit)	(2		)	1,112
Total Liabilities and Stockholders’ Equity (Deficit)	$	119		$	4,127

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,
	2012			2011			2012			2011
Revenues	$	53		$	326		$	230		$	831
Cost of sales	(46		)	(225		)	(132		)	(503		)

Gross margin, exclusive of depreciation shown separately below	7			101			98			328
Operating and maintenance expense, exclusive of depreciation shown separately below	(30		)	(106		)	(69		)	(216		)
Depreciation and amortization expense	(28		)	(75		)	(78		)	(201		)
Loss on Coal Holdco Transfer (Note 3)	(941		)	—			(941		)	—
Impairment and other charges	—			(1		)	—			(1		)
General and administrative expenses	(44		)	(25		)	(67		)	(65		)

Operating loss	(1,036		)	(106		)	(1,057		)	(155		)
Loss from unconsolidated investment (Note 7)	(1		)	—			(1		)	—
Interest expense	(27		)	(89		)	(64		)	(178		)
Other income and expense, net	—			3			—			4
Loss from continuing operations before income taxes	(1,064		)	(192		)	(1,122		)	(329		)
Income tax benefit (Note 12)	—			76			—			136
Net loss	$	(1,064	)	$	(116	)	$	(1,122	)	$	(193	)

Loss Per Share (Note 14):

Basic loss per share	$	(8.65	)	$	(0.95	)	$	(9.12	)	$	(1.58	)
Diluted loss per share	$	(8.65	)	$	(0.95	)	$	(9.12	)	$	(1.58	)

Basic shares outstanding	123			122			123			122
Diluted shares outstanding	123			122			123			122

See the notes to condensed consolidated financial statements

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)

	Three Months Ended June 30,
	2012			2011
Net loss	$	(1,064	)	$	(116	)
Other comprehensive income:
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of zero and $1)	1			1
Reclassification of mark-to-market losses to earnings, net	1			—
Total other comprehensive income, net of tax	2			1
Total Comprehensive loss	$	(1,062	)	$	(115	)

	Six Months Ended June 30,
	2012			2011
Net loss	$	(1,122	)	$	(193	)
Other comprehensive income:
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of zero and $1)	4			2
Reclassification of mark-to-market losses to earnings, net	1			—
Total other comprehensive income, net of tax	5			2
Total Comprehensive loss	$	(1,117	)	$	(191	)

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,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,122	)	$	(193	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization	80			209
Loss on Coal Holdco Transfer	941			—
Impairment and other charges	—			1
Risk-management activities	(4		)	127
Loss on unconsolidated investments	1			—
Deferred income taxes	—			(135		)
Other	3			24
Changes in working capital:
Accounts receivable	3			60
Inventory	(12		)	(4		)
Broker margin account	2			(92		)
Prepayments and other assets	1			1
Accounts payable and accrued liabilities	10			(55		)
Affiliate transactions	(6		)	—
Changes in non-current assets	—			(33		)
Changes in non-current liabilities	5			4
Net cash used in operating activities	(98		)	(86		)

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(42		)	(128		)
Coal Holdco Transfer	(256		)	—
Maturities of short-term investments	—			217
Purchases of short-term investments	—			(247		)
Changes in restricted cash and investments	55			53
Other investing	(2		)	10
Net cash used in investing activities	(245		)	(95		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs of zero and $1, respectively	—			399
Repayments of borrowings	(2		)	(113		)
Net proceeds from issuance of capital stock	—			3
Net cash provided by (used in) financing activities	(2		)	289

Net increase (decrease) in cash and cash equivalents	(345		)	108
Cash and cash equivalents, beginning of period	396			291
Cash and cash equivalents, end of period	$	51		$	399

Other non-cash investing activity:
Non-cash capital expenditures	$	(3	)	$	(7	)
Investment in DH	(64		)	—

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

See the notes to condensed consolidated financial statements

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

Note 1—Basis of Presentation and Organization

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. Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. Discussions or areas of this report that apply only to Dynegy or Dynegy Holdings, LLC (“DH”) are clearly noted in such sections or areas and specific defined terms may be introduced for use only in those sections or areas. 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. 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. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011, filed on March 8, 2012, which we refer to as our “Form 10-K”.

Organization

We are a holding company 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 segments in our consolidated financial statements: (i) the Coal segment (“Coal”); (ii) the Gas segment (“Gas”) and (iii) the Dynegy Northeast segment (“DNE”). Prior to the third quarter 2011, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Our consolidated financial results also reflect corporate-level expenses such as interest and depreciation and amortization. General and administrative expenses are allocated to each reportable segment. Accordingly, we have recast the corresponding items of segment information for all prior periods.

With the commencement of the DH Chapter 11 Cases (as defined below), DH and its direct and indirect subsidiaries, including the subsidiaries in our Gas and DNE segments, were deconsolidated effective November 7, 2011. Financial statements presented after November 7, 2011 reflect our investment in, and the results of operations of, DH and its wholly-owned subsidiaries under the equity method of accounting. For further discussion, please read Note 3—Chapter 11 Cases and Note 7—Variable Interest Entities. Additionally, effective June 5, 2012, we transferred the Coal segment to DH; therefore, the results of the Coal segment are only included in our results through June 5, 2012. See further discussion below.

Chapter 11 Filing by Dynegy and Certain Subsidiaries. On November 7, 2011, DH and four of its wholly-owned subsidiaries, Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C. and Dynegy Roseton, L.L.C. (collectively, the “DH Debtor Entities” ) filed voluntary petitions (the “DH Chapter 11 Cases”) for relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of New York, Poughkeepsie Division (the “Bankruptcy Court”). The DH Chapter 11 Cases were assigned to the Honorable Cecelia G. Morris and are being jointly administered for procedural purposes only under the caption In re: Dynegy Holdings, LLC, et. al, Case No. 11-38111. On July 6, 2012, Dynegy filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court (the “Dynegy Chapter 11 Case,” and together with the DH Chapter 11 Cases, the “Chapter 11 Cases”). The Dynegy Chapter 11 Case was also assigned to the Honorable Cecilia G. Morris, but it is being separately administered under the caption In re: Dynegy Inc., Case No. 12-36728. Dynegy’s subsidiaries, other than the five DH Debtor Entities, did not file voluntary petitions for relief and are not debtors under the Bankruptcy Code and, consequently, continue to operate their business in the ordinary course. For further discussion, please read Note 3—Chapter 11 Cases.

Going Concern. The accompanying financial statements have been prepared on a going concern basis of accounting. However, as discussed in Note 3—Chapter 11 Cases, our ability to continue as a going concern is

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

contingent upon the Bankruptcy Court’s approval of the Plan (as defined below) and our ability to successfully implement the Plan, among other factors. As a result of the Chapter 11 Cases, the realization of assets and the satisfaction of liabilities are subject to uncertainty. Furthermore, on June 5, 2012, the effective date of the Settlement Agreement, (as defined and discussed in Note 3—Chapter 11 Cases) we assigned and contributed 100% of our outstanding equity interests in Dynegy Coal Holdco, LLC (“Coal Holdco”) to DH (the “Coal Holdco Transfer”). Coal Holdco is the indirect owner of our assets in the Coal segment, therefore, subsequent to the transfer, we have no operating assets outside of our equity investment in DH. As a result of the Coal Holdco Transfer and the lack of operating assets until DH’s expected emergence from bankruptcy, we believe there is substantial doubt about our ability to continue as a going concern. Please read Note 3—Chapter 11 Cases for further discussion.

Note 2—Accounting Policies

Use of Estimates

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. Actual results could differ materially from our estimates. 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, charges associated with the Chapter 11 Cases, and other factors.

Accounting Principles Adopted During the Current Period

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 IFRS (“ASU No. 2011-04”). This authoritative guidance changes the wording used to describe the requirements in GAAP for measuring fair value and requires additional disclosure about fair value measurements. ASU No. 2011-04 is effective for interim and annual periods beginning after December 15, 2011. The implementation of this guidance has been reflected in Note 5—Fair Value Measurements.

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 have elected to present comprehensive income as two separate consecutive statements.

Note 3—Chapter 11 Cases

On November 7, 2011, the DH Debtor Entities commenced the DH Chapter 11 Cases. On July 6, 2012, Dynegy commenced the Dynegy Chapter 11 Case. Dynegy and the DH Debtor Entities (together, the “Debtor Entities”) remain in possession of their property and continue to operate their business as “debtors in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. The Dynegy Chapter 11 Case is a necessary step to facilitate the restructuring contemplated by the Plan and the Agreements (as defined and discussed below), including the planned merger of Dynegy and DH (the “Merger”).

None of Dynegy’s direct or indirect subsidiaries, other than the five DH Debtor Entities, sought relief under the Bankruptcy Code, and none of those entities are debtors thereunder. Coal Holdco and Dynegy GasCo Holdings, LLC and their indirect, wholly-owned subsidiaries (including Dynegy Midwest Generation, LLC (“DMG”) and Dynegy Power, LLC

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

(“DPC”)) are not included in the Chapter 11 Cases. The normal day-to-day operations of the coal-fired power generation facilities held by DMG and the gas-fired power generation facilities held by DPC have continued without interruption. The commencement of the Chapter 11 Cases did not constitute an event of default under either DMG’s senior secured term loan facility (the “DMG Credit Agreement) or DPC’s senior secured term loan facility (the “DPC Credit Agreement”).

On November 7, 2011, the DH Debtor Entities filed a motion with the Bankruptcy Court for authorization to reject the leases of the Roseton and Danskammer power generation facilities (the “Facilities”) and sought to impose a cap on the lease rejection damages under Section 502(b)(6) of the Bankruptcy Code. On December 13, 2011, Dynegy and the DH Debtor Entities entered into a binding term sheet with Resources Capital Management Corporation (“RCM”), Resources Capital Asset Recovery, L.L.C., Series DD and Series DR, Roseton OL LLC, Danskammer OL LLC, Roseton OP LLC and Danskammer OP LLC (collectively with RCM, the “PSEG Entities”), as the owners and lessors of the Roseton and a portion of Danskammer facilities, to settle and resolve issues among them in lieu of further litigation, regarding, among other things, the Roseton and Danskammer leases and all of the parties’ rights and claims arising under the related lease documents, including certain tax indemnity agreements (the “PSEG Settlement”).

On December 20, 2011, the Bankruptcy Court entered a stipulated order (as amended by a stipulated order entered by the Bankruptcy Court on December 28, 2011) approving the rejection of the Roseton and Danskammer leases subject to certain conditions. The DH Debtor Entities have operated and plan to continue operating the leased facilities until such facilities can be sold in accordance with the terms of the Agreements (as defined below) and in compliance with applicable federal and state regulatory requirements. Please read the section entitled “Settlement Agreement and Plan Support Agreement” below for further discussion.

Adversary Proceeding and Examiner Report. On November 11, 2011, U.S. Bank National Association (“U.S. Bank”), in its capacity as successor lease indenture trustee (the “Lease Trustee”) under the Indenture of Trust, Mortgage, Assignment of Leases and Rents and Security Agreement related to Roseton Units 1 and 2, dated as of May 8, 2001, and the Indenture of Trust, Mortgage, Assignment of Leases and Rents and Security Agreement related to Danskammer Units 3 and 4, dated as of May 8, 2001 (collectively, the “Lease Indentures”), commenced an adversary proceeding against Dynegy Danskammer, L.L.C. (“Dynegy Danskammer”), Dynegy Roseton, L.L.C (“Dynegy Roseton”) and DH (the “Adversary Proceeding”). The Lease Indentures govern the terms of the notes issued by Roseton OL LLC and Danskammer OL LLC, as owner lessors of the Facilities, to the pass through trust established under the Roseton-Danskammer 2001-Series B Pass Through Trust Agreement, dated as of May 1, 2001 (the “Pass Through Trust Agreement”). The Adversary Proceeding sought, among other things, a declaration that: (i) the leases of the Facilities to Dynegy Roseton and Dynegy Danskammer are not leases of real property; (ii) the leases are financings, not leases; (iii) notwithstanding the lease rejection claims, claims arising from DH’s guaranty of certain of the Facilities’ lease obligations are not subject to a cap pursuant to section 502(b)(6) of the Bankruptcy Code; and (iv) a determination of the allowed amount of the Lease Trustee’s claims against Dynegy Danskammer, Dynegy Roseton, and DH.

Dynegy Danskammer, Dynegy Roseton and DH contested the claims made in the Adversary Proceeding, including the attempt to recharacterize the leases of the Facilities as financings and not as leases of real property and the applicability of Section 502(b)(6) of the Bankruptcy Code. The parties to the Adversary Proceeding filed motions seeking judgment on the pleadings and subsequently agreed to an informal stay of the proceedings, pending further settlement negotiations among the parties as discussed below under “Settlement Agreement and Plan Support Agreement.”

On November 11, 2011, the Lease Trustee also filed a motion with the Bankruptcy Court seeking the appointment of an examiner. On December 29, 2011, the Bankruptcy Court entered an order directing the appointment of the examiner (the “Examiner”), which order provided, among other things, that the Examiner investigate (i) the DH Debtor Entities’ conduct in connection with the prepetition 2011 restructuring and reorganization of the DH Debtor Entities and their non-debtor affiliates (the “Prepetition Restructurings”), (ii) any possible fraudulent conveyances and (iii) whether DH was capable of confirming a Chapter 11 plan of reorganization. On March 9, 2012, the Examiner filed a report with the Bankruptcy Court and on March 20, 2012, Dynegy filed a preliminary response to such report.

All disputes and claims related to the Adversary Proceeding or otherwise related to the rejection of the Lease Documents have been resolved by the Settlement Agreement. Upon the effectiveness of the Settlement Agreement, the Adversary Proceeding was dismissed with prejudice and any potential claims relating to or arising from disputes with respect to, among

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

other things, the Adversary Proceeding and the Lease Documents were released. In addition, pursuant to the Settlement Agreement, Dynegy, DH and the other settling parties have released any potential claims relating to or arising from disputes with respect to the matters investigated by the Examiner, including, among other things, the Prepetition Restructurings and including, without limitation, any claims that have been or could have been brought in connection with the transfer of the membership interests in Coal Holdco to Dynegy, the Undertaking Agreement or the DH note, described in Note 20-Related Party Transactions-Transactions with DH-DMG Transfer and Undertaking Agreement in our Form 10-K.

Settlement Agreement and Plan Support Agreement. On May 1, 2012, Dynegy, DGIN, Coal Holdco, the DH Debtor Entities, certain beneficial holders of approximately $1.9 billion of DH’s outstanding senior notes (the “Consenting Senior Noteholders”), the PSEG Entities and the Lease Trustee, as directed by a majority of, and on behalf of all holders of those certain pass through trust certificates issued pursuant to the Pass Through Trust Agreement (the “Lease Certificate Holders” and, collectively the “Original Settlement Parties”) entered into a settlement agreement (the Original Settlement Agreement”). On May 30, 2012, the Original Settlement Parties, holders of a majority of the outstanding subordinated notes (the “Consenting Sub Debt Holders”) and, solely with respect to certain sections of the Settlement Agreement (as defined below), the successor trustee under DH’s subordinated notes indenture (“Wells Fargo” and collectively, with the Original Settlement Parties and the Consenting Sub Debt Holders, the “Settlement Parties”) entered into an amended and restated settlement agreement (the “Settlement Agreement”).

Also on May 1, 2012, Dynegy, DGIN, Coal Holdco, the Debtor Entities, the Consenting Senior Noteholders, the PSEG Entities and certain Lease Certificate Holders (the “Consenting Lease Certificate Holders”) entered into a plan support agreement (the “Original Plan Support Agreement”). On May 30, 2012, the parties to the Original Plan Support Agreement entered into an amended and restated plan support agreement including the Consenting Sub Debt Holders (the “Plan Support Agreement” and, together with the Settlement Agreement, the “Agreements”), providing for, among other things, the treatment of claims and certain rights and obligations of the supporting creditor parties as well as the Consenting Senior Noteholders thereunder. Additionally, pursuant to the Plan Support Agreement, Dynegy and DH each agreed, subject to the terms of the Plan Support Agreement, to amend the then existing plan of reorganization for DH to reflect the terms contained in the Plan Support Agreement. On July 31, 2012, as provided for in the Disclosure Statement, Dynegy, DH, the Consenting Senior Noteholders, the Consenting Lease Certificate Holders and RCM (the “Amendment Parties) entered into the First Amendment to the Plan Support Agreement (the “First Amendment”). The First Amendment makes certain modifications and conforming changes to the Plan Support Agreement related to the modifications made to the Plan (as defined below) in connection with the filing of the Dynegy Chapter 11 Case. The material terms of the Plan are described below under the heading “Plan of Reorganization.” As of the date of the Original Plan Support Agreement, the earlier noteholder restructuring support agreement, dated November 7, 2011, which was amended and restated on December 26, 2011, was terminated.

The Bankruptcy Court entered an order approving the Settlement Agreement on June 1, 2012 (the “Approval Order”) and the Settlement Agreement became effective on June 5, 2012 (the “Settlement Effective Date”). Pursuant to the Settlement Agreement, Dynegy and DH entered into a Contribution and Assignment Agreement (the “Contribution Agreement”), pursuant to which Dynegy and DH undertook the Coal Holdco Transfer. In full consideration for such contribution and in accordance with the terms of the Settlement Agreement and the Approval Order, (i) Dynegy has received an allowed administrative claim pursuant to sections 503(b) and 507(a) of the Bankruptcy Code in an unliquidated amount against DH in the DH Chapter 11 Cases (the “Administrative Claim”), (ii) the Prepetition Litigation (as defined below), the Adversary Proceeding and the affiliate payable to DH were dismissed with prejudice or released and (iii) the parties to the Settlement Agreement issued and received the releases set forth in the Settlement Agreement and described above under “—Adversary Proceeding and Examiner Report.” Also pursuant to the Settlement Agreement on June 5, 2012, the Undertaking Agreement and the DH note were terminated with no further obligations thereunder.

Plan of Reorganization. On December 1, 2011, Dynegy and DH, as co-plan proponents (the “Plan Proponents”), filed a proposed Chapter 11 plan of reorganization and a related disclosure statement for DH with the Bankruptcy Court, which was subsequently amended and filed with the Bankruptcy Court on each of January 19, 2012, March 6, 2012 and June 8, 2012,

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as the proposed amended plan, the proposed second amended plan and the proposed third amended plan of reorganization for DH. On June 18, 2012, the Plan Proponents filed a proposed modified third amended plan of reorganization (the “Third Amended Plan”) and related disclosure statement (the “Third Amended Disclosure Statement”) for DH with the Bankruptcy Court. Like earlier versions, the Third Amended Plan addressed claims against and interests in DH and Dynegy only and did not address claims against and interests in the other DH Debtor Entities. On July 3, 2012, in the DH Chapter 11 Cases, the Bankruptcy Court entered an order (i) approving (a) the Third Amended Disclosure Statement, (b) solicitation and voting procedures and (ii) scheduling the plan confirmation process (the “DH Disclosure Statement Order”), which authorized DH and Dynegy, in the event Dynegy later commenced a Chapter 11 case in the Bankruptcy Court, among other things, to modify the Third Amended Plan and Third Amended Disclosure Statement as necessary to constitute a plan of reorganization and disclosure statement for both DH and Dynegy, as debtors.

On July 6, 2012, upon the commencement of the Dynegy Chapter 11 Case, Dynegy submitted a first day motion to the Bankruptcy Court seeking to have certain relief entered in the DH Chapter 11 Cases made applicable to the Dynegy Chapter 11 Case, including the DH Disclosure Statement Order. On July 10, 2012, the Bankruptcy Court entered an order in the Dynegy Chapter 11 Case (i) approving (a) the Third Amended Disclosure Statement, (b) solicitation and voting procedures and (ii) scheduling the plan confirmation process in the Dynegy Chapter 11 Case (the “Dynegy Disclosure Statement Order,” and together with the DH Disclosure Statement Order, the “Disclosure Statement Orders”), which, among other things, authorized DH and Dynegy to modify the Third Amended Plan and Third Amended Disclosure Statement as necessary to constitute a plan of reorganization and disclosure statement for both DH and Dynegy, as debtors.

In accordance with the Disclosure Statement Orders, Dynegy and DH (together, the “Plan Debtors”) made certain modifications to the Third Amended Plan (as so modified, the “Plan”) and the Third Amended Disclosure Statement (as so modified, the “Disclosure Statement”), to reflect the commencement of the Dynegy Chapter 11 Case and to have them constitute a plan of reorganization and disclosure statement for both Plan Debtors. On July 12, 2012, the Plan and Disclosure Statement were filed with the Bankruptcy Court [Dynegy Case Docket No. 28; DH Case Docket No. 861] and the Plan Debtors commenced solicitation of votes to accept or reject the proposed Plan in accordance with the Disclosure Statement Orders.

The material terms of the Plan have been agreed upon by Dynegy, DH, a majority of the Consenting Senior Noteholders, the Consenting Sub Debt Holders, the Lease Trustee and the official committee of creditors holding unsecured claims appointed in the DH Chapter 11 Cases (the “Creditors’ Committee”) and include, among other things:

· on or prior to the effective date of the Plan (such date, the “Effective Date”), Dynegy and DH will be merged (the entity surviving such merger being the “Surviving Entity”) and, by virtue of the Merger, all DH equity interests issued and outstanding immediately prior to the effective time of the Merger will be canceled;

· the initial Board of Directors of the Surviving Entity will be selected pursuant to a process agreed upon among a majority of the Consenting Senior Noteholders, the Lease Trustee and the Creditors’ Committee with existing Board members eligible for service on the new Board of the Surviving Entity;

· holders of allowed general unsecured claims will receive their pro rata share of: (a) 99% of the fully-diluted common shares of the Surviving Entity to be outstanding immediately following the Plan Effective Date (subject to dilution), (b) any amounts to which they may be entitled as a result of the sale of the Facilities, and (c) a cash payment of $200 million;

· holders of equity interests in Dynegy, DH or the Surviving Entity shall not receive any distribution or retain any interest or property under the Plan on account of such holder’s equity interest; and

· the Administrative Claim will be satisfied in full under the Plan with: (a) 1.0% of the fully-diluted common shares of the Surviving Entity to be outstanding immediately following the Effective Date (subject to dilution by the Warrants (as defined below) and options, restricted stock or other equity interests issued as equity compensation to officers, employees or directors of the Surviving Entity or its affiliates), (b) warrants to purchase an aggregate of 13.5% of the fully-diluted common shares of the Surviving Entity (the “Warrants”) (subject to dilution) for an exercise price to be determined based on a net equity value of the Surviving Entity of $4 billion, and containing customary anti-dilution adjustments, as provided in the Settlement Agreement.

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The parties to the Plan Support Agreement as amended by the First Amendment (the “Amended Plan Support Agreement”) agreed to use their commercially reasonable efforts to support the Plan and complete the transactions contemplated thereby.

The consummation of the Plan is contingent upon a number of factors including, among other things, that the Plan may not be confirmed by the Bankruptcy Court . Further, the Amended Plan Support Agreement may be terminated if the Settlement Agreement terminates or if certain milestones established with respect to certain actions in the Chapter 11 Cases are not satisfied (such as the failure of the Bankruptcy Court to enter an order confirming the Plan on or prior to September 21, 2012) or if a “Non-Conforming Plan Assertion” (as defined in the Amended Plan Support Agreement) is made and the Bankruptcy Court determines that the Plan is not a “Conforming Plan” (as defined in the Amended Plan Support Agreement) because of claims asserted against Dynegy.

Accounting Impact. Upon effectiveness of the Settlement Agreement on June 5, 2012 , we recognized a loss on the Coal Holdco Transfer of approximately $941 million. The Settlement Agreement resulted in the termination of the Undertaking payable to DH and the Affiliate payable to DH. In addition, we received the Administrative Claim.

The loss on the Coal Holdco Transfer represents the difference in (i) the carrying value of the Undertaking payable to DH of $1.25 billion, (ii) the carrying value of the Affiliate payable to DH of approximately $863 million, and (iii) the fair value of the Administrative Claim received in the transfer of approximately $64 million less the carrying value of our Coal segment of approximately $3.12 billion. The fair value of the Administrative Claim was recorded as an additional investment in DH. Please read Note 5—Fair Value Measurements and Note 7—Variable Interest Entities for further discussion.

As a result of the Coal Holdco Transfer, we currently have no operating assets and our primary asset is our 100 percent equity ownership of DH.

Note 4—Risk Management Activities, Derivatives and Financial Instruments

The nature of our business necessarily involves market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially settled and other types of contracts consistent with our commodity risk management policy. Our commercial team also uses financial instruments in an attempt to capture the benefit of fluctuations in market prices in the geographic regions where our assets operate. Our treasury team manages our financial risks and exposures associated with interest rates.

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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.

Many of our contractual arrangements are derivative instruments and are accounted for at fair value as part of Revenues in our unaudited condensed consolidated statements of operations. 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 delivery occurs. Currently, we have chosen not to designate any of our derivatives as cash flow hedges nor fair value hedges.

Quantitative Disclosures Related to Financial Instruments and Derivatives

Derivatives on the Balance Sheet. As a result of the Coal Holdco Transfer, we do not have any derivatives in our June 30, 2012 unaudited condensed consolidated balance sheet. The following table presents the fair value and balance sheet classification of derivatives in the condensed consolidated balance sheet as of December 31, 2011 segregated by type of contract segregated by assets and liabilities.

Contract Type	Balance Sheet Location	December 31, 2011
		(in millions)
Derivatives not designated as hedging instruments:
Derivative Assets:
Commodity contracts	Assets from risk management activities	$	65
Commodity contracts, affiliates	Assets from risk management activities, affiliates	7
Interest rate contracts	Assets from risk management activities	1
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities	(63		)
Commodity contracts, affiliates	Liabilities from risk management activities, affiliates	(2		)
Interest rate contracts	Liabilities from risk management activities	(3		)
Total derivatives not designated as hedging instruments, net		$	5

Impact of Derivatives on the Consolidated Statements of Operations

For the three-month period ended June 30, 2012, our revenues included approximately $21 million of mark-to-market losses related to this activity compared to $129 million of mark-to-market losses in the same period in the prior year. For the six-month period ended June 30, 2012, our revenues included approximately $9 million of mark-to-market gains related to this activity compared to $127 million of mark-to-market losses in the same period in the prior year.

The impact of derivative financial instruments on our unaudited condensed consolidated statements of operations for the six months ended June 30, 2012 and 2011 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.

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Derivatives Not	Location of Gain (Loss) Recognized in	Amount of Gain (Loss) Recognized in Income on Derivatives for the						Amount of Gain (Loss) Recognized in Income on Derivatives for the
Designated as Hedging	Income on	Three months ended June 30,						Six months ended June 30,
Instruments	Derivatives	2012			2011			2012			2011
		(in millions)
Commodity contracts	Revenues	$	(17	)	$	(89	)	$	37		$	(70	)
Interest rate contracts	Interest Expense	(3		)	—			(5		)	—

Note 5—Fair Value Measurements

Due to the Coal Holdco Transfer on June 5, 2012, we have no financial assets or liabilities as of June 30, 2012. The following tables set forth by level within the fair value hierarchy our financial assets and liabilities, including transactions with affiliates, that were accounted for at fair value on a recurring basis as of December 31, 2011. 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 assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value as of
	December 31, 2011
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—	$	64		$	1		$	65
Electricity derivatives, affiliates	—		2			5			7
Total assets from commodity risk management activities	$	—	$	66		$	6		$	72
Assets from interest rate swaps	—		—			1			1
Total	$	—	$	66		$	7		$	73

Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(62	)	$	(1	)	$	(63	)
Electricity derivatives, affiliates	—		(1		)	(1		)	(2		)
Total liabilities from commodity risk management activities	$	—	$	(63	)	$	(2	)	$	(65	)
Liabilities from interest rate swaps	—		—			(3		)	(3		)
Total	$	—	$	(63	)	$	(5	)	$	(68	)

We primarily apply the market approach for recurring fair value measurements. 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

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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.

The finance organization monitors commodity risk through the CRCG. Our EMT monitors interest rate risk. The EMT has delegated the responsibility for managing interest rate risk to the Chief Financial Officer. The CRCG is independent of our commercial operations and has direct access to the Audit and Compliance Committee. The Finance and Risk Management Committee, chaired by the Chief Financial Officer, meets periodically and is responsible for reviewing our overall day-to-day energy commodity risk exposure as measured against the limits established in our Commodity Risk Policy.

Each quarter, as part of its internal control processes, representatives from the CRCG review the methodology and assumptions behind the pricing of the forward curves. As part of this review, liquidity periods are established based on third party market information, the basis relationship between direct and derived curves is evaluated, and changes are made to the forward power model assumptions.

The CRCG reviews changes in value on a daily basis through the use of various reports. The pricing for power, natural gas and fuel oil curves is automatically entered into our commercial system nightly based on data received from our market data provider. The CRCG reviews the data provided by the market data provider by utilizing third party broker quotes for comparison purposes. In addition, our traders are required to review various reports to ensure accuracy on a daily basis.

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, 2012
	Electricity Derivatives			Interest Rate Swaps			Total
	(in millions)
Balance at March 31, 2012	$	4		$	(3	)	$	1
Total gains (losses) included in earnings, net of affiliates	—			(3		)	(3		)
Settlements, net of affiliates	—			—			—
Coal Holdco Transfer	(4		)	6			2
Balance at June 30, 2012	$	—		$	—		$	—

Unrealized gains (losses) relating to instruments (net of affiliates) held as of June 30, 2012	$	—		$	—		$	—

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	Six Months Ended June 30, 2012
	Electricity Derivatives			Interest Rate Swaps			Total
	(in millions)
Balance at December 31, 2011	$	4		$	(2	)	$	2
Total gains (losses) included in earnings, net of affiliates	2			(4		)	(2		)
Settlements, net of affiliates	(2		)	—			(2		)
Coal Holdco Transfer	(4		)	6			2
Balance at June 30, 2012	$	—		$	—		$	—

Unrealized gains (losses) relating to instruments (net of affiliates) held as of June 30, 2012	$	—		$	—		$	—

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

The carrying values of current financial assets and liabilities such as cash, accounts receivable, and accounts payable not presented in the table below, approximate fair values due to the short-term maturities of these instruments. The $870 million non-current Accounts payable, affiliate balance with DH, as of December 31, 2011, does not have a fair value as there are no defined settlement terms, it is not evidenced by any promissory note and there has never been an intent for payment to occur. The Accounts payable, affiliate balance with DH was fully released on June 5, 2012, the Settlement Agreement Effective Date. Please read Note 15—Related Party Transactions—Transactions with DH—Accounts payable, affiliate for further discussion. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes for the period ended December 31, 2011. Due to the Coal Holdco Transfer and the termination of the Undertaking Agreement as of June 5, 2012 as a result of the Settlement Agreement and settlement of the Accounts payable, affiliate, we have no financial instruments as of June 30, 2012.

	December 31, 2011
	Carrying Amount			Fair Value
	(in millions)
Interest rate derivatives not designated as accounting hedges (1)	$	(2	)	$	(2	)
Commodity-based derivative contracts not designated as accounting hedges, net of affiliates (1)	$	7		$	7
Undertaking payable to DH (2)	$	(1,250	)	$	(728	)
DMG Credit Agreement due 2016 (3)	$	(588	)	$	(603	)

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

(2) The fair value of the Undertaking payable to DH is classified within Level 3 of the fair value hierarchy. Our December 31, 2011 estimate of the fair value of the Undertaking payable to DH represents the $750 million fair value of the Undertaking as of November 7, 2011, less the $22 million payment in December 2011. Pursuant to the Settlement Agreement on June 5, 2012, the Undertaking Agreement was terminated.

(3) Carrying amount includes unamortized discounts of $11 million at December 31, 2011.

Nonfinancial Assets and Liabilities. We recorded the Administrative Claim received in the Coal Holdco Transfer at its estimated fair value of $64 million. We estimated the fair value of the Administrative Claim using the market capitalization of Dynegy as of the date of the Coal Holdco Transfer. We believe the market capitalization of Dynegy represents a reasonable estimate of the fair value of the Administrative Claim because the current holders of Dynegy’s common stock will be the beneficiaries of the Administrative Claim upon DH’s emergence from bankruptcy. The fair value of the Administrative Claim is classified within Level 3 of the fair value hierarchy. Please read Note 3—Chapter 11 Cases for further discussion.

There were no other nonfinancial assets and liabilities measured at fair value on a nonrecurring basis during the three and six months ended June 30, 2012 or 2011.

Note 6—Accumulated Other Comprehensive Loss

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

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	June 30, 2012			December 31, 2011
	(in millions)
Cash flow hedging activities, net	$	—		$	(1	)
Unrecognized prior service cost and actuarial loss, net	(48		)	(52		)

Accumulated other comprehensive loss, net of tax	$	(48	)	$	(53	)

Note 7—Variable Interest Entities

Dynegy Holdings, LLC. Effective November 7, 2011, DH, our wholly-owned subsidiary, was deconsolidated. As of June 30, 2012 and December 31, 2011, we did not have any carrying amounts related to our investment in DH included in our consolidated balance sheets. Our maximum exposure to loss related to our investment in DH is limited to our guarantee related to two charter agreements entered into by a DH subsidiary. Please read Note 8—Commitments and Contingencies—Guarantees and Indemnifications—VLGC Guarantee for further discussion. Also, please read Note 15—Related Party Transactions—Transactions with DH for a discussion of transactions with DH and its subsidiaries.

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

	Three Months Ended June 30, 2012						Six Months Ended June 30, 2012
	Total			Equity Share			Total			Equity Share
	(in millions)
Revenues	$	319		$	—		$	648		$	—
Operating loss	(8		)	—			(10		)	—
Net loss	(729		)	(1		)	(1,153		)	(1		)

During the three and six months ended June 30, 2012, we did not recognize $739 million and $1,177 million, respectively, of our share of losses from our investment in DH as to do so would have reduced our investment below zero and we do not have an obligation to fund such losses.

DH’s net loss for the three months ended June 30, 2012 includes a loss of approximately $848 million related to the impairment of the Undertaking receivable from Dynegy Inc. partially offset by a gain of approximately $144 million related to adjustments of the expected allowed claim related to DH’s subordinated notes.

DH’s net loss for six months ended June 30, 2012 includes a loss of $848 million related to the impairment of the Undertaking receivable from Dynegy Inc. and charges of approximately $272 million related to adjustments of the expected allowed claims. Please read Note 3—Chapter 11 Cases for further discussion.

Note 8—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, and nature of damages sought and the probability of success. Management regularly reviews all new information with respect to each such contingency and adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties

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including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals and that such differences could be material.

In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business or related to discontinued business operations. Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows.

Creditor Litigation. On September 21, 2011, an ad-hoc group of bondholders of DH (the “Avenue Plaintiffs”) filed a complaint in the Supreme Court of the State of New York, captioned Avenue Investments, L.P. et al v. Dynegy Inc., Dynegy Holdings, LLC, Dynegy Gas Investments, LLC, Clint C. Freeland, Kevin T. Howell and Robert C. Flexon (Index No. 652599/11) (the “Avenue Investments Litigation”). The Avenue Plaintiffs challenged the transfer of 100% of the outstanding membership interests of Coal Holdco by DGIN to Dynegy (the “Coal Holdco Transfer”). On September 27, 2011, the Lease Trustee filed a complaint in the Supreme Court of the State of New York, captioned The Successor Lease Indenture Trustee et al v. Dynegy Inc., Dynegy Holdings, LLC, Dynegy Gas Investments, LLC, E. Hunter Harrison, Thomas W. Elward, Michael J. Embler, Robert C. Flexon, Vincent J. Intrieri, Samuel Merksamer, Felix Pardo, Clint C. Freeland, Kevin T. Howell, John Doe 1, John Doe 2, John Doe 3, Etc. (Index No. 652642/2011) (the “Lease Trustee Litigation”). On November 4, 2011, certain of the PSEG Entities as owner-lessors of the Facilities filed a lawsuit in the Supreme Court of the State of New York, captioned Resources Capital Management Corp., Roseton OL, LLC and Danskammer OL, LLC, v. Dynegy Inc., Dynegy Holdings, Inc., Dynegy Holdings, LLC, Dynegy Gas Investments, LLC, Thomas W. Elward, Michael J. Embler, Robert C. Flexon, E. Hunter Harrison, Vincent J. Intrieri, Samuel J. Merksamer, Felix Pardo, Clint C. Freeland, Kevin T. Howell, Icahn Capital LP, and Seneca Capital Advisors, LLC (Index No. 635067/11) (the “PSEG Litigation”). The Avenue Investments Litigation, the Lease Trustee Litigation and the PSEG Litigation are collectively referred to as the “Prepetition Litigation”.

The Prepetition Litigation challenged the Coal Holdco Transfer. Plaintiffs in all three actions allege, among other claims, breach of contract, breach of fiduciary duties, and violations of prohibitions on fraudulent transfers in connection with the Coal Holdco Transfer and also seek to have the Coal Holdco Transfer set aside, and request unspecified damages as well as attorneys’ fees. We filed motions to dismiss the Avenue Investments Litigation and Lease Trustee Litigation on October 31, 2011. The complaint in the PSEG Litigation was never served on the Defendants. On November 7, 2011, Dynegy, DH and the Consenting Noteholders (as defined and discussed in Note 3—Chapter 11 Cases) agreed to enter into a stipulation staying the Avenue Investments Litigation.

On November 21, 2011, the Prepetition Litigation defendants filed in each case a Notice of Filing of Bankruptcy Petition and of the Automatic Stay, which provided, among other things, that (i) “pursuant to section 362(a) of the Bankruptcy Code, this lawsuit is stayed in its entirety, as to all claims and all defendants (the “Automatic Stay”),” and (ii) “actions taken in violation of the Automatic Stay are void and may subject the person or entity taking such actions to the imposition of sanctions by the Bankruptcy Court.” In addition, on November 21, 2011, the defendants filed two stipulations in the Avenue Investments Litigation and the Lease Trustee Litigation, pursuant to which the parties agreed, among other things, (i) to stay or take no action in the lawsuits, including the pending motions to dismiss, until further application, and (ii) to reserve all rights and/or arguments with respect to the scope or effect of the Automatic Stay.

Pursuant to the Settlement Agreement, on the Settlement Effective Date, the plaintiffs or parties (as applicable) to the Prepetition Litigation filed necessary papers to dismiss and discontinue with prejudice each of the Avenue Investments Litigation, the Lease Trustee Litigation and the PSEG Litigation and any potential claims relating to or arising from disputes with respect to such actions were released by the parties thereto. For additional information see Note 3—Chapter 11 Cases— Settlement Agreement and Plan Support Agreement.

On April 2, 2012, a putative class action lawsuit on behalf of bondholders was filed in the Southern District of New York captioned Shirlee Schwartz v. Dynegy Inc., et al, however, plaintiffs voluntarily dismissed the case shortly after filing.

Derivative Litigation. On or about May 4, 2012, a stockholder derivative action was commenced in Dallas county Court of the State of Texas captioned Bryce Nicolle v. Robert C. Flexon, et al. (Cause No. CC-12-2703-A) (the “Nicolle Litigation”). In connection with the 2011 Prepetition Restructurings and specifically the Coal Holdco Transfer, the petition alleges that

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certain current and former directors and officers of Dynegy Inc. breached their fiduciary duties and seeks unspecified damages, restitution and attorneys’ fees.

On or about May 16, 2012, a stockholder derivative action was filed in the Court of Chancery of the State of Delaware captioned Cleo A. Zahariades v. Thomas W. Elward, et al., (Case No. 7539-VCP) (the “Zahariades Litigation”). In connection with the 2011 Prepetition Restructurings and specifically the Coal Holdco Transfer, the complaint alleges that the directors and officers of Dynegy Inc. breached their fiduciary duties and seeks unspecified damages, restitution and attorneys’ fees.

Following the filing by Dynegy Inc. of a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code, on or about July 11, 2012 defendants filed (i) a Notice of Automatic Stay in the Nicolle Litigation, and (ii) a Suggestion of Bankruptcy and Notice of Automatic Stay in the Zahariades Litigation, noticing that any further proceedings in each action was automatically stayed pursuant to 11 U.S.C. § 362.

Stockholder Litigation Relating to the Blackstone and Icahn Merger Agreements. In connection with the 2010 and 2011 terminations of the merger agreement with an affiliate of The Blackstone Group L.P. (“Blackstone”) and the merger agreement with an affiliate of Icahn Enterprises L.P. (“Icahn”), respectively, numerous stockholder lawsuits and one stockholder derivative lawsuit previously filed in the District Courts of Harris County, Texas, the Southern District of Texas, and the Court of Chancery of the State of Delaware were dismissed. In July 2011, the Harris County District Court granted the motion of the plaintiff’s lead class counsel for an award of attorney’s fees and expenses in the amount of approximately $2 million. We have appealed the decision, but as a result of the filing of the Dynegy Chapter 11 Case, this appeal has been stayed.

Stockholder Litigation Relating to the Internal Reorganization. In connection with the 2011 Prepetition Restructurings and specifically the Coal Holdco Transfer, a putative class action stockholder lawsuit captioned Charles Silsby v. Carl C. Icahn, et al., Case No. 12CIV2307, was filed in the United States District Court of the Southern District of New York. The lawsuit challenges certain disclosures made in connection with the Coal Holdco Transfer. We believe the plaintiffs’ complaints lack merit and we will oppose their claims vigorously. As a result of the filing of the voluntary petition for bankruptcy by Dynegy Inc., this lawsuit has been stayed as against Dynegy Inc.

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. All of the remaining 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 July 2011, the court granted defendants’ motions for summary judgment, thereby dismissing all of plaintiffs’ claims. Plaintiffs have appealed the decision to the Ninth Circuit Court of Appeals.

Illinova Generating Company Arbitration. In May 2007, our 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. Coincident 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. The case is presently before the Dallas Court of Appeals, which heard oral arguments in April 2012. As a result of the uncertainty surrounding the outcome of PPE’s appeal, our receivable from PPE is fully reserved at June 30, 2012.

Other Commitments and Contingencies

In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges

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associated with firm transmission, transportation, storage and leases for office space, equipment, plant sites, power generation assets and LPG vessel charters. The following describes the more significant commitments outstanding at June 30, 2012.

Blackstone Merger Agreement. On August 13, 2010, we entered into the merger agreement with an affiliate of Blackstone, pursuant to which we would be acquired and our stockholders would receive $4.50 per share in cash. On November 16, 2010, the agreement was amended to increase the merger consideration to $5.00 per share in cash. The merger agreement was not approved by our stockholders at a special stockholders’ meeting on November 23, 2010 and was subsequently terminated by the parties in accordance with the terms of the agreement. The merger agreement required us to pay Blackstone a termination fee in the amount of approximately $16 million in the event that within 18 months of November 23, 2010, we consummate an alternative transaction having an aggregate value of more than $4.50 per share. This potential obligation expired on April 23, 2012.

Icahn Merger Agreement. On December 15, 2010, our Board of Directors unanimously approved us entering into a merger agreement with an affiliate of Icahn. In connection with the merger agreement, Icahn launched a tender offer on December 22, 2010 for all of our issued and outstanding shares of common stock at $5.50 per share. At the expiration of the tender offer on February 18, 2011, an insufficient number of shares had been tendered in response to the tender offer, and as a result the merger agreement automatically terminated. In connection with the termination, we paid $5 million to Icahn with respect to expenses incurred by Icahn related to the merger agreement in February 2011, and may be required to pay additional fees of $11 million in the event that within 18 months of February 18, 2011, we consummate an alternative transaction having an aggregate value of more than $5.50 per share. This potential obligation will expire on August 18, 2012.

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 agreements 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 less than $1 million as of June 30, 2012.

LS Power Indemnities. In connection with the sale of certain assets and investments (comprising former subsidiaries of DH) to LS Power (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.

West Coast Power Indemnities. In connection with the sale of our 50 percent interest in West Coast Power (held by a former indirect subsidiary of DH) 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

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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. In April 2012, NRG and West Coast Power settled all claims brought by the California Parties. The settlement does not exceed NRG’s indemnity obligation to Dynegy, therefore, we have no exposure in connection with the settlement.

Targa Indemnities. During 2005, as part of our sale of DH’s 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. We have 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 our liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses. We have made certain payments in respect of these indemnities following regulatory action by the ICC, and have established reserves for further potential indemnity claims. Further events, which fall within the scope of the indemnity, may still occur. However, we are 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. We intend to contest any proposed regulatory actions.

VLGC Guarantee. A subsidiary of DH is party to two charter party agreements relating to VLGCs previously utilized in our former global liquids business. The aggregate minimum base commitments of the charter party agreements are approximately $9 million for the remainder of 2012, and approximately $23 million in aggregate for the period from 2013 through lease expiration. The charter party rates payable under the two charter party agreements float in accordance with market based rates for similar shipping services. The $9 million and $23 million amounts set forth above are based on the minimum obligations set forth in the two charter party agreements. The primary term of one charter is through September 2013 while the primary term of the second charter is through September 2014. On January 1, 2003, both VLGCs were sub-chartered to a wholly-owned subsidiary of Transammonia Inc. The terms of the sub-charters are identical to the terms of the original charter agreements. To date, the subsidiary of Transammonia has complied with the terms of the sub-charter agreements. We have guaranteed the obligation of the DH subsidiary related to the charter agreements.

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, 2012, 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 9—Asset Retirement Obligations

We record the present value of our legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities when the liability is incurred. Significant judgment is involved in estimating future cash flows associated with such obligations, as well as the ultimate timing of the cash flows. A summary of changes in our AROs is as follows:

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	Six Months Ended June 30,
	2012			2011
	(in millions)
Beginning of year	$	42		$	119
Accretion expense	1			4
Revision of previous estimate (1)	8			(1		)
Coal Holdco Transfer	(51		)	—
Other	—			(1		)
End of period	$	—		$	121

(1) As a result of additional remediation obligations at our Vermilion facility, in the first quarter 2012 we increased our asset retirement obligation by approximately $8 million. This increase is reflected in depreciation expense on our consolidated statement of operations as the Vermilion facility has been retired and is fully depreciated.

Note 10—Restricted Cash

The following table depicts our restricted cash as of June 30, 2012 and December 31, 2011. As a result of the Coal Holdco Transfer, the restricted cash held by DMG was transferred to DH effective June 5, 2012.

	June 30, 2012		December 31, 2011
	(in millions)
DMG LC facility (1)	$	—	$	103
DMG Collateral Posting Account (2)	—		69
Other (3)	3		—
Total restricted cash	$	3	$	172

(1) Includes cash posted to support the letter of credit reimbursement and collateral agreements under the DMG LC facility. Please read Note 19—Debt—Letter of Credit Facilities in our Form 10-K for further discussion. Amounts are classified as non-current restricted cash to match the term of the related facility.

(2) Amounts are restricted and may be used for future collateral posting requirements or released per the terms of the DMG Credit Agreement.

(3) Includes cash posted to support the letter of credit issued by Dynegy Inc. and collateral for the corporate card program.

Note 11—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully described in Note 25—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:

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	Three Months Ended June 30,
	Pension Benefits						Other Benefits
	2012			2011			2012		2011
	(in millions)
Service cost benefits earned during period	$	2		$	3		$	1	$	—
Interest cost on projected benefit obligation	4			3			—		1
Expected return on plan assets	(4		)	(4		)	—		—
Recognized net actuarial loss	1			2			—		—
Net periodic benefit cost	$	3		$	4		$	1	$	1

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
	2012			2011			2012		2011
	(in millions)
Service cost benefits earned during period	$	5		$	6		$	1	$	1
Interest cost on projected benefit obligation	7			7			1		2
Expected return on plan assets	(8		)	(8		)	—		—
Recognized net actuarial loss	2			3			—		—
Net periodic benefit cost	$	6		$	8		$	2	$	3

Contributions. During the six months ended June 30, 2012 and 2011 we contributed approximately $7 million and $6 million, respectively, to our pension plans or other postretirement benefit plans. We expect to make contributions of approximately $13 million to our pension plans during the remainder of 2012.

Note 12—Income Taxes

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions, except rates)
Income tax benefit	$	—		$	76		$	—		$	136

Effective tax rate	—		%	40		%	—		%	41		%

During the second quarter of 2012, we had an ownership change for income tax purposes because of a greater than 50 percent shift in ownership of Dynegy common stock. This will significantly limit our ability to utilize our federal NOLs and AMT credits at the time of the ownership change. We are currently in the process of determining the amount of the limitation, however, the limitation will not impact our ability to utilize the federal

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NOLs and AMT credits to offset cancellation of indebtedness income that will be recognized upon our emergence from bankruptcy.

For the three and six months ended June 30, 2012 the difference between the effective rate of zero and the statutory rate of 35 percent resulted primarily from a valuation allowance to eliminate our net deferred tax assets partially offset by the impact of state taxes. As of June 30, 2012, we do not believe we will produce sufficient future taxable income, nor are there tax strategies available, to realize our net deferred tax assets not otherwise realized by reversing temporary differences.

For the three months ended June 30, 2011, Dynegy’s overall effective tax rate 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, the difference between the effective rate of 41 percent for Dynegy and the statutory rate of 35 percent resulted primarily from the impact of state taxes including a benefit of $9 million related to an increase in state NOLs due to the acceptance of amended returns, which we filed as a result of a change in a tax position, partially offset by an expense of $3 million related to an increase in the Illinois statutory rate.

Note 13—Inventory

A summary of our inventories as of December 31, 2011 is included below. As a result of the Coal Holdco Transfer, we did not have any inventory as of June 30, 2012.

	December 31, 2011
	(in millions)
Material and supplies	$	20
Coal	36
Fuel oil	1
Total	$	57

Note 14—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. Please read Note 24—Capital Stock in our Form 10-K for further discussion.

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

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	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions, except per share amounts)
Loss from continuing operations for basic and diluted loss per share	$	(1,064	)	$	(116	)	$	(1,122	)	$	(193	)

Basic weighted-average shares	123			122			123			122
Effect of dilutive securities:
Stock options and restricted stock	—			—			—			—
Diluted weighted-average shares	123			122			123			122

Loss per share from continuing operations:
Basic	$	(8.65	)	$	(0.95	)	$	(9.12	)	$	(1.58	)

Diluted (1)	$	(8.65	)	$	(0.95	)	$	(9.12	)	$	(1.58	)

(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 all periods presented.

Note 15—Related Party Transactions

Transactions with DH

The following tables summarize the Accounts receivable, affiliates, and Accounts payable, affiliates, on our unaudited condensed consolidated balance sheets as of June 30, 2012 and December 31, 2011 and cash received (paid) during the three and six months ended June 30, 2012 related to various agreements with DH and its consolidated subsidiaries, as discussed below. There were no cash payments related to the various service agreements for the three or six months ended June 30, 2011.

	June 30, 2012				Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
	Accounts receivable, affiliates		Accounts payable, affiliates		Cash received (paid)			Cash received (paid)
	(in millions)
Service Agreements	$	1	$	—	$	(4	)	$	(15	)
EMA Agreements	—		—		—			(1		)
Total	$	1	$	—	$	(4	)	$	(16	)

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	December 31, 2011
	Accounts receivable, affiliates		Accounts payable, affiliates
	(in millions)
Service Agreements	$	6	$	4
EMA Agreements	41		22
Total	$	47	$	26

Service Agreements. We and certain of our subsidiaries (the “Providers”) provide certain services (the “Services”) to Dynegy Gas Investments Holdings, LLC (“DGIH”), Dynegy Coal Investments Holdings, LLC, (“DCIH”), Dynegy Northeast Generation, Inc., their respective subsidiaries and certain of our other subsidiaries (the “Recipients”). Service Agreements between us and each of DGIH, DCIH, Dynegy Northeast Generation, Inc. and certain other subsidiaries of Dynegy, govern the terms under which such Services are provided.

The Providers act as agents for the Recipients for the limited purpose of providing the Services set forth in the Service Agreements. 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. We recorded income from the Recipients which was offset by expenses incurred by a subsidiary of DH that provided the services. Therefore, there is no impact of the Service Agreements on our consolidated statement of operations for the three and six months ended June 30, 2012.

Energy Management Agreements. Each of our subsidiaries that owns or operates one or more power plants (each an “Internal Customer”) has entered into an Energy Management Agency Services Agreement (an “EMA”) with Dynegy Power Marketing, LLC (“DPM”), an indirect wholly-owned subsidiary of DH. Pursuant to each EMA, DPM provides power management services to the Internal 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 DPM’s subsidiary, Dynegy Marketing and Trade, LLC, DPM provides fuel management services, consisting of procuring the requisite quantities of fuel, assisting with storage and transportation, scheduling delivery of fuel, assisting Internal 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 DPM’s indirect subsidiary, Dynegy Coal Trading & Transportation, LLC, DPM also provides fuel management services to one or more Internal Customers that require services related to coal. DPM also assists the Internal Customer with risk management by entering into one or more risk management transactions, the purpose of which is to set the price or value of a commodity or to mitigate or offset changes in the price or value of a commodity. DPM may from time to time provide other services as the parties may agree. Our consolidated statement of operations includes Revenues of $69 million and $198 million, respectively, from sales to affiliates and Costs of sales includes $24 million and $79 million, respectively in purchases from affiliates for the three and six months ended June 30, 2012, respectively.

Tax Sharing Agreement. Under U.S. federal income tax law, we are responsible for the tax liabilities of our subsidiaries because we file consolidated income tax returns. These returns include the income and business activities of the ring-fenced entities (as further discussed below) and our other affiliates. To properly allocate taxes among us and each of our subsidiaries, we and certain of our subsidiaries have entered into a Tax Sharing Agreement under which we agree to prepare consolidated returns on behalf of ourselves and our subsidiaries and make all required payments to relevant revenue collection authorities as required by law. Each of DPC, DMG, Dynegy GasCo Holdings, LLC, Dynegy Gas Holdco, LLC, DGIH, Dynegy Coal Holdco, LLC, and DCIH agrees to make payments to us of amounts representing the tax that each such subsidiary would have

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paid if each began business on the execution date of the Tax Sharing Agreement and filed a separate corporate income tax return (excluding from income any subsidiary distributions) on a stand-alone basis beginning on the that same date.

Cash Management Agreements. The Prepetition Restructurings created new companies, some of which are “bankruptcy remote.” These bankruptcy remote entities have an independent manager whose consent is required for certain corporate actions and such entities are required to present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, they conduct business in their own names (other than any business relating to the trading activities of us and our subsidiaries), they observe a higher level of formalities, and they have restrictions on pledging their assets for the benefit of certain other persons. In addition, as part of the Prepetition Restructurings, some companies within our portfolio were reorganized into “ring-fenced” groups. The upper-level companies in such ring-fenced groups are bankruptcy-remote entities governed by limited liability company operating agreements which, in addition to the bankruptcy remoteness provisions described above, contain certain additional restrictions prohibiting any material transactions with affiliates other than the direct and indirect subsidiaries within the ring-fenced group without independent manager approval.

Pursuant to our Cash Management Agreements, our ring-fenced entities maintain cash accounts separate from those of our non-ring-fenced entities. Cash collected by a ring-fenced entity is not swept into accounts held in the name of any non-ring-fenced entity and cash collected by a non-ring-fenced entity is not swept into accounts held in the name of any ring-fenced entity. The cash in deposit accounts owned by a ring-fenced entity is not used to pay the debts and/or operating expenses of any non-ring-fenced entity, and the cash in deposit accounts owned by a non-ring-fenced entity is not used to pay the debts and/or operating expenses of any ring-fenced entity. There were no material payments during the three and six months ended June 30, 2012 related to the Cash Management Agreements.

Undertaking Agreement. We had an undertaking payable of $1.25 billion to DH related to our acquired equity stake in Coal Holdco. Please read Note 20—Related Party Transactions—Transactions with DH—DMG Transfer and Undertaking Agreement in our Form 10-K for further discussion. Pursuant to the Settlement Agreement on June 5, 2012, we assigned and contributed all of our outstanding equity interests in Coal Holdco to DH free and clear of all liens and the Undertaking Agreement and the DH note, described in Note 20—Related Party Transactions—Transactions with DH—DMG Transfer and Undertaking Agreement in our Form 10-K, were terminated with no further obligations. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

We recorded interest expense of $16 million and $40 million related to the undertaking, which is included in Interest expense on our consolidated statement of operations during the three and six months ended June 30, 2012, respectively. In addition, we made payments of $48 million to DH during the three and six months ended June 30, 2012 related to the Undertaking Agreement. As of December 31, 2011, we had approximately $8 million in accrued interest related to the undertaking, which is reflected in Accrued interest, affiliates on our consolidated balance sheet.

Accounts payable, affiliates. We have historically recorded intercompany transactions in the ordinary course of business, including the reallocation of deferred taxes between legal entities in accordance with applicable IRS regulations. As a result of such transactions, we have recorded over time a payable to DH and its affiliates in the aggregate amount of $846 million at December 31, 2011. This amount is classified within long-term liabilities as Accounts payable, affiliates on our December 31, 2011 condensed consolidated balance sheet because there are no defined payment terms, it is not evidenced by any promissory note and there has never been an intent for payment to occur. The intercompany receivable was fully released on June 5, 2012 upon the effective date of the Settlement Agreement. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

Administrative Claim. As discussed in Note 3—Chapter 11 Cases, we received the Administrative Claim in connection with the Coal Holdco Transfer. The Administrative Claim, which was valued at approximately $64 million was recorded as an additional equity investment in DH. Subsequent to the Coal Holdco Transfer, we recorded equity losses of $1 million that reduced our investment to $63. Please read Note 7—Variable Interest Entities for further discussion.

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

DH Employee benefits. Our employees, and employees of DH, participate in the stock compensation, pension and other post-retirement benefit plans sponsored by us. Please read Note 11—Employee Compensation, Savings and Pension Plans for further discussion.

Note 16—Segment Information

As reflected in this report, we have changed our reportable segments. Prior to the third quarter 2011, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Beginning with the third quarter 2011, our reportable segments are: (i) the Coal segment (“Coal”); (ii) the Gas segment (“Gas”), and (iii) the Dynegy Northeast segment (“DNE”). Accordingly, we have recast the corresponding items of segment information for all prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as interest and depreciation and amortization. General and administrative expenses are allocated to each reportable segment. Additionally, effective November 7, 2011, DH, including our Gas and DNE segments, was deconsolidated and we began accounting for our investment in DH using the equity method of accounting. Effective June 5, 2012, in connection with the Settlement Agreement we assigned our interest in Coal Holdco, the Coal segment, to DH.

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three and six months ended June 30, 2012 and 2011 is presented below:

Segment Data as of and for the Three Months Ended June 30, 2012

(in millions)

	Coal			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	53		$	—		$	53
Total revenues	$	53		$	—		$	53
Depreciation and amortization	$	(28	)	$	—		$	(28	)
Loss on Coal Holdco Transfer	(2,652		)	1,711			(941		)
General and administrative expense	(5		)	(39		)	(44		)
Operating income (loss)	$	(2,708	)	$	1,672		$	(1,036	)
Loss from unconsolidated investment	—			(1		)	(1		)
Interest expense							(27		)
Loss before income taxes							(1,064		)
Income tax benefit							—
Net loss							$	(1,064	)

Identifiable assets (domestic)	$	—		$	119		$	119
Capital expenditures	$	(19	)	$	—		$	(19	)

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

Segment Data as of and for the Six Months Ended June 30, 2012

(in millions)

	Coal			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	230		$	—		$	230
Total revenues	$	230		$	—		$	230
Depreciation and amortization	$	(78	)	$	—		$	(78	)
Loss on Coal Holdco Transfer	(2,652		)	1,711			(941		)
General and administrative expense	(14		)	(53		)	(67		)
Operating income (loss)	$	(2,715	)	$	1,658		$	(1,057	)
Loss from unconsolidated investment	—			(1		)	(1		)
Interest expense							(64		)
Loss before income taxes							(1,122		)
Income tax benefit							—
Net loss							$	(1,122	)

Identifiable assets (domestic)	$	—		$	119		$	119
Capital expenditures	$	(42	)	$	—		$	(42	)

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

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

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	128		$	178		$	20		$	—		$	326
Total revenues	$	128		$	178		$	20		$	—		$	326
Depreciation and amortization	$	(40	)	$	(33	)	$	—		$	(2	)	$	(75	)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	(10		)	(12		)	(3		)	—			(25		)
Operating income (loss)	$	(47	)	$	(32	)	$	(24	)	$	(3	)	$	(106	)
Other items, net	—			1			—			2			3
Interest expense													(89		)
Loss before income taxes													(192		)
Income tax benefit													76
Net loss													$	(116	)

Identifiable assets (domestic)	$	3,617		$	4,265		$	520		$	1,461		$	9,863
Capital expenditures	$	(44	)	$	(17	)	$	(1	)	$	—		$	(62	)

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DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

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

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	328		$	445		$	58		$	—		$	831
Total revenues	$	328		$	445		$	58		$	—		$	831
Depreciation and amortization	$	(130	)	$	(67	)	$	—		$	(4	)	$	(201	)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	(21		)	(25		)	(7		)	(12		)	(65		)
Operating income (loss)	$	(79	)	$	(19	)	$	(39	)	$	(18	)	$	(155	)
Other items, net	—			1			—			3			4
Interest expense													(178		)
Loss before income taxes													(329		)
Income tax benefit													136
Net loss													$	(193	)

Identifiable assets (domestic)	$	3,617		$	4,265		$	520		$	1,461		$	9,863
Capital expenditures	$	(87	)	$	(40	)	$	(1	)	$	—		$	(128	)

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DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Item 2—MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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 2011 Form 10-K.

We are a holding company 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 unaudited condensed consolidated financial statements. Prior to the third quarter 2011, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Beginning with the third quarter 2011, our reportable segments are: (i) the Coal segment (“Coal”); (ii) the Gas segment (“Gas”) and (iii) the Dynegy Northeast segment (“DNE”). Accordingly, we have recast the corresponding items of segment information for all prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as interest and depreciation and amortization. General and administrative expenses are allocated to each reportable segment.

The following discussion includes information related to our unconsolidated investment in DH, which includes the Gas and DNE segments, and the Coal segment after June 5, 2012. We have included this information because management continues to review the results of the company on an enterprise-wide basis and we believe it is meaningful to investors.

Dynegy and DH Chapter 11 Cases. On November 7, 2011, the DH Debtor Entities filed the DH Chapter 11 Cases. On July 6, 2012, Dynegy filed the Dynegy Chapter 11 Case. The Dynegy Chapter 11 Case is a necessary step to facilitate the restructuring contemplated by the Plan and the Agreements, including the planned Merger of Dynegy and DH. None of Dynegy’s other direct or indirect subsidiaries, other than the five DH Debtor Entities, sought relief under Chapter 11 of the Bankruptcy Code, and none of those entities are debtors thereunder. The normal day-to-day operations of the coal-fired power generation facilities held by DMG and the natural gas-fired power generation facilities held by DPC have continued without interruption. Also on July 6, 2012, the NYSE announced suspension of trading of our common stock. This announcement was followed by written notice to us on July 9, 2012, that the NYSE had determined to suspend trading in our common stock immediately on July 6, 2012. The NYSE noted that it reached this decision in view of the Dynegy Chapter 11 Case. We do not intend to take any further action to appeal the NYSE’s decision and therefore it is expected that our common stock will be delisted after the completion and approval of the NYSE’s application to the SEC. Dynegy’s common stock is currently trading under the symbol “DYNIQ” in the over-the-counter market. Please see Item 1A-Risk Factors for risks related to trading stock in the over-the-counter market.

As of May 1, 2012, the restructuring support agreement was terminated in its entirety and superseded by the Settlement Agreement and Plan Support Agreement, which was approved by the Bankruptcy Court on June 1, 2012 and became effective on June 5, 2012. On June 5, 2012, pursuant to the Approval Order and the Settlement Agreement, Dynegy and DH entered into a Contribution Agreement, pursuant to which Dynegy effectuated the Coal Holdco Transfer. In full consideration for such contribution and in accordance with the terms of the Settlement Agreement and the Approval Order, (i) Dynegy received the “Administrative Claim, (ii) the Prepetition Litigation, the Adversary Proceeding and the intercompany receivable were dismissed with prejudice or released and (iii) the parties to the Settlement Agreement issued and received the releases set forth in the Settlement Agreement. Also pursuant to the Settlement Agreement on June 5, 2012, the Undertaking Agreement and the DH note were terminated with no further obligations. Please read Note 3—Chapter 11 Cases for further discussion.

On June 18, 2012, the Plan Proponents filed the Third Amended Plan and the Third Amended Disclosure Statement for DH with the Bankruptcy Court and on July 3, 2012, the Bankruptcy Court entered the DH Disclosure Statement Order. Bankruptcy Court approval of the Third Amended Disclosure Statement, among other things, authorized DH and Dynegy, in the event Dynegy later commenced a chapter 11 case in the Bankruptcy Court, to modify the Third Amended Plan and Third Amended Disclosure Statement as necessary to constitute a plan of reorganization and disclosure statement for both DH and Dynegy, as debtors. In connection with the Dynegy Chapter 11 Case, Dynegy submitted a first day motion to the Bankruptcy Court seeking to have certain relief entered in the DH Chapter 11 Cases made applicable to the Dynegy Chapter 11 Case, including the DH Disclosure Statement Order. On July 10, 2012, the Bankruptcy Court entered the Dynegy Disclosure Statement Order, which allowed DH and Dynegy to begin soliciting formal creditor votes on the Plan.

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On July 12, 2012, the Plan Proponents filed the Plan for Dynegy and DH and the related Disclosure Statement with the Bankruptcy Court. The deadline for voting on and for objecting to the Plan is August 24, 2012. The Plan is subject to confirmation by the Bankruptcy Court and the confirmation hearing is scheduled for September 5, 2012.

LIQUIDITY AND CAPITAL RESOURCES

Overview

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

Our primary sources of internal liquidity are cash flows from operations and cash on hand. Cash on hand includes cash proceeds from the DPC Credit Agreement and the DMG Credit Agreement, which is limited in use and distribution as further described in footnote 1 to the liquidity table below.

Our primary sources of external liquidity are proceeds from capital market transactions to the extent we engage in such transactions.

Our ability to continue as a going concern is contingent upon the Bankruptcy Court’s approval of the Plan and our ability to successfully implement the Plan, among other factors. As a result of the Chapter 11 Cases, the realization of assets and the satisfaction of liabilities are subject to uncertainty. Furthermore, on June 5, 2012, the effective date of the Settlement Agreement, we effectuated the Coal Holdco Transfer. Coal Holdco is the indirect owner of our assets in the Coal segment, therefore, subsequent to the transfer, we have no operating assets outside of our equity investment in DH. For additional information please read Note 3—Chapter 11 Cases.

Current Liquidity. The following tables summarize our liquidity position, including the consolidated liquidity of DH, our wholly-owned subsidiary accounted for as an equity method investment at July 30, 2012 and June 30, 2012:

	July 30, 2012
	Dynegy Inc. (as reported)			DMG			DPC			Other DH (1)			Total
	(in millions)
LC capacity, inclusive of required reserves (2)	$	1		$	42		$	252		$	27		$	322
Less: Required reserves (2)	—			(1		)	(8		)	(1		)	(10		)
Less: Outstanding letters of credit	(1		)	(29		)	(240		)	(26		)	(296		)
LC availability	—			12			4			—			16
Cash and cash equivalents	27			61			80			544			712
Collateral posting account (3)	—			62			227			—			289
Total available liquidity (4)	$	27		$	135		$	311		$	544		$	1,017

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	June 30, 2012
	Dynegy Inc. (as reported)			DMG			DPC			Other DH (1)			Total
	(in millions)
LC capacity, inclusive of required reserves (2)	$	1		$	41		$	298		$	27		$	367
Less: Required reserves (2)	—			(1		)	(9		)	(1		)	(11		)
Less: Outstanding letters of credit	(1		)	(29		)	(239		)	(26		)	(295		)
LC availability	—			11			50			—			61
Cash and cash equivalents	51			67			47			542			707
Collateral posting account (3)	—			65			167			—			232
Total available liquidity (4)	$	51		$	143		$	264		$	542		$	1,000

(1) Other DH cash consists of $173 million and $173 million at Coal Holdco, $306 million and $305 million at Dynegy Gas HoldCo, LLC; $12 million and $11 million at Dynegy Administrative Services Company; $46 million and $52 million at DH; and $7 million and $1 million at Dynegy Northeast Generation, Inc. as of July 30, 2012 and June 30, 2012, respectively.

(2) The LC facilities were collateralized with cash proceeds received from the DPC and DMG credit agreements. The amount of the LC availability plus any unused required reserves of 3 percent on the unused capacity, may be withdrawn from the LC facilities with three days written notice for unrestricted use in the operations of the applicable entity. LC capacity as of July 30, 2012 and June 30, 2012 reflects a reduction in capacity for DMG and DPC following the requested release of unused cash collateral from restricted cash. Actual commitment amounts under each credit agreement have not been reduced, and DMG and DPC can increase the LC capacity up to the original commitment amount in the future by posting additional cash collateral.

(3) The collateral posting account included in the above liquidity tables is restricted per the DMG Credit Agreement and the DPC Credit Agreement and may be used for future collateral posting requirements or released per the terms of the applicable credit agreement.

(4) Does not reflect our ability to use the first lien structure as described in “Collateral Postings” below.

DPC and DMG Restricted Payments. The DPC Credit Agreement and the DMG Credit Agreement allow distributions by DPC and DMG to their parents of up to $135 million and $90 million per year, respectively, provided the borrower and its subsidiaries possess at least $50 million of unrestricted cash and short-term investments as of the date of the proposed distribution. There were no distributions made by DPC or DMG during the first half of 2012.

Collateral Postings. We use a significant portion of our capital resources in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. The following table summarizes our collateral postings to third parties by legal entity at July 30, 2012, June 30, 2012 and December 31, 2011:

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	July 30, 2012		June 30, 2012		December 31, 2011
	(in millions)
Dynegy Inc.:
Cash	$	1	$	1	$	—
Letters of credit	1		1		—
Total Dynegy Inc.	2		2		—

Dynegy Midwest Generation, LLC:
Cash	$	26	$	23	$	11
Letters of credit	29		29		38
Total DMG	55		52		49

Dynegy Power, LLC:
Cash	$	100	$	117	$	44
Letters of credit	239		239		386
Total DPC	339		356		430

Dynegy Holdings, LLC:
Cash	$	2	$	2	$	—
Letters of credit	26		26		26
Total DH	28		28		26

The change in letters of credit postings from December 31, 2011 to June 30, 2012 is due to a decision to post cash as collateral from the Collateral Posting Accounts instead of letters of credit, reductions due to ordinary course settlements and market conditions, use of first liens, and cancellation of certain contracts. Collateral postings decreased from June 30, 2012 to July 30, 2012 primarily due to settlements and market conditions.

In addition to cash and letters of credit posted as collateral, we have granted additional permitted first priority liens on the assets already subject to first priority liens under the DMG Credit Agreement and the DPC Credit Agreement. The additional liens were granted as collateral under certain of our commodity derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under the DMG Credit Agreement and the DPC Credit Agreement.

The fair value of DMG’s derivatives collateralized by first priority liens included liabilities of $29 million and $11 million at July 30, 2012 and June 30, 2012, respectively. The fair value of DPC’s derivatives collateralized by first priority liens included liabilities of $108 million and $84 million at July 30, 2012 and June 30, 2012, respectively.

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.

Operating Activities

Historical Operating Cash Flows. Our cash flow used in operations totaled $98 million for the six months ended June 30, 2012 primarily due to general and administrative expenses and interest payments to service the Undertaking payable to DH.

Future Operating Cash Flows. Due to the Coal Holdco Transfer, our future operating cash flows will vary based on general and administrative costs, including those associated with restructuring activities.

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Investing Activities

Capital Expenditures. We had approximately $42 million and $128 million in capital expenditures during the six months ended June 30, 2012 and 2011, respectively. Our capital spending by reportable segment was as follows:

	For the Six Months Ended June 30,
	2012		2011
	(in millions)
Coal (1)	$	42	$	87
Gas (2)	—		40
DNE (2)	—		1
Total	$	42	$	128

(1) Effective June 5, 2012, the legal entities included in this segment were transferred to DH, which was deconsolidated effective November 7, 2011. The Coal segment incurred $11 million of capital expenditures subsequent to the Coal Holdco Transfer which are not included in the table above.

(2) Effective November 7, 2011 the legal entities included in these segments were deconsolidated. Capital expenditures for the six months ended June 30, 2012 related to the legal entities included in these segments, but not shown in the table above, were $20 million, $zero, and $6 million for Gas, DNE and Other, respectively.

Capital spending in our Coal segment primarily consisted of environmental and maintenance capital projects. The decrease in our capital expenditures in our Coal segment is largely due to the completion of projects related to our Consent Decree and the transfer of Coal Holdco to DH.

Other Investing Activities. There was a $256 million cash outflow related to the Coal Holdco Transfer .

There was a $55 million cash inflow related to restricted cash balances associated with the DMG LC Facility and DMG Credit Agreement. During the six months ended June 30, 2012, we requested the release of unused cash collateral related to the DMG LC Facility. The actual capacity of the DMG LC Facility has not been reduced, but in the event additional letters of credit are posted, we would be required to post additional collateral.

Cash outflow for purchases of short-term investments during the six months ended June 30, 2011 totaled $247 million. Cash inflow related to maturities of short-term investments for the six months ended June 30, 2011 was $217 million. There was a $53 million cash inflow related to restricted cash balances during the six months ended June 30, 2011 due to a 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 investing cash flows also included $10 million of property insurance claim proceeds.

Financing Activities

Historical Cash Flow from Financing Activities. Cash flow used in financing activities totaled $2 million for the six months ended June 30, 2012 due to repayments of borrowings on the DMG Credit Agreement.

Cash flow provided by financing activities totaled $289 million for the six months ended June 30, 2011 due to $400 million in proceeds from long-term borrowings 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 DPC Credit Agreement and the DMG Credit Agreement. Our financing activities also included $3 million from proceeds of stock option exercises.

Financing Trigger Events. The debt instruments and other financial obligations related to our subsidiaries which have not filed for bankruptcy protection include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events connected to the financing of our non-debtor subsidiaries 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. Our non-debtor subsidiaries do not have any trigger events tied to specified credit ratings or stock price in

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our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.

The pre-petition debt instruments and other financial obligations related to the Debtor Entities included similar trigger events. The Debtor Entities do not currently pay interest or make other debt service payments on such pre-petition obligations and the conditions necessary for certain of such trigger events may exist. The Debtor Entities have entered into and obtained Bankruptcy Court approval of a $15 million Intercompany Revolving Loan Agreement which includes certain covenants and requirements that, if not met, could require early payment or similar actions.

Financial Covenants. 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 six months ended June 30, 2012, and we do not anticipate declaring or paying dividends at least through the consummation of the Plan.

Credit Ratings

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

	Standard & Poor’s	Moody’s	Fitch
Dynegy Inc.:
Corporate Family Rating (1)	D	NR	CC
DH:
Corporate Family Rating (1)	NR	NR	D
Senior Unsecured (1)	NR	NR	CC
DPC:
Senior Secured	B	B2	B

(1) Moody’s Investor Services withdrew its Corporate family rating and the rating of the DH senior unsecured bonds after the Debtor Entities filed the Chapter 11 Cases. Standard & Poor’s withdrew its Corporate family rating and the rating of the DH senior unsecured bonds on May 18, 2012.

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 “Disclosure of Contractual Obligations and Contingent Financial Commitments” in our Form 10-K for further discussion. Please read “Uncertainty of Forward-Looking Statements and Information” for additional factors that could impact our future operating results and financial condition.

RESULTS OF OPERATIONS

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, 2012 and 2011. We have included our outlook for each segment at the end of this section.

As a result of the DH Chapter 11 Cases, we deconsolidated our investment in DH and its wholly-owned subsidiaries as of November 7, 2011. Financial statement periods presented after November 7, 2011 reflect our investment in, and the results of operations of, DH and its wholly-owned subsidiaries under the equity method of accounting. Additionally, as a result of

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the Settlement Agreement we completed the Coal Holdco Transfer effective June 5, 2012. For further discussion, please read Note 3—Chapter 11 Cases—Accounting Impact.

Non-GAAP Performance Measures

In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA. 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 the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy, and must be considered in conjunction with GAAP measures.

We believe that the historical non-GAAP measures disclosed in our filings are 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; therefore, to be truly valuable, they must be used in conjunction with the comparable GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies’ non-GAAP 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.

EBITDA and Adjusted EBITDA. 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 to exclude (i) gains or losses on the sale of assets, (ii) the impacts of mark-to-market changes on economic hedges related to our generation portfolio, (iii) the impact of impairment charges and certain other costs such as those associated with the internal reorganization, including those charges and costs embedded in losses from unconsolidated investments on our consolidated statements of operations, (iv) amortization of intangible assets related to the Sithe acquisition, and (v) income or expense on up front premiums received or paid for financial options in periods other than the strike periods. Our Adjusted EBITDA for the three and six months ended June 30, 2011, is based on our prior methodology which did not include (i) adjustments for up front premiums, (ii) amortization of intangible assets related to the Sithe acquisition, or (iii) mark-to-market adjustments for financial activity not related to our generation portfolio.

We believe EBITDA and Adjusted EBITDA provide a meaningful representation of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our power generation fleet; consequently, it excludes the impact of mark-to-market accounting, impairment charges and gains and losses on sales of assets, and other items that could be considered “non-operating” or “non-core” in nature. Because EBITDA and Adjusted EBITDA are financial measures 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 they provide 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 EBITDA and Adjusted EBITDA format.

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 EBITDA and 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 is Operating income (loss).

Consolidated Summary Financial Information — Three months ended June 30, 2012

Effective November 7, 2011, we deconsolidated our investment in DH, and effective June 5, 2012 we transferred the Coal segment to DH. As a result, the results of our Gas and DNE segments, as well as certain items in the Other segment, and the Coal segment subsequent to June 5, 2012, are not included in our 2012 consolidated results. The following table provides summary financial data regarding our consolidated results of operations for the three month periods ended June 30, 2012 and 2011, respectively:

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	Three Months Ended June 30,
	2012			2011			$ Change			% Change
	(dollars in millions)
Revenues	$	53		$	326		$	(273	)	(84	)%
Cost of sales	(46		)	(225		)	179			80	%
Gross margin, exclusive of depreciation shown separately below	7			101			(94		)	(93	)%
Operating and maintenance expense, exclusive of depreciation shown separately below	(30		)	(106		)	76			72	%
Depreciation and amortization expense	(28		)	(75		)	47			63	%
Loss on Coal Holdco Transfer	(941		)	—			(941		)	100	%
Impairment and other charges	—			(1		)	1			100	%
General and administrative expenses	(44		)	(25		)	(19		)	(76	)%
Operating income (loss)	(1,036		)	(106		)	(930		)	(877	)%
Loss from unconsolidated investment	(1		)	—			(1		)	100	%
Interest expense	(27		)	(89		)	62			70	%
Other income and expense, net	—			3			(3		)	(100	)%
Loss from continuing operations before income taxes	(1,064		)	(192		)	(872		)	(454	)%
Income tax benefit	—			76			(76		)	(100	)%
Net loss	$	(1,064	)	$	(116	)	$	(948	)	(817	)%

The following tables provide summary financial data regarding our operating income (loss) by segment for the three month periods ended June 30, 2012 and 2011, respectively:

	Three Months Ended June 30, 2012
	Coal			Other			Total
	(in millions)
Revenues	$	53		$	—		$	53
Cost of sales	(46		)	—			(46		)
Gross margin, exclusive of depreciation shown separately below	7			—			7
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(30		)	—			(30		)
Depreciation and amortization expense	(28		)	—			(28		)
Loss on Coal Holdco Transfer	(2,652		)	1,711			(941		)
General and administrative expense	(5		)	(39		)	(44		)
Operating income (loss)	$	(2,708	)	$	1,672		$	(1,036	)

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	Three Months Ended June 30, 2011
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	128		$	178		$	20		$	—		$	326
Cost of sales	(86		)	(128		)	(11		)	—			(225		)
Gross margin, exclusive of depreciation shown separately below	42			50			9			—			101
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(39		)	(37		)	(29		)	(1		)	(106		)
Depreciation and amortization expense	(40		)	(33		)	—			(2		)	(75		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	(10		)	(12		)	(3		)	—			(25		)
Operating loss	$	(47	)	$	(32	)	$	(24	)	$	(3	)	$	(106	)

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The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three month period ended June 30, 2012:

	Three Months Ended June 30, 2012
	Coal			Gas		DNE			Other			Total
	(in millions)
Net loss												$	(1,064	)
Interest expense												27
Loss from unconsolidated investment												1
Other items, net												—
Operating income (loss)	$	(2,708	)	$	—	$	—		$	1,672		$	(1,036	)
Other items, net	—			—		—			—			—
Depreciation and amortization expense	28			—		—			—			28
Loss from unconsolidated investment	—			—		—			(1		)	(1		)
EBITDA	(2,680		)	—		—			1,671			(1,009		)
Loss (gain) on Coal Holdco Transfer	2,652			—		—			(1,711		)	941
Restructuring costs	—			—		—			39			39
Loss from unconsolidated investment	—			—		—			1			1
Mark-to-market loss, net	22			—		—			—			22
Deconsolidated Adjusted EBITDA	(6		)	—		—			—			(6		)
Adjustment to include Adjusted EBITDA from unconsolidated investments (1)	2			14		(5		)	—			11
Adjusted EBITDA	$	(4	)	$	14	$	(5	)	$	—		$	5

(1) Effective November 7, 2011, we deconsolidated our investment in DH. As a result, the results of our Gas and DNE segments, as well as certain items in the Other segment, are not included in our consolidated results. Additionally, effective June 5, 2012, we transferred Coal to DH, as such, the results of the Coal segment subsequent to that date are not included in our consolidated results. We recorded losses of $1 million from our unconsolidated investment in DH for the three months ended June 30, 2012. We did not record the remaining losses of $739 million because to do so would have reduced our investment below zero and we do not have an obligation to fund such losses. However, we have included the Adjusted EBITDA from our investment in this adjustment because management uses Adjusted EBITDA to focus on the operating performance of our entire power generation fleet.

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The following table presents a reconciliation of Adjusted EBITDA to Operating income (loss) for our investment in DH:

	Three Months Ended June 30, 2012
	Coal			Gas			DNE			Other			Total
	(in millions)
Operating income (loss)	$	(22	)	$	17		$	(5	)	$	2		$	(8	)
Depreciation and amortization expense	4			36			—			3			43
EBITDA	(18		)	53			(5		)	5			35
Mark-to-market (income) loss, net	2			(53		)	—			—			(51		)
Restructuring charges	1			2			—			(5		)	(2		)
Other	5			2			—			—			7
Amortization of intangibles (1)	12			10			—			—			22
Adjusted EBITDA	$	2		$	14		$	(5	)	$	—		$	11

(1) In connection with DH’s acquisition of Coal Holdco as a result of the Coal Holdco Transfer, DH recorded intangible assets and liabilities related to rail transportation and coal contracts, respectively. The amount in the Gas segment is related to the intangible assets related to the Sithe acquisition.

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three month period ended June 30, 2011:

	Three Months Ended June 30, 2011
	Coal			Gas			DNE			Other			Total
	(in millions)
Net loss													$	(116	)
Income tax benefit													(76		)
Interest expense													89
Other items, net													(3		)
Operating loss	$	(47	)	$	(32	)	$	(24	)	$	(3	)	$	(106	)
Other items, net	—			1			—			2			3
Depreciation and amortization expense	40			33			—			2			75
EBITDA	(7		)	2			(24		)	1			(28		)
Merger agreement transaction costs	—			—			—			—			—
Executive separation agreement expenses	—			—			—			—			—
Mark-to-market (income) loss, net	66			51			13			—			130
Adjusted EBITDA	$	59		$	53		$	(11	)	$	1		$	102

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $273 million from $326 million for the three months ended June 30, 2011 to $53 million for the three months ended June 30, 2012. Of this decrease, $198 million is due to the deconsolidation of DH and $40 million is related to only including two months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer. The remaining decrease is a result of lower market prices, as well as less revenue from capacity sales, premiums, and the financial settlement of derivative instruments, as further described below.

The decrease from realized activity was offset by lower mark-to-market losses on forward sales of power and other derivatives in 2012, compared to 2011. Such losses totaled $21 million for the three months ended June 30, 2012 compared to $129 million for the three months ended June 30, 2011.

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Cost of Sales. Cost of sales decreased by $179 million from $225 million for the three months ended June 30, 2011 to $46 million for the three months ended June 30, 2012. Of this decrease, $139 million is due to the deconsolidation of DH and $39 million is related to only including two months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer. The remaining decrease is due to lower Coal segment generation volumes.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. Operating and maintenance expense decreased by $76 million from $106 million for the three months ended June 30, 2011 to $30 million for the three months ended June 30, 2012. Of this decrease, $66 million is due to the deconsolidation of DH and $14 million is related to only including two months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer.

Depreciation and Amortization Expense. Depreciation expense decreased by $47 million from $75 million for the second quarter 2011 to $28 million for the second quarter 2012. Of this decrease, $35 million is due to the deconsolidation of DH and $5 million is related to only including two months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer.

Loss on Coal Holdco Transfer. As a result of the Coal Holdco Transfer, we recorded a loss of approximately $941 million during the three months ended June 30, 2012. There was no such loss during the three months ended June 30, 2011. Please read Note 3 - Chapter 11 Cases - Accounting Impact for further discussion.

General and Administrative Expenses. General and administrative expenses increased by $19 million from $25 million for the three months ended June 30, 2011 to $44 million for the three months ended June 30, 2012. The increase is primarily due to higher restructuring costs in the three months ended June 30, 2012 compared to the three months ended June 30, 2011. The increase was partially offset by a $15 million decrease due to the deconsolidation of DH and $3 million decrease related to only including two months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer.

Losses from Unconsolidated Investments. We recorded losses of $1 million from our unconsolidated investment in DH for the three months ended June 30, 2012. We did not have any earnings (losses) from unconsolidated investments during the three months ended June 30, 2011. Please read Note 7—Variable Interest Entities for further discussion.

Interest Expense. Interest expense totaled $27 million and $89 million for the three months ended June 30, 2012 and 2011, respectively. The decrease was primarily driven by the absence of interest in the three months ended June 30, 2012 related to the DH unsecured notes and debentures as a result of the Chapter 11 Cases and the repayment of DH’s prior credit agreement. These decreases were partially offset by interest related to the DMG Credit Agreement which has higher borrowing rates and interest related to the Undertaking payable to DH.

Income Tax Benefit. We reported no income taxes for the three month period ended June 30, 2012, compared to an income tax benefit of $76 million for the three months ended June 30, 2011. The effective tax rate in 2012 was zero compared to 40 percent for 2011.

For the three month period ended June 30, 2012, the difference between the effective rate of zero and the statutory rate of 35 percent resulted primarily from a valuation allowance to eliminate our net deferred tax assets partially offset by the impact of state taxes. As of June 30, 2012, we do not believe we will produce sufficient future taxable income, nor are there tax strategies available, to realize our net deferred tax assets not otherwise realized by reversing temporary differences. For the three month period ended June 30, 2011, the difference between the effective rate of 40 percent and the statutory rate of 35 percent resulted primarily from the impact of state taxes.

Adjusted EBITDA. Adjusted EBITDA decreased by $97 million from $102 million for the three months ended June 30, 2011 to $5 million for the three months ended June 30, 2012. The decrease is primarily due to lower overall market and capacity prices in 2012 compared to 2011 and lower premium revenue in 2012. Offsetting the decrease to Adjusted EBITDA from lower pricing, operating expense decreased due to lease expense associated with the DNE assets no longer being accrued and general and administrative expense decreased due to a reduction in head count.

Discussion of Segment Results of Operations

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reflected in the results of DH, our equity method investment. Additionally, we completed the Coal Holdco Transfer effective June 5, 2012. As such, the results of our Coal segment subsequent to the transfer are not reflected in our consolidated results, but instead are reflected in the results of DH. We have included the results for the Gas and DNE Segments in our Discussion of Segment Results of Operations because management still reviews the results of the company on an enterprise-wide basis and we believe it is meaningful to investors.

Coal Segment. Both on-peak and off-peak power prices were lower in the second quarter 2012 compared to the second quarter 2011 while generation volumes decreased period over period.

As discussed above, as a result of the Coal Holdco Transfer, 2012 results only include the results of the Coal segment through June 5, 2012. The following table provides summary financial data regarding our Coal segment results of operations for the three month periods ended June 30, 2012 and 2011, respectively:

	Three Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	69		$	174		$	(105	)	(60	)%
Capacity	—			1			(1		)	(100	)%
Financial transactions:
Mark-to-market income (loss)	(21		)	(65		)	44			68	%
Financial settlements	4			4			—			—	%
Option premiums	1			16			(15		)	(94	)%
Total financial transactions	(16		)	(45		)	29			64	%
Other (1)	—			(2		)	2			100	%
Total revenues	53			128			(75		)	(59	)%
Cost of sales	(46		)	(86		)	40			47	%
Gross margin	$	7		$	42		$	(35	)	(83	)%
Million Megawatt Hours Generated	4.6			5.8			(1.2		)	(21	)%
In Market Availability for Coal Fired Facilities (2)	93		%	94		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Indiana (Indy Hub) (4)	$	34		$	44		$	(10	)	(23	)%

(1) Other includes ancillary services and other miscellaneous items.

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

(3) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

(4) The market reference for 2011 was Cinergy (Cin Hub).

Gross margin for Coal decreased by $35 million from $42 million for the three months ended June 30, 2011, to $7 million for the three months ended June 30, 2012. There is approximately $1 million in gross margin, which includes amortization of intangibles of $12 million mark-to-market losses of $2 million, that is not included in the 2012 results due to the Coal Holdco Transfer. The decrease is driven by the following:

· Energy revenue and the corresponding cost of sales both decreased by $105 million and $40 million, respectively, for a net decrease in energy margin of $65 million. The decrease in energy revenue is due to lower market prices and more planned outages, both of which led to lower volumes produced. Much of the market impacts on volume occurred during off-peak hours.

· Premium revenue decreased by $15 million due to a reduction in the number of options sold in the second quarter 2012 compared to the second quarter 2011.

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The above decreases were partially offset by the following:

· Mark-to-market revenue increased by $44 million due to a net change in mark-to-market losses of $65 million in the second quarter 2011 to $21 million in the second quarter 2012.

Gas Segment. As discussed above, our second quarter 2012 consolidated results do not include the results of our Gas segment due to the deconsolidation of DH. Spark-spreads were higher in the second quarter 2012 compared to the second quarter 2011 resulting in higher generation volumes period over period.

The following table provides summary financial data regarding our Gas segment results of operations for the three month periods ended June 30, 2012 and 2011, respectively:

	Three Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	138		$	107		$	31		29	%
Capacity	61			64			(3		)	(5	)%
Tolls	19			20			(1		)	(5	)%
RMR	3			1			2			200	%
Natural gas	30			31			(1		)	(3	)%
Financial transactions:
Mark-to-market income (loss)	46			(51		)	97			190	%
Financial settlements	(56		)	(21		)	(35		)	(167	)%
Option premiums	3			30			(27		)	(90	)%
Total financial transactions	(7		)	(42		)	35			83	%
Other (1)	(10		)	(3		)	(7		)	(233	)%
Total revenues	234			178			56			31	%
Cost of sales	(131		)	(128		)	(3		)	(2	)%
Gross margin	$	103		$	50		$	53		106	%

Million Megawatt Hours Generated (2)	4.8			2.6			2.2			85	%
Average Capacity Factor for Combined Cycle Facilities (3)	50		%	27		%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Commonwealth Edison (NI Hub)	$	32		$	44		$	(12	)	(27	)%
PJM West	$	39		$	56		$	(17	)	(30	)%
North of Path 15 (NP 15)	$	26		$	34		$	(8	)	(24	)%
New York—Zone A	$	32		$	42		$	(10	)	(24	)%
Mass Hub	$	35		$	49		$	(14	)	(29	)%
Average Market Spark Spreads ($/MWh) (5):
PJM West	$	22		$	24		$	(2	)	(8	)%
North of Path 15 (NP 15)	$	6		$	—		$	6		100	%
New York—Zone A	$	13		$	7		$	6		86	%
Mass Hub	$	18		$	16		$	2		13	%

Average natural gas price—Henry Hub ($/MMBtu) (6)	$	2.27		$	4.35		$	(2.08	)	(48	)%

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(1) Other includes ancillary services and other miscellaneous items.

(2) Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility for the three months ended June 30, 2012 and 2011, respectively.

(3) Reflects actual production as a percentage of available capacity.

(4) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

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

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

Gross margin for Gas increased by $53 million from $50 million for the three months ended June 30, 2011, to $103 million for the three months ended June 30, 2012. This increase is driven by the following:

· Mark-to-market revenue increased by $97 million due to a net change in mark-to-market losses of $51 million in the second quarter 2011 to mark-to-market revenue of $46 million in the second quarter 2012.

· Energy revenue and the corresponding cost of sales increased by $31 million and $3 million, respectively, for a net increase in energy margin of $28 million. Energy revenue and cost of sales increased due to higher volumes generated. Volumes were up due to higher spark spreads at Moss Landing, Kendall, Independence and Casco Bay in the second quarter 2012 compared to the second quarter 2011. Volumes were also up due to fewer planned outage hours at Moss Landing which were partially offset by more planned outage hours at Kendall. The increases to both energy revenue and cost of sales caused by higher generation volumes were offset by lower power and gas pricing across all regions.

The above increases were partially offset by the following decreases:

· Settlements revenue decreased by $35 million primarily due to an increase in settlement expense associated with gas positions executed in prior periods.

· Premium revenue decreased by $27 million due to a reduction in the number of options sold.

· Capacity revenue decreased by $3 million due to lower capacity prices in the second quarter 2012 compared to the second quarter 2011. Capacity prices have decreased significantly quarter over quarter due to excess capacity in the PJM market.

DNE Segment. As discussed above, our 2012 consolidated results do not include the results of our DNE segment due to the deconsolidation of DH. During the period, dark spreads at Danskammer were compressed by lower Zone G prices and increased coal prices.

The following table provides summary financial data regarding our DNE segment results of operations for the three month periods ended June 30, 2012 and 2011, respectively:

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	Three Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	13		$	18		$	(5	)	(28	)%
Capacity	5			5			—			—	%
Financial transactions:
Mark-to-market income (loss)	(1		)	(13		)	12			92	%
Financial settlements	—			9			(9		)	(100	)%
Option premiums	—			—			—			100	%
Financial transactions	(1		)	(4		)	3			75	%
Other (1)	1			1			—			—	%
Total revenues	18			20			(2		)	(10	)%
Cost of sales	(9		)	(11		)	2			18	%
Gross margin	$	9		$	9		$	—		—	%
Million Megawatt Hours Generated	0.2			0.2			—			—	%
In Market Availability for Coal Fired Facilities (2)	86		%	97		%
Average Capacity Factor—Coal	6		%	16		%
Average Capacity Factor—Gas	4		%	3		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	40		$	56		$	(16	)	(29	)%
Average Market Spark Spreads ($/MWh) (4):
Fuel Oil	$	(149	)	$	(131	)	$	(18	)	(14	)%

(1) Other includes ancillary services and other miscellaneous items.

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

(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.

Gross margin for DNE remained relatively flat from the three months ended June 30, 2011 to the three months ended June 30, 2012 as a result of the following:

· Energy revenue and the corresponding cost of sales decreased by $5 million and $2 million respectively for a net decrease in energy margin of $3 million. Energy margin decreased due to lower power prices and lower generation volumes. The decrease in volumes is due to fewer economic opportunities to dispatch in 2012 compared to 2011.

· Settlement revenue decreased by $9 million due to a reduction in the use of financial instruments to hedge DNE. In 2011, a majority of these instruments were terminated with only limited derivatives in 2012.

The above decreases were partially offset by the following:

· Mark-to-market revenue increased by $12 million due to a net change in mark-to-market losses of $13 million in the second quarter 2011 to $1 million in the second quarter 2012. In 2011 the financial instruments associated with DNE were closed and there were significantly fewer financial instruments in 2012.

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Consolidated Summary Financial Information — Six months ended June 30, 2012

Effective November 7, 2011, we deconsolidated our investment in DH. Effective June 5, 2012, we completed the Coal Holdco Transfer. As a result, the results of our Gas and DNE segments, as well as certain items in the Other segment, are not included in our 2012 consolidated results and the results of our Coal segment are only included in our consolidated results until June 5, 2012. The following table provides summary financial data regarding our consolidated results of operations for the six month periods ended June 30, 2012 and 2011, respectively:

	Six Months Ended June 30,
	2012			2011			$ Change			% Change
	(dollars in millions)
Revenues	$	230		$	831		$	(601	)	(72	)%
Cost of sales	(132		)	(503		)	371			74	%
Gross margin, exclusive of depreciation shown separately below	98			328			(230		)	(70	)%
Operating and maintenance expense, exclusive of depreciation shown separately below	(69		)	(216		)	147			68	%
Depreciation and amortization expense	(78		)	(201		)	123			61	%
Loss on Coal Holdco Transfer	(941		)	—			(941		)	100	%
Impairment and other charges	—			(1		)	1			100	%
General and administrative expenses	(67		)	(65		)	(2		)	(3	)%
Operating income (loss)	(1,057		)	(155		)	(902		)	(582	)%
Loss from unconsolidated investment	(1		)	—			(1		)	100	%
Interest expense	(64		)	(178		)	114			64	%
Other income and expense, net	—			4			(4		)	(100	)%
Loss from continuing operations before income taxes	(1,122		)	(329		)	(793		)	(241	)%
Income tax benefit	—			136			(136		)	(100	)%
Net loss	$	(1,122	)	$	(193	)	$	(929	)	(481	)%

The following tables provide summary financial data regarding our operating income (loss) by segment for the six month periods ended June 30, 2012 and 2011, respectively:

	Six Months Ended June 30, 2012
	Coal			Other			Total
	(in millions)
Revenues	$	230		$	—		$	230
Cost of sales	(132		)	—			(132		)
Gross margin, exclusive of depreciation shown separately below	98			—			98
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(69		)	—			(69		)
Depreciation and amortization expense	(78		)	—			(78		)
Loss on Coal Holdco Transfer	(2,652		)	1,711			(941		)
General and administrative expense	(14		)	(53		)	(67		)
Operating loss	$	(2,715	)	$	1,658		$	(1,057	)

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	Six Months Ended June 30, 2011
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	328		$	445		$	58		$	—		$	831
Cost of sales	(177		)	(293		)	(33		)	—			(503		)
Gross margin, exclusive of depreciation shown separately below	151			152			25			—			328
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(79		)	(79		)	(56		)	(2		)	(216		)
Depreciation and amortization expense	(130		)	(67		)	—			(4		)	(201		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	(21		)	(25		)	(7		)	(12		)	(65		)
Operating loss	$	(79	)	$	(19	)	$	(39	)	$	(18	)	$	(155	)

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The following table provides summary financial data regarding our Adjusted EBITDA by segment for the six month period ended June 30, 2012:

	Six Months Ended June 30, 2012
	Coal			Gas		DNE			Other			Total
	(in millions)
Net loss												$	(1,122	)
Income tax benefit												—
Interest expense												64
Loss from unconsolidated investment												1
Other items, net												—
Operating income (loss)	$	(2,715	)	$	—	$	—		$	1,658		$	(1,057	)
Other items, net	—			—		—			—			—
Depreciation and amortization expense	78			—		—			—			78
Loss from unconsolidated investment	—			—		—			(1		)	(1		)
EBITDA	(2,637		)	—		—			1,657			(980		)
Loss (gain) on Coal Holdco Transfer	2,652			—		—			(1,711		)	941
Restructuring costs	—			—		—			53			53
Loss from unconsolidated investment	—			—		—			1			1
Mark-to-market income, net	(8		)	—		—			—			(8		)
Deconsolidated Adjusted EBITDA	7			—		—			—			7
Adjustment to include Adjusted EBITDA from unconsolidated investments (1)	2			39		(20		)	1			22
Adjusted EBITDA	$	9		$	39	$	(20	)	$	1		$	29

(1) Effective November 7, 2011, we deconsolidated our investment in DH. As a result, the results of our Gas and DNE segments, as well as certain items in the Other segment, are not included in our consolidated results. Additionally, effective June 5, 2012, we completed the Coal Holdco Transfer, as such, the results of the Coal segment subsequent to that date are not included in our consolidated results. We recorded losses of $1 million from our unconsolidated investment in DH for the six months ended June 30, 2012. We did not record the remaining losses of $1.18 billion because to do so would have reduced our investment below zero and we do not have an obligation to fund such losses.

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However, we have included the Adjusted EBITDA from our investment in this adjustment because management uses Adjusted EBITDA to focus on the operating performance of our entire power generation fleet.

A reconciliation of Adjusted EBITDA to Operating income (loss) for our investment in DH is presented below:

	Six Months Ended June 30, 2012
	Coal			Gas			DNE			Other			Total
	(in millions)
Operating income (loss)	$	(22	)	$	36		$	(20	)	$	(4	)	$	(10	)
Depreciation and amortization expense	4			56			—			5			65
EBITDA	(18		)	92			(20		)	1			55
Mark-to-market (income) loss, net	2			(78		)	—			—			(76		)
Restructuring charges	1			2			—			—			3
Amortization of intangible assets (1)	12			20			—			—			32
Other	5			2			—			—			7
Premium adjustment	—			1			—			—			1
Adjusted EBITDA	$	2		$	39		$	(20	)	$	1		$	22

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the six month periods ended June 30, 2011:

	Six Months Ended June 30, 2011
	Coal			Gas			DNE			Other			Total
	(in millions)
Net loss													$	(193	)
Income tax benefit													(136		)
Interest expense													178
Other items, net													(4		)
Operating loss	$	(79	)	$	(19	)	$	(39	)	$	(18	)	$	(155	)
Other items, net	—			1			—			3			4
Depreciation and amortization expense	130			67			—			4			201
EBITDA	51			49			(39		)	(11		)	50
Merger agreement transaction costs	—			—			—			9			9
Executive separation agreement expenses	—			—			—			3			3
Mark-to-market (income) loss, net	73			31			23			—			127
Adjusted EBITDA	$	124		$	80		$	(16	)	$	1		$	189

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $601 million from $831 million for the six months ended June 30, 2011 to $230 million for the six months ended June 30, 2012. Of this decrease, $503 million is due to the deconsolidation of DH and $40 million to only including five months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer. The remaining decrease is related to lower market prices, as well as less revenue from premiums and the financial settlement of derivative instruments, as further described below.

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The decrease from realized activity was offset by higher mark-to-market gains on forward sales of power and other derivatives in 2012 compared to 2011. Such gains totaled $9 million for the six months ended June 30, 2012 compared to losses of $127 million for the six months ended June 30, 2011.

Cost of Sales. Cost of sales decreased by $371 million from $503 million for the six months ended June 30, 2011 to $132 million for the six months ended June 30, 2012. Of this decrease, $326 million is due to the deconsolidation of DH and $39 million to only including five months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. Operating and maintenance expense decreased by $147 million from $216 million for the six months ended June 30, 2011 to $69 million for the six months ended June 30, 2012. Of this decrease, $135 million is due to the deconsolidation of DH and $14 million to only including five months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer.

Depreciation and Amortization Expense. Depreciation expense decreased by $123 million from $201 million for the six months ended June 30, 2011 to $78 million for the six months ended June 30, 2012. Of this decrease, $67 million is due to the deconsolidation of DH and $5 million to only including five months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer. In addition, the Vermilion facility was mothballed during the six months ended June 30, 2011 and subsequently retired resulting in a decrease of $50 million.

Loss on Coal Holdco Transfer. As a result of the Coal Holdco Transfer, we recorded a loss of approximately $941 million during the six months ended June 30, 2012. There was no such loss during the six months ended June 30, 2011. Please read Note 3—Chapter 11 Cases—Accounting Impact for further discussion.

General and Administrative Expenses. General and administrative expenses increased by $2 million from $65 million for the six months ended June 30, 2011 to $67 million for the six months ended June 30, 2012. The increase is primarily due to higher restructuring costs in the six months ended June 30, 2012 compared to the six months ended June 30, 2011. The increase was partially offset by a $32 million decrease due to the deconsolidation of DH and a $3 million decrease related to only including five months of activity related to the Coal segment in 2012 results due to the Coal Holdco Transfer with the remaining decrease primarily driven by lower salary and benefits costs as a result of ongoing cost savings initiatives.

Losses from Unconsolidated Investments. We recorded losses of $1 million from our unconsolidated investment in DH for the six months ended June 30, 2012. We did not have any earnings (losses) from unconsolidated investments during the six months ended June 30, 2011. Please read Note 7—Variable Interest Entities for further discussion.

Interest Expense. Interest expense totaled $64 million and $178 million for the six months ended June 30, 2012 and 2011, respectively. The decrease was primarily driven by the absence of interest expense in the six months ended June 30, 2012 related to the DH unsecured notes and debentures as a result of the DH Chapter 11 Cases and the and the repayment of DH’s prior credit agreement. These decreases were partially offset by interest related to the DMG Credit Agreement which has higher borrowing rates and interest expense on the Undertaking payable to DH.

Income Tax Benefit. We reported no income taxes from continuing operations for the six months ended June 30, 2012, compared to an income tax benefit from continuing operations of $136 million for the six months ended June 30, 2011. The effective tax rate in 2012 was zero percent compared to 41 percent for 2011.

For the six month period ended June 30, 2012, the difference between the effective rate of zero percent and the statutory rate of 35 percent resulted primarily from a valuation allowance to eliminate our net deferred tax assets partially offset by the impact of state taxes. As of June 30, 2012, we do not believe we will produce sufficient future taxable income, nor are there tax strategies available, to realize our net deferred tax assets not otherwise realized by reversing temporary differences.

For the six months ended June 30, 2011, the difference between the effective rate of 41 percent and the statutory rate of 35 percent resulted primarily from the impact of state taxes.

Adjusted EBITDA. Adjusted EBITDA decreased by $160 million from $189 million for the six months ended June 30, 2011 to $29 million for the six months ended June 30, 2012. The decrease is primarily due to lower overall market and capacity prices in 2012 compared to 2011 and lower premium revenue in 2012. Offsetting the decrease to adjusted EBITDA from lower pricing, operating expense decreased due to lease expense associated with the DNE assets no longer being accrued and general and administrative expense decreased due to a reduction in head count.

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Discussion of Segment Results of Operations

Effective November 7, 2011, we deconsolidated our investment in DH. As a result, the results of our Gas and DNE segment, as well as certain items in the Other segment, were not included in our 2012 consolidated results but instead are reflected in the results of DH, our equity method investment. Additionally, we transferred Coal Holdco to DH effective June 5, 2012. As such, the results of our Coal segment subsequent to the transfer are not reflected in our consolidated results, but instead are reflected in the results of DH. We have included the results for the Gas and DNE Segments in our Discussion of Segment Results of Operations because management still reviews the results of the company on an enterprise-wide basis and we believe it is meaningful to investors.

Coal Segment. Both on-peak and off-peak power prices were lower in the six months ended June 30, 2012 compared to the six months ended June 30, 2011 while generation volumes decreased period over period.

As discussed above, 2012 results only include the results of the Coal segment through June 5, 2012 as a result of the Coal Holdco Transfer. The following table provides summary financial data regarding our Coal segment results of operations for the six month periods ended June 30, 2012 and 2011, respectively:

	Six Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	193		$	363		$	(170	)	(47	)%
Capacity	—			2			(2		)	(100	)%
Financial transactions:
Mark-to-market income (loss)	9			(72		)	81			113	%
Financial settlements	27			21			6			29	%
Option premiums	1			16			(15		)	(94	)%
Total financial transactions	37			(35		)	72			206	%
Other (1)	—			(2		)	2			100	%
Total revenues	230			328			(98		)	(30	)%
Cost of sales	(132		)	(177		)	45			25	%
Gross margin	$	98		$	151		$	(53	)	(35	)%
Million Megawatt Hours Generated	10.2			11.8			(1.6		)	(14	)%
In Market Availability for Coal Fired Facilities (2)	94		%	93		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Indiana (Indy Hub) (4)	$	32		$	42		$	(10	)	(24	)%

(1) Other includes ancillary services and other miscellaneous items.

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

(3) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

(4) The market reference for 2011 was Cinergy (Cin Hub).

Gross margin for Coal decreased by $53 million from $151 million for the six months ended June 30, 2011, to $98 million for the six months ended June 30, 2012. There is approximately $1 million in gross margin, which includes amortization of intangibles of $12 million and mark-to-market losses of $2 million, that is not included in the 2012 results due to the Coal Holdco Transfer. This decrease is driven by the following:

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· Energy revenue and the corresponding cost of sales decreased by $170 million and $45 million, respectively, for a net decrease in energy margin of $125 million. The decrease in energy margin was due to lower market prices and more planned outages, both of which led to lower volumes produced. Much of the market impacts on volume occurred during the off-peak hours.

· Premium revenue decreased by $15 million due to a reduction in the number of options sold in the six months ended June 30, 2012 compared to the six months ended June 30, 2011.

The above decreases were partially offset by the following:

· Mark-to-market revenue increased by $81 million due to a net change in mark-to-market losses of $72 million in the six months ended June 30, 2011 compared to mark-to-market revenue of $9 million in the six months ended June 30, 2012.

· Settlements revenue increased by $6 million primarily due to an increase in revenue received from power swaps. This increase was partially offset by lower volumes hedged in the six months ended June 30, 2012 compared to the six months ended June 30, 2011.

Gas Segment. As discussed above, our six months ended June 30, 2012 consolidated results do not include the results of our Gas segment due to the deconsolidation of DH. Spark-spreads were higher in the six months ended June 30, 2012 compared to the six months ended June 30, 2011 resulting in higher generation volumes period over period.

The following table provides summary financial data regarding our Gas segment results of operations for the six month periods ended June 30, 2012 and 2011, respectively:

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	Six Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	297		$	218		$	79		36	%
Capacity	119			131			(12		)	(9	)%
Tolls	39			39			—			—	%
RMR	4			2			2			100	%
Natural gas	62			95			(33		)	(35	)%
Financial transactions:
Mark-to-market income (loss)	89			(31		)	120			387	%
Financial settlements	(97		)	(34		)	(63		)	(185	)%
Option premiums	2			31			(29		)	(94	)%
Total financial transactions	(6		)	(34		)	28			82	%
Other (1)	(13		)	(6		)	(7		)	(117	)%
Total revenues	502			445			57			13	%
Cost of sales	(311		)	(293		)	(18		)	(6	)%
Gross margin	$	191		$	152		$	39		26	%
Million Megawatt Hours Generated (2)	10.7			5.2			5.5			106	%
Average Capacity Factor for Combined Cycle Facilities (3)	55		%	27		%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Commonwealth Edison (NI Hub)	$	31		$	42		$	(11	)	(26	)%
PJM West	$	37		$	54		$	(17	)	(31	)%
North of Path 15 (NP 15)	$	27		$	35		$	(8	)	(23	)%
New York—Zone A	$	32		$	42		$	(10	)	(24	)%
Mass Hub	$	35		$	57		$	(22	)	(39	)%
Average Market Spark Spreads ($/MWh) (5):
PJM West	$	18		$	18		$	—		—	%
North of Path 15 (NP 15)	$	5		$	2		$	3		150	%
New York—Zone A	$	11		$	7		$	4		57	%
Mass Hub	$	14		$	16		$	(2	)	(13	)%
Average natural gas price—Henry Hub ($/MMBtu) (6)	$	2.36		$	4.26		$	(1.9	)	(45	)%

(1) Other includes ancillary services and other miscellaneous items.

(2) Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility for the six months ended June 30, 2012 and 2011, respectively.

(3) Reflects actual production as a percentage of available capacity.

(4) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

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

Gross margin for Gas increased by $39 million from $152 million for the six months ended June 30, 2011, to $191 million for the six months ended June 30, 2012. This increase is driven by the following:

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· Energy revenue and the corresponding cost of sales increased by $79 million and $18 million, respectively, for a net increase in energy margin of $61 million. Energy revenue and cost of sales increased due to higher volumes generated. Volumes were up due to higher spark spreads at Moss Landing, Kendall, Ontelaunee, Independence and Casco Bay in the six months ended June 30, 2012 compared to the six months ended June 30, 2011. Volumes were also up due to fewer planned outage hours at Moss Landing and Casco Bay in the first six months of 2011 which were partially offset by more planned outage hours at Kendall in the first six months of 2012. The increases to both energy revenue and cost of sales caused by higher generation volumes were offset by lower power and gas pricing across all regions.

· Mark-to-market revenue increased by $120 million due to a net change in mark-to-market losses of $31 million in the six months ended June 30, 2011 to mark-to-market revenue of $89 million in the six months ended June 30, 2012.

The above increases were partially offset by the following:

· Capacity revenue decreased by $12 million due to lower capacity prices in the six months ended June 30, 2012 compared to the six months ended June 30, 2011. Capacity prices have decreased significantly year over year due to excess capacity in the PJM market.

· Gas revenue decreased by $33 million due to lower volumes sold and lower gas pricing in the six months ended June 30, 2012 compared to the six months ended June 30, 2011. As we lack gas storage capability, all gas purchased must be used in generation or sold back to the market. Higher generation across the gas fleet in the first six months of 2012 led to less gas available for resale and therefore less gas revenue.

· Settlements revenue decreased by $63 million primarily due to an increase in settlement expense associated with gas positions executed in prior periods.

· Premium revenue decreased by $29 million due to a reduction in the number of options sold.

DNE Segment. As discussed above, our 2012 consolidated results do not include the results of our DNE segment due to the deconsolidation of DH. During the six months ended June 30, 2012, dark spreads at Danskammer were compressed by lower Zone G prices and increased coal prices.

The following table provides summary financial data regarding our DNE segment results of operations for the six month periods ended June 30, 2012 and 2011, respectively:

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	Six Months Ended
	June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	17		$	52		$	(35	)	(67	)%
Capacity	7			9			(2		)	(22	)%
Financial transactions:
Mark-to-market income (loss)	(1		)	(23		)	22			96	%
Financial settlements	—			18			(18		)	(100	)%
Option premiums	—			—			—			100	%
Financial transactions	(1		)	(5		)	4			80	%
Other (1)	2			2			—			—	%
Total revenues	25			58			(33		)	(57	)%
Cost of sales	(15		)	(33		)	18			55	%
Gross margin	$	10		$	25		$	(15	)	(60	)%
Million Megawatt Hours Generated	0.3			0.6			(0.3		)	(50	)%
In Market Availability for Coal Fired Facilities (2)	91		%	95		%
Average Capacity Factor—Coal	7		%	33		%
Average Capacity Factor—Gas	2		%	2		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	39		$	60		$	(21	)	(35	)%
Average Market Spark Spreads ($/MWh) (4):
Fuel Oil	$	(156	)	$	(115	)	$	(41	)	(36	)%

(1) Other includes ancillary services and other miscellaneous items.

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

(3) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

Gross margin for DNE decreased by $15 million from $25 million for the six months ended June 30, 2011, to $10 million for the six months ended June 30, 2012. This decrease is driven by the following:

· Energy revenue and the corresponding cost of sales decreased by $35 million and $18 million, respectively, for a net decrease in energy margin of $17 million. Energy margin decreased due to lower power prices and lower generation volumes. The decrease in volumes is due to fewer economic opportunities to dispatch during the six months ended June 30, 2012 compared to the six months ended June 30, 2011.

· Settlement revenue decreased by $18 million due to a reduction in the use of financial instruments associated with DNE. In 2011, a majority of our DNE instruments were terminated and we have limited derivative use during the six months ended June 30, 2012.

The above decreases were partially offset by the following:

· Mark-to-market revenue increased by $22 million due to a net change in mark-to-market losses of $23 million in the six months ended June 30, 2011 to $1 million in the six months ended June 30, 2012. In 2011 the financial instruments associated with DNE were closed out and there were significantly fewer financial instruments in 2012.

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Outlook

We are focused on reducing and consolidating non-plant support activities and achieving cost efficiencies at both operating facilities and corporate support functions. Going forward, we have an operating fleet supported by our service contracts, which has resulted in adjusting corporate functions to support the new operational model. As previously discussed, the Gas and DNE segments, as well as the Coal segment, as of June 5, 2012, are owned by DH, which is accounted for as an equity method investment. For purposes of this discussion, we have included the Coal, Gas and DNE segments, as management still reviews the results of the company on an enterprise-wide basis and we believe it is meaningful to investors.

On November 7, 2011, the DH Debtor Entities filed the DH Chapter 11 Cases. On July 6, 2012, Dynegy commenced the Dynegy Chapter 11 Case. None of Dynegy’s direct or indirect subsidiaries other than the five DH Debtor Entities, sought relief under the Bankruptcy Code, and none of those entities are debtors thereunder. The Debtor Entities will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Coal Holdco and its indirect, wholly-owned subsidiary, DMG, as well as all other subsidiaries of DH other than the Debtor Entities, including DPC and all of its subsidiaries, are not included in the Chapter 11 Cases. The normal day-to-day operations of the coal-fired power generation facilities held by DMG and the gas-fired generation facilities held by DPC will continue without interruption.

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 Coal segment consists of six plants, all located in the MISO region, and totaling 3,132 MW.

Our Consent Decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in Illinois. We have achieved all emission reductions scheduled to date under the Consent Decree and only Baldwin Unit 2 has material outstanding Consent Decree work yet to be performed, which is scheduled for completion by the end of 2012. We expect our costs associated with the remaining Consent Decree projects as of June 30, 2012, to be approximately $31 million and $3 million for the remainder of 2012 and 2013, respectively. This estimate includes a number of assumptions about uncertainties beyond our control, such as costs associated with labor and materials.

Our expected coal requirements are fully contracted and priced in 2012. Our forecast coal requirements for 2013 are 85 percent contracted and 53 percent priced. The remaining contracted volumes are unpriced but are subject to a price collar structure. Our coal transportation requirements are 100 percent contracted and priced through 2013 when our current contracts expire. We have recently executed new coal transportation contracts which take effect when our current contracts expire. These new long-term contracts also cover 100 percent of our coal transportation requirements. We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies.

Our Coal expected generation volumes are volumetrically 75 percent hedged through 2012 and approximately 13 percent hedged for 2013.

Moves by various market transmission-owning entities joining or exiting the MISO could impact system planning reserve margins in the future. The MISO filed proposed Resource Adequacy Enhancements with FERC on July 20, 2011. FERC conditionally approved MISO’s proposal on June 11, 2012, leaving much of MISO’s proposal in place. The proposed tariff revisions require capacity to be procured on a zonal basis for a full planning year (June 1 - May 31) versus the current monthly requirement, with procurement occurring two months ahead of the planning year. The new construct will be in place for the 2013-14 Planning Year. While the 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 poor economics or expected environmental mandates could also affect MISO capacity and energy market prices in the future.

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We currently intend to retire the Oglesby and Stallings peaking facilities, representing 152 MW, by the end of 2012, subject to a reliability assessment by MISO.

Gas. The Gas segment consists of eight plants, geographically diverse in five markets, totaling 6,771 MW. Approximately 50 percent of our power plant capacity in the CAISO market is contracted through 2012 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.

The CAISO capacity market is bilateral in nature. The load-serving entities are required to procure sufficient resources for their peak load plus a fifteen percent reserve margin. The CAISO footprint currently has a capacity surplus due to a weak economy and increased participation from renewable resources. The CAISO faces challenges to ensure system reliability as well as adequate ancillary services in the future with the mandate to have 33 percent renewable resources by 2020. The combination of bilateral markets, one-off utility procurements, and short-term requirements make this a larger concern than in other markets where multi-year forward requirements and more transparent markets are in place.

Certain contractual arrangements were terminated in mid-May 2012 for the Gas assets in the West. Such terminations will likely impact the timing of cash flows going forward. We are actively seeking other commercial arrangements for the facilities and have been offering output in the day-ahead market administered by the CAISO since May 19, 2012. We will continue to respond to the RFO from California utilities seeking to procure electric capacity needed to serve their customers. While we have been successful in winning contracts through this RFO process in the past, we believe that a more forward-looking, transparent, market-based solution to securing electric supply would benefit consumers, utilities and independent generators. We have no plans to retire the impacted facilities at this time, and as long as the plants are economically viable, we will continue to operate them.

The South Bay power generation facility has been permanently retired and is currently in the process of being decommissioned. We have a contractual obligation to demolish the facility and potentially remediate specific parcels of the property. Our cost estimates for the demolition of the facility have not been finalized as we are in the early phases of the demolition process. Our obligation is expected to be approximately $22 million, exclusive of certain rental payments that will be due the Port of San Diego. Our estimates for the demolition and any potential remediation costs will likely change as the project advances through the next phase of the demolition process.

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 would be required to install cooling systems that could 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.

In New England, five forward capacity auctions have been held since the ISO-NE transitioned to a forward capacity 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. We anticipate the next forward capacity market auction for 2015-2016 to clear at the floor price of approximately $3.43 per kW-month. The annual auctions continue to clear at the designated floor due to oversupply conditions. 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 2015-2016 Planning Year, which cleared at $4.14/kW-month (Kendall) and $5.09/kW-month (Ontelaunee).

Although capacity prices have been trending downward in NYISO due to surplus capacity and lower demand, the summer auction for 2012 cleared at $1.25 per kW-month. This is approximately $0.70 higher than last summer, which cleared at $0.55 per kW-month. Approximately 70 percent of the capacity revenue for our Independence facility has been contracted at a favorable premium compared to current market prices through 2014.

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Currently, our Gas portfolio is approximately 91 percent hedged volumetrically through 2012 and approximately 47 percent hedged for 2013.

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

DNE. DNE is comprised of the Roseton and Danskammer facilities located in Newburgh, New York, with a total capacity of 1,693 MW. A total of 1,570 MW of generation capacity relates to leased units at the two facilities. In connection with the Chapter 11 cases, the Debtor Entities rejected these long-term leases. The Debtor Entities have operated and plan to continue operating the leased facilities until such facilities can be sold in accordance with the terms of the Settlement Agreement and Plan Support Agreement and in compliance with applicable federal and state regulatory requirements. Please read Note 3—Chapter 11 Cases for further discussion.

All of our expected physical coal supply and delivery requirements for 2012 are fully contracted and priced for the forecasted run throughout the remainder of the year. Shortfall due to unexpectedly high burn rates will be purchased in the spot market from domestic suppliers. We have hedged significantly fewer generation volumes for 2012.

Please read Note 3—Chapter 11 Cases for a discussion of the developments in our Chapter 11 Cases.

Other. Other includes traditional corporate support functions, including those services contemplated in the various service agreements, including the Service Agreements, Energy Management Agreements, Tax Sharing Agreements and Cash Management Agreements, which were entered into in conjunction with the Reorganization.

During 2011, we initiated a new cost and performance improvement initiative, known as PRIDE (“Producing Results through Innovation by Dynegy Employees”), which is designed to drive recurring cash flow benefits by optimizing our cost structure, implementing company-wide process and operating improvements, and improving balance sheet efficiency. In the six months ended June 30, 2012, we recognized $11 million in operating margin and cost improvements versus 2011 and $71 million in incremental liquidity from balance sheet improvements due to PRIDE initiatives. In 2012, we are targeting additional margin and cost improvements of $39 million, and additional balance sheet improvements of $100 million. We will continue to use the PRIDE initiative to improve our operating performance, cost structure and balance sheet.

Environmental and Regulatory Matters

Please read Item 1. Business—Environmental Matters in our Form 10-K for the period ended December 31, 2011 and Outlook—Environmental and Regulatory Matters in our Form 10-Q for the period ended March 31, 2012 for a more detailed discussion.

The Dodd-Frank Act

The CFTC has regulatory oversight authority over the trading of electricity and gas commodities, including financial products and derivatives, under the Commodity Exchange Act. On July 21, 2010, President Obama signed the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which, among other things, aims to improve transparency and accountability in derivative markets. The Dodd-Frank Act increases the CFTC’s regulatory authority on matters related to over-the-counter derivatives, market clearing, position reporting, and capital requirements. The CFTC continues to work to clarify the scope of the Dodd-Frank Act and issue final rules concerning the definition of a “swap,” define terms associated with central clearing and execution exemption for derivative end-users, margin requirements for transactions and other issues that may affect our over-the-counter derivatives trading. Because there are many details that remain to be addressed in CFTC rulemaking proceedings, at this time we cannot measure the impact to our current operations or collateral requirements.

The Clean Air Act

On April 30, 2012, the EPA designated as nonattainment with the 2008 ozone NAAQS the St. Louis-St. Charles-Farmington, Missouri-Illinois area, which includes Madison County, Illinois, the location of our Wood River station. The EPA classified the affected multi-state area as marginal nonattainment with an attainment deadline in 2015. On June 12, 2012, the EPA designated the multi-state area as attainment with the 1997 8-hour ozone NAAQS. While the nature and scope of potential future requirements concerning the 2008 ozone NAAQS cannot be predicted with confidence at this time, a

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requirement for additional NOx emission reductions at our Wood River facility, or any of our other facilities, for purposes of the 2008 ozone NAAQS, may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

On June 15, 2012, the EPA proposed to revise the NAAQS for PM2.5 by lowering the primary annual standard from 15 ug/m3 to in the range of 13 to 11 µg/m3. The EPA is required to take final action by December 31, 2012. The EPA intends to make initial nonattainment designations by December 2014, based on air quality data for 2011 to 2013. The earliest attainment deadlines would be in approximately 2020. The nature and scope of potential future requirements resulting from a more stringent PM2.5 NAAQS cannot be predicted with confidence at this time, but a requirement for additional emission reductions at any of our facilities for purposes of a more stringent PM2.5 NAAQS may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

The Clean Water Act

On June 11, 2012, the EPA released a NODA concerning impingement mortality control requirements in its June 2011 proposed rule for cooling water intake structures. The EPA’s NODA requests comment on new impingement data in the rulemaking record and alternative approaches for impingement controls, which generally would provide more flexibility to affected facilities. The EPA has reached an agreement to extend the deadline for issuing its final rule on cooling water intake structures until June 27, 2013.

Coal Combustion Residuals

In May 2012, we received from the EPA draft dam safety assessment reports of the surface impoundments at our Baldwin and Hennepin facilities. The draft reports would rate the impoundments at each facility as “poor”, meaning that a deficiency is recognized for a required loading condition in accordance with applicable dam safety criteria. A poor rating also applies when further critical studies are needed to identify any potential dam safety deficiencies. The draft reports include recommendations for further studies, repairs, and changes in operational and maintenance practices. We provided comments to the EPA on the draft reports and continue to review the draft reports’ recommendations. The nature and scope of potential required repairs cannot be predicted with confidence at this time, but may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

We have implemented groundwater monitoring plans for the CCR surface impoundment at our Baldwin facility and for two CCR surface impoundments at our Vermilion facility in response to requests by the Illinois EPA. Groundwater monitoring results indicate that the CCR surface impoundments at each site impact onsite groundwater. In July 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at the Baldwin and Vermilion facilities. We previously submitted corrective action plans for the two affected CCR surface impoundments at our Vermilion facility to the Illinois EPA and, based on the results of groundwater monitoring at Baldwin, we intend to apply to the Illinois EPA for a groundwater management zone at Baldwin while impacts from the facility are mitigated. For additional discussion, please read Item 1 - Legal Proceedings.

Climate Change

Federal Regulation of Greenhouse Gases. On June 26, 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion in Coalition For Responsible Regulation, Inc., et al. v. EPA, upholding several EPA GHG-related rules. The court held that the EPA’s Endangerment Finding was not arbitrary and capricious notwithstanding scientific uncertainty and that the Agency had adequate evidence on which to base its finding. The court also held that the Tailpipe Rule was adequately justified and that, upon making the Endangerment Finding, the Agency was required by Clean Air Act Section 202 to regulate tailpipe GHG emissions. The court did not reach the merits of the arguments challenging the EPA’s Timing Rule and Tailoring Rule, instead deciding that the petitioners lacked standing to challenge those rules.

State Regulation of Greenhouse Gases. Our assets in California are subject to the CARB’s GHG cap-and-trade regulation, which imposes cap-and-trade compliance obligations beginning on January 1, 2013. The first allowance auction is scheduled for November 2012. In June 2012, CARB released proposed revisions to the cap-and-trade rule that would link the rule to WCI partner Quebec’s GHG program and allow California entities to comply with the CARB cap-and-trade rule using Quebec-issued compliance instruments. CARB also released other GHG program proposals in June 2012 that address issues such as auction administration and revisions to the mandatory reporting rule. We will continue to monitor developments regarding the California cap-and-trade program and evaluate any potential impacts on our operations.

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Our assets in New York and Maine are subject to a state-driven GHG emission control program known as RGGI. On June 6, 2012, RGGI held its sixteenth auction, in which approximately 20.9 million allowances for the second control period (covering 2012-2014) were sold at a clearing price of $1.93 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. RGGI’s next quarterly auction is scheduled for September 2012.

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, 2012
	(in millions)
Balance Sheet Risk-Management Accounts (1)
Fair value of portfolio at December 31, 2011	$	5
Risk-management losses recognized through the income statement in the period, net	10
Cash received related to risk-management contracts settled in the period, net	(6		)
Changes in fair value as a result of a change in valuation technique	—
Coal Holdco Transfer (2)	(9		)
Non-cash adjustments and other	—
Fair value of portfolio at June 30, 2012	$	—

(1)	Our modeling methodology has been consistently applied.
(2)	On June 5, 2012, the effective date of the Settlement Agreement, we completed the Coal Holdco Transfer. Please read Note 3—Chapter 11 Cases for further discussion.

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

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:

· our ability to obtain approval of the Bankruptcy Court with respect to the Debtor Entities’ motions in the Chapter 11 Cases and to develop, prosecute, confirm and consummate one or more plans of reorganization

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with respect to the Chapter 11 Cases, and to consummate all the transactions contemplated by the Settlement Agreement and Plan Support Agreement;

· our ability to consummate the Merger;

· our ability to sell the Roseton and Danskammer Facilities to one or more third parties as set forth in the Settlement Agreement;

· our ability to obtain the acceptance of the requisite number and amount of holders of claims in the Chapter 11 Cases;

· 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;

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

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

· expectations regarding our compliance with the DMG and DPC Credit Agreements, including collateral demands, interest expense and other payments;

· the timing and anticipated benefits to be achieved through our company-wide cost savings programs, including our PRIDE initiative;

· 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 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;

· 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, administrative, legislative and regulatory matters, including the impact of final rules regarding derivatives to be issued by the CFTC under the Dodd-Frank Act; and

· expectations regarding performance standards and estimates regarding capital and maintenance expenditures, including the 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,

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including those set forth under Part II—Other Information, Item 1A-Risk Factors and Item 1A-Risk Factors of our Form 10-K and Form 10-Q for the quarter ended March 31, 2012.

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

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, 2012.

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 Coal, Gas and DNE segments at DH 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, 2012 VaR was primarily due to decreased forward sales as compared to December 31, 2011.

Daily and Average VaR for Risk-Management Portfolios—DH

	June 30, 2012		December 31, 2011
	(in millions)
One day VaR—95 percent confidence level	$	9	$	12
One day VaR—99 percent confidence level	$	12	$	18
Average VaR for the year-to-date period—95 percent confidence level	$	10	$	9

Credit Risk. The following table represents our credit exposure at June 30, 2012 associated with the mark-to-market portion of DH’s risk-management portfolio, on a net basis.

	Investment Grade Quality		Non-Investment Grade Quality		Total
	(in millions)
Type of Business:
Utility and power generators	$	34	$	—	$	34
Financial institutions	8		—		8
Commercial / industrial / end users	1		10		11

Total	$	43	$	10	$	53

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Item 4—CONTROLS AND PROCEDURES

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 our management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of the design and operation of our 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 our disclosure committee. This evaluation also considered the work completed relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2012.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the quarter ended June 30, 2012.

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DYNEGY INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

See Note 8—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. As a result of the DH Chapter 11 Cases, we deconsolidated our investment in DH and its wholly owned subsidiaries as of November 7, 2011 and for the Coal segment as of June 5, 2012. In addition to those proceedings described in Note 8, the following is a description of proceedings related to DH and its wholly owned subsidiaries.

Consent Decree. In 2005, we settled a lawsuit filed by the EPA and the United States Department of Justice in the U.S. District Court for the Southern District of Illinois that alleged violations of the Clean Air Act and related federal and Illinois regulations concerning certain maintenance, repair and replacement activities at our Baldwin generating station. A consent decree (the “Consent Decree”) was finalized in July 2005. Among other provisions of the Consent Decree, we are required to not operate certain of our power generating facilities after specified dates unless certain emission control equipment is installed. As of June 30, 2012, only Baldwin Unit 2 has material Consent Decree work yet to be performed, which is scheduled to be completed by the end of 2012. We have spent approximately $902 million through June 30, 2012 related to these Consent Decree projects.

Vermilion and Baldwin Groundwater. We have implemented hydrogeologic investigations for the CCR surface impoundment at our Baldwin facility and for two CCR surface impoundments at our Vermilion facility in response to a request by the Illinois EPA. Groundwater monitoring results indicate that these CCR surface impoundments impact onsite groundwater at these sites. In July 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at the Baldwin and Vermilion facilities.

At the request of the Illinois EPA, in late 2011 we initiated an investigation at the Baldwin facility to determine if the facility’s CCR surface impoundment impacts offsite groundwater. Results of the offsite groundwater quality investigation at Baldwin, as submitted to the Illinois EPA on April 24, 2012, indicate two localized areas where Class I groundwater standards were exceeded. If these offsite groundwater results are ultimately attributed to the Baldwin CCR surface impoundment and remediation measures are necessary in the future, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs of corrective action that ultimately may be required at Baldwin.

On April 2, 2012, we submitted to the Illinois EPA proposed corrective action plans for two of the CCR surface impoundments at the Vermilion facility. The proposed corrective action plans reflect the results of a hydrogeologic investigation, which indicate that the facility’s old east and north CCR impoundments impact groundwater quality onsite and that such groundwater migrates offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River. The proposed corrective action plans include groundwater monitoring and recommend closure of both CCR impoundments, including installation of a geosynthetic cover. In addition, we submitted an application to the Illinois EPA to establish a groundwater management zone while impacts from the facility are mitigated. The preliminary estimated cost of the recommended closure alternative for both impoundments, including post-closure care, is approximately $14 million. As such, in the first quarter 2012 we increased our asset retirement obligation by approximately $8 million. The Vermilion facility also has a third CCR surface impoundment, the new east impoundment that is lined and is not known to impact groundwater. Although not part of the proposed corrective action plans, if we decide to close the new east impoundment by removing its CCR contents concurrent with the recommended closure alternative for the old east and north impoundments, the preliminary total estimated closure cost for all three impoundments would be approximately $16 million. If the proposed corrective action plans are timely approved by the Illinois EPA, detailed proposed closure plans would be submitted to the Illinois EPA by year-end 2012 for approval.

Item 1A—RISK FACTORS

In addition to the risk factors below, please read Item 1A—Risk Factors, of our Form 10-K and Form 10-Q for the quarter ended March 31, 2012 for factors, risks and uncertainties that may affect future results. For the avoidance of doubt, references to the “Plan” in this Item 1A shall refer exclusively to the plan of reorganization of Dynegy and DH, as amended, to

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contain the terms and conditions agreed upon by the parties to the Plan Support Agreement and as required by the Bankruptcy Court. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

There are risks associated with our common stock trading on the OTC Market.

On July 6, 2012, our common stock ceased trading on the New York Stock Exchange. Our common stock is currently trading under the symbol “DYNIQ” in the over-the-counter market (“OTC Market”). Stocks trading in the OTC Market generally have substantially less liquidity; consequently, it can be much more difficult for stockholders and broker/dealers to purchase and sell our shares in an orderly manner or at all. In addition, the trading price of our common stock may change quickly, and brokers may not be able to execute trades as quickly as they previously could when our common stock was listed on an exchange. Currently, we are not actively seeking to become listed on any exchange. There can be no assurance that our common stock will again be listed on an exchange.

We may not be able to successfully implement the restructuring set forth in the Agreements and the Plan.

The consummation of the Plan is contingent upon a number of factors which include, among other things, that:

·	the Plan may not be confirmed by the Bankruptcy Court or federal and state regulators may not approve certain elements of the Plan; and
·	the Agreements may be terminated.

The Settlement Agreement and the obligations of the parties thereunder may be terminated by: (i) mutual written agreement of Dynegy, DH, a majority of the Consenting Senior Noteholders, a majority of the Consenting Lease Certificate Holders, a majority of the Consenting Sub Debt Holders, and RCM or (ii) by any of Dynegy, DH, a majority of the Consenting Senior Noteholders or a majority of the Consenting Lease Certificate Holders upon the occurrence of certain events or the failure to meet certain milestone dates in the restructuring process. For a discussion of the termination events under the Plan Support Agreement, please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement.

If we are unable to implement the restructuring contemplated by the Agreements and the Plan, it is unclear whether we will be able to reorganize our and the Debtor Entities’ businesses and what, if any, distribution holders of claims against, or equity interests in, the Debtor Entities ultimately would receive with respect to their claims or equity interests.

We may not be able to secure confirmation of or consummate the Plan.

The Plan requires the acceptance of a requisite number of holders of claims that are entitled to vote on the Plan, and the approval of the Bankruptcy Court. Furthermore, confirmation and consummation of the Plan are subject to the satisfaction of certain conditions precedent. There can be no assurance that such acceptance and approval will be obtained, or that such conditions will be satisfied, and therefore, that the Plan will be confirmed and consummated.

Furthermore, although we believe that the Plan will be confirmed and that the Plan will become effective reasonably soon after the date on which the Bankruptcy Court’s order confirming the Plan is entered on the Bankruptcy Court’s docket, there can be no assurance as to the timing or that the Plan will become effective. If the Plan is not confirmed, does not become effective or if a protracted reorganization or liquidation were to occur, there is a substantial risk that holders of claims would receive less than they would otherwise receive under the Plan and Dynegy may continue to face ongoing litigation at significant costs. Additionally, if the Plan is not confirmed, or is confirmed but does not become effective, Dynegy will retain the Administrative Claim in the DH Chapter 11 Cases, but under the Settlement Agreement, the Administrative Claim will be subject to a valuation through arbitration, with an uncertain outcome.

The Plan contemplates the Merger and although the Bankruptcy Court has already authorized DH and Dynegy to enter into the Merger pursuant to the terms and conditions set forth in the Bankruptcy Court’s July 10, 2012 order authorizing the Merger, the Plan also requires that the Merger and all material documents, instruments and agreements necessary to implement the Merger, be in form and substance reasonably acceptable to Dynegy, DH, the majority of the Consenting Senior Noteholders, the Lease Trustee and the Creditors’ Committee. If the Merger is not consummated for any reason and DH decides to prosecute a standalone plan of reorganization on similar terms to those set forth in the Plan, including in particular the extinguishment of all equity interests in DH and, as a result, DH and its subsidiaries cease to be subsidiaries of Dynegy, there could be an adverse impact on each of DH and Dynegy. Specifically, such an occurrence may constitute a “Change of Control” as such term is defined in the DMG Credit Agreement and the DPC Credit Agreement (together, the “New Credit Facilities”). A Change of Control is an “Event of Default” under the New Credit Facilities and, as a result, amounts outstanding under the New Credit Facilities may be declared immediately due and payable. This could have a negative impact on DH’s financial condition and future operations if DH were unable to timely obtain waivers under or refinance the New Credit Facilities on reasonable terms, and recoveries to holders of claims against DH may be negatively impacted. Such negative impact may not be fully offset by any reduction in the amount of the Administrative Claim pursuant to the terms of the Settlement Agreement and the fact that DH would not be liable for any liabilities of Dynegy. In addition, any assets currently held by Dynegy,

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including any cash, may remain assets of Dynegy only, and therefore would not inure to the benefit of DH. This may also have a negative impact on Dynegy’s financial condition and future operations, as well as on recoveries to holders of claims against and equity interests in Dynegy.

If the Plan is confirmed but the Effective Date does not occur, it may become necessary to amend the Plan to provide alternative treatment of claims and equity interests. There can be no assurance that any such alternative treatment would be on terms as favorable to the holders of claims and equity interests as the treatment provided under the Plan. If any modifications to the Plan are material, it would be necessary to resolicit votes from holders of claims and equity interests adversely affected by the modifications with respect to such amended Plan.

The Plan may not be confirmed by the Bankruptcy Court and the value of the Administrative Claim and equity interest in DH is therefore uncertain.

The Settlement Agreement and the Plan Support Agreement contemplate a plan in which, if confirmed by the Bankruptcy Court, Dynegy and DH are merged and the holders of equity interests in the Surviving Entity (which may be the current stockholders of Dynegy) will not receive any distribution or retain any interest in or property on account of such holders’ equity interests. Consequently, in such a circumstance the holders of Dynegy Common Stock would not be entitled to any recovery under the Plan, other than a distribution of recoveries on account of the Administrative Claim. The Plan, however, may not be confirmed. If the Plan is not confirmed , to the extent not otherwise resolved by the parties to the Settlement Agreement, the amount of the Administrative Claim will be subject to arbitration proceedings. The Settlement Agreement provides that the amount of the Administrative Claim is to be equal to the value of the equity consideration that would have been distributed on account of the Administrative Claim if the Plan had been confirmed but, in any event, not less than $70 million nor more than $130 million in cash. The potential outcome of such an arbitration proceeding is uncertain and there is no assurance that the Administrative Claim would be valued at any specific amount within the prescribed range. If, however, the Plan is not confirmed because (1) Dynegy breached the Plan Support Agreement or the Plan Support Agreement is terminated under certain circumstances or (2) Dynegy and DH are unable to be combined other than as a result of any action or any inaction on the part of DH, then (x) the determination of the amount of the Administrative Claim shall take into account (and shall be reduced in respect of) any value lost by DH as a result of the failure of Dynegy and DH to be combined and (y) the Administrative Claim (as reduced) may be satisfied with plan securities or other non-cash consideration of equivalent value as determined by the Bankruptcy Court in connection with confirmation of any alternative DH plan of reorganization. Additionally, if the Plan is not confirmed, an alternative plan of reorganization for DH and Dynegy would be necessary and it is unclear how Dynegy’s equity ownership of DH would be affected. In light of the transfer of Coal Holdco to DH pursuant to the Settlement Agreement, the uncertain value of the Administrative Claim is exacerbated by the uncertain treatment of Dynegy’s equity interest in DH in any plan of reorganization for DH other than the Plan.

The composition of our board may change.

Pursuant to the Plan, as of the Effective Date, the board will be the persons identified on an exhibit to the Plan. The board of directors of Dynegy (the “Board”) shall be selected in a manner to be agreed to among the Majority Consenting Senior Noteholders, the Lease Trustee and the Creditors’ Committee. The term of any current members of the board of directors of Dynegy not identified as members of the Board shall expire upon the Effective Date. The term of any current members of the board of managers of DH shall expire on the Merger Effective Time. The current directors of Dynegy and DH are eligible to be, but there shall be no obligation that they be, selected for the Board pursuant to sections 1123(a)(7) and 1129(a)(5) of the Bankruptcy Code. Currently, the identities of the members of the Board have not been identified. While the current directors of Dynegy and DH are eligible to be selected for the Board, the composition of such board is expected to change.

Dynegy’s ability to use its federal net operating losses or alternative minimum tax credits to offset its future taxable income may be further limited under sections 382 and 383 of the Internal Revenue Code and as a result of Dynegy’s having recognized certain cancellation of indebtedness income.

Dynegy’s ability to use previously incurred federal net operating loss carryforwards (“NOLs”) and alternative minimum tax credit carryforwards (“AMT Credits”), which have a maximum balance of $1,419 million and $271 million, respectively, at December 31, 2011, will likely be limited or modified on the Effective Date as a result of section 382 of the Internal Revenue Code and at the close of Dynegy’s taxable year as a result of cancellation of indebtedness income (“COD Income”). In addition, Dynegy had an Ownership Change (as defined below) in the second quarter of 2012 and thus its ability to utilize its federal NOLs and AMT Credits that existed at the time of the Ownership Change will be significantly limited (in an amount yet to be determined).

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Under Internal Revenue Code sections 382 and 383, if a corporation or a consolidated group of corporations with NOLs (a “loss corporation”) undergoes an “ownership change,” the loss corporation’s use of its pre-change NOLs, AMT Credits, and certain other tax attributes generally will be subject to an annual limitation in the post-change period. In general, an ownership change occurs if the percentage of the value of the loss corporation’s stock owned by one or more direct or indirect “five percent shareholders” increases by more than fifty percentage points over the lowest percentage of value owned by the five percent shareholders at any time during the applicable testing period (an “Ownership Change”).

Notwithstanding that the use of the NOLs and AMT Credits existing at the time of this Ownership Change will be limited, such tax attributes continue to exist after such Ownership Change and, as a result of COD Income resulting on the Effective Date, such tax attributes held at DH will be reduced or eliminated prior to the reduction of tax attributes held by entities other than DH or produced after the Ownership Change. Because the use of these tax attributes existing at the time of the Ownership Change has been limited and these tax attributes are expected to be reduced or eliminated as a result of COD Income, the impact of a further Ownership Change on the Effective Date should not have a significant impact on Dynegy’s use of these tax attributes. Dynegy produced additional NOLs after the Ownership Change in the second quarter of 2012 and prior to the Effective Date. The use of these additional NOLs will not be limited by the Ownership Change in the second quarter of 2012, but may be limited by a further Ownership Change on the Effective Date.

DPC and DMG receive significant services from certain of Dynegy’s other subsidiaries and the loss of such services, as a result of any of such subsidiaries becoming the subject of a voluntary or involuntary bankruptcy case or otherwise, may have a material adverse impact on the Gas and Coal segments’ business, financial condition, and results of operations.

The Gas and Coal segments receive significant services from certain of Dynegy’s subsidiaries, including, among others, cash management and energy management services. If the provision of these services were to be delayed, interrupted or otherwise halted for any reason, including if any of Dynegy’s subsidiaries that provide such services become the subject of a voluntary or involuntary bankruptcy case, this may have a material adverse impact on the Gas and Coal segments’ businesses, financial condition, and results of operations. A replacement supplier of these services may not be found within a reasonable time (or at all) and/or on economic terms that are commercially reasonable.

Item 2—UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

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	2,741	$	.55	—	N/A
May 1-31	—	$	—	—	N/A
June 1-30	1,024	$	.58	—	N/A

Total	3,765	$	.56	—	N/A

These were the only purchases of equity securities made by us during the three months ended June 30, 2012. We do not have a stock repurchase program.

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Item 6—EXHIBITS

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

Exhibit Number		Description
10.1		Amended and Restated Settlement Agreement, dated May 30, 2012, among Dynegy Inc., Dynegy Holdings, LLC and certain of its subsidiaries and certain beneficial owners of a portion of Dynegy Holdings, LLC’s outstanding senior notes (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on May 31, 2012, File No. 001-33443).

10.2		Contribution and Assignment Agreement by and between Dynegy Inc. and Dynegy Holdings, LLC, dated June 5, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on June 11, 2012, File No. 001-33443).

10.3		Assignment Agreement by and between Dynegy Inc. and Dynegy Operating Company, dated July 5, 2012 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. on July 10, 2012, File No. 001-33443).

10.4		Third Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC proposed by Dynegy Holdings, LLC and Dynegy Inc., dated June 8, 2012 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on June 11, 2012, File No. 001-33443).

10.5		Disclosure Statement related to the Third Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC proposed by Dynegy Holdings, LLC and Dynegy Inc., dated June 8, 2012 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on June 11, 2012, File No. 001-33443).

10.6		Modified Third Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC proposed by Dynegy Holdings, LLC and Dynegy Inc., dated June 18, 2012 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on June 19, 2012, File No. 001-33443).

10.7		Disclosure Statement related to the Modified Third Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC proposed by Dynegy Holdings, LLC and Dynegy Inc., dated June 18, 2012 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on June 19, 2012, File No. 001-33443).

10.8		Joint Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC and Dynegy Inc. proposed by Dynegy Holdings, LLC and Dynegy Inc., dated July 12, 2012 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on July 13, 2012, File No. 001-33443).

10.9		Disclosure Statement related to the Joint Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC and Dynegy Inc. proposed by Dynegy Holdings, LLC and Dynegy Inc., dated July 12, 2012 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on July 13, 2012, File No. 001-33443).

10.10		First Amendment to the Amended Plan Support Agreement, dated July 31, 2012, among Dynegy Inc., Dynegy Holdings, LLC and certain of its subsidiaries and certain beneficial owners of a portion of Dynegy Holdings, LLC’s outstanding senior notes (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K for Dynegy Inc. and Dynegy Holdings, LLC filed on August 1, 2012, File No. 001-33443).

**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**31.2		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.

†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.

†32.2		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.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema Document

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

**101.LAB		XBRL Taxonomy Extension Label Linkbase Document

**101.PRE		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.

SIGNATURE

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 3, 2012	By:	/s/ CLINT C. FREELAND
			Clint C. Freeland Executive Vice President and Chief Financial Officer