UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý      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: 002-29311

DYNEGY HOLDINGS, LLC

(Exact name of registrant as specified in its charter)

State of Incorporation	I.R.S. Employer Identification No.
	94-3248415
Delaware
601 Travis Street, 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 o  No ý

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 o No ý

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 ¨
Non-accelerated filer ý	Smaller reporting company o
(Do not check if a smaller reporting company)

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

All of the registrant’s outstanding membership interests are owned directly by 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		1
Condensed Consolidated Statements of Operations:
For the three and six months ended June 30, 2012 and 2011		3
Condensed Consolidated Statements of Comprehensive Loss:
For the three and six months ended June 30, 2012 and 2011		4
Condensed Consolidated Statements of Cash Flows:
For the six months ended June 30, 2012 and 2011		5
Notes to Condensed Consolidated Financial Statements		6
Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	41
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	64
Item 4.	CONTROLS AND PROCEDURES	65
PART II. OTHER INFORMATION
Item 1.	LEGAL PROCEEDINGS	67
Item 1A.	RISK FACTORS	67
Item 3.	DEFAULTS UPON SENIOR SECURITIES	67
Item 6.	EXHIBITS	68

i

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
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
DH	Dynegy Holdings, LLC (formerly known as Dynegy Holdings Inc.)
DMSLP	Dynegy Midstream Services L.P.
EBITDA	Earnings before interest, taxes, depreciation and amortization
EGU	Electric generating unit
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
ISO	Independent System Operator
ISO-NE	Independent System Operator New England
MACT	Maximum achievable control technology
MGGA	Midwest Greenhouse Gas Accord
MGGRP	Midwestern Greenhouse Gas Reduction Program
MISO	Midwest Independent Transmission System Operator, Inc.
MMBtu	One million British thermal units
MW	Megawatts
MWh	Megawatt hour
NOL	Net operating loss
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NRG	NRG Energy, Inc.
NSPS	New Source Performance Standard

ii

NYISO	New York Independent System Operator
NYSDEC	New York State Department of Environmental Conservation
OAL	Office of Administrative Law
OTC	Over-the-counter
PJM	PJM Interconnection, LLC
PPEA	Plum Point Energy Associates, LLC
PPEA Holding	Plum Point Energy Associates Holding Company, LLC
PSD	Prevention of significant deterioration
RACT	Reasonably available control technology
RCRA	Resource Conservation and Recovery Act
RFO	Request for offer
RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must Run
SEC	U.S. Securities and Exchange Commission
SIP	State Implementation Plan
SO2	Sulfur dioxide
SPDES	State Pollutant Discharge Elimination System
VaR	Value at Risk
VIE	Variable Interest Entity
WCI	Western Climate Initiative

iii

Item 1—FINANCIAL STATEMENTS

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)

	June 30, 2012			December 31, 2011
ASSETS
Current Assets
Cash and cash equivalents	$	656		$	398
Restricted cash and investments	259			159
Accounts receivable, net of allowance for doubtful accounts of $12 and $12, respectively	164			147
Accounts receivable, affiliates	—			26
Interest receivable, affiliates	—			8
Inventory	132			65
Assets from risk-management activities	1,271			2,615
Assets from risk-management activities, affiliates	—			2
Broker margin account	43			23
Prepayments and other current assets	377			126
Total Current Assets	2,902			3,569
Property, Plant and Equipment	4,416			3,911
Accumulated depreciation	(1,126		)	(1,090		)
Property, Plant and Equipment, Net	3,290			2,821
Other Assets
Restricted cash and investments	339			455
Assets from risk-management activities	17			26
Intangible assets	149			92
Undertaking receivable, affiliate	—			1,250
Deferred income taxes	50			44
Other long-term assets	52			54
Total Assets	$	6,799		$	8,311

See the notes to condensed consolidated financial statements.

1

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)

	June 30, 2012			December 31, 2011
LIABILITIES AND MEMBER'S EQUITY (DEFICIT)
Current Liabilities
Accounts payable	$	92		$	80
Accounts payable, affiliates	1			47
Accrued interest	27			1
Deferred income taxes	50			50
Accrued liabilities and other current liabilities	119			64
Liabilities from risk-management activities	1,367			2,798
Liabilities from risk-management activities, affiliates	—			4
Notes payable and current portion of long-term debt	16			7
Total Current Liabilities	1,672			3,051
Liabilities subject to compromise	4,315			4,012
Long-term debt	1,665			1,069
Other Liabilities
Liabilities from risk-management activities	44			20
Liabilities from risk-management activities, affiliates	—			3
Other long-term liabilities	267			124
Total Liabilities	7,963			8,279
Commitments and Contingencies (Note 11)
Member's Equity (Deficit)	(1,164		)	32
Total Liabilities and Member's Equity (Deficit)	$	6,799		$	8,311

See the notes to condensed consolidated financial statements.

2

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues	$	290		$	326		$	565		$	831
Cost of sales	(179		)	(225		)	(365		)	(503		)
Gross margin, exclusive of depreciation shown separately below	111			101			200			328
Operating and maintenance expense, exclusive of depreciation shown separately below	(63		)	(106		)	(112		)	(216		)
Depreciation and amortization expense	(43		)	(75		)	(65		)	(201		)
Impairment and other charges	—			(1		)	—			(1		)
General and administrative expenses	(17		)	(23		)	(37		)	(64		)
Operating loss	(12		)	(104		)	(14		)	(154		)
Bankruptcy reorganization charges	(22		)	—			(269		)	—
Interest expense	(42		)	(89		)	(73		)	(178		)
Impairment of Undertaking receivable, affiliate	—			—			(832		)	—
Other income and expense, net	6			3			30			4
Loss before income taxes	(70		)	(190		)	(1,158		)	(328		)
Income tax benefit (Note 14)	1			75			7			133
Net loss	$	(69	)	$	(115	)	$	(1,151	)	$	(195	)

See the notes to condensed consolidated financial statements.

3

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)

	Three Months Ended June 30,
	2012			2011
Net loss	$	(69	)	$	(115	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of zero and $1)	—			1
Total Other comprehensive income, net of tax	—			1
Comprehensive loss	$	(69	)	$	(114	)

	Six Months Ended June 30,
	2012			2011
Net loss	$	(1,151	)	$	(195	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of zero and $1)	(1		)	2
Total Other comprehensive income, net of tax	(1		)	2
Comprehensive loss	$	(1,152	)	$	(193	)

See the notes to condensed consolidated financial statements.

4

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(1,151	)	$	(195	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization	69			209
Bankruptcy reorganization charges	247			—
Impairment and other charges	—			1
Impairment of Undertaking receivable, affiliate	832			—
Risk-management activities	(49		)	127
Risk-management activities, affiliate	(1		)	—
Deferred income taxes	(7		)	(132		)
Other	35			22
Changes in working capital:
Accounts receivable	(14		)	60
Inventory	1			(4		)
Broker margin account	(12		)	(92		)
Prepayments and other assets	(73		)	1
Affiliate transactions	6			—
Accounts payable and accrued liabilities	34			(54		)
Changes in non-current assets	(10		)	(33		)
Changes in non-current liabilities	(14		)	4
Net cash used in operating activities	(107		)	(86		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(37		)	(128		)
Maturities of short-term investments	—			201
Purchases of short-term investments	—			(235		)
Decrease (increase) in restricted cash and investments	134			53
DMG acquisition	256			—
Payments received for Undertaking, receivable affiliate	16			—
Other investing	3			10
Net cash provided by (used in) investing activities	372			(99		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs of $1	—			399
Repayments of borrowings	(7		)	(113		)
Debt extinguishment costs	—			—
Net cash provided by (used in) financing activities	(7		)	286
Net increase in cash and cash equivalents	258			101
Cash and cash equivalents, beginning of period	398			253
Cash and cash equivalents, end of period	$	656		$	354
Other non-cash investing activity:
Non-cash capital expenditures	$	1		$	(7	)
Other non-cash financing activity:
Deferred financing fees	$	—		$	(4	)

See the notes to condensed consolidated financial statements.

5

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended June 30, 2012 and 2011

EXPLANATORY NOTE

As explained herein, on November 7, 2011, we and four of our wholly owned subsidiaries, Dynegy Northeast Generation, Inc. (“Dynegy Northeast Generation”), Hudson Power, L.L.C. (“Hudson”), Dynegy Danskammer, L.L.C. (“Danskammer”) and Dynegy Roseton, L.L.C. (“Roseton”, and together with us, DNE, Hudson and Danskammer, 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"). Since filing the DH Chapter 11 Cases, we have not filed our quarterly reports on Form 10-Q or our annual report on Form 10-K with the SEC. On the filing date hereof, we are simultaneously filing our quarterly report for the third quarter of 2011, our annual report for the year ended December 31, 2011, and our quarterly reports for the first and second quarters of 2012. In each of these reports, in a note to the financial statements, we have disclosed recent material developments with respect to our business, including with respect to the DH Chapter 11 Cases and other legal proceedings, in each case, as of the date of the filing of such reports. In this report, please see Note 3—Chapter 11 Cases. Further, additional disclosures regarding such developments can be found throughout each of these reports.

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 "DH," “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Holdings, LLC and its direct and indirect subsidiaries, unless the context clearly indicates otherwise. The term “Dynegy” refers to our parent company, Dynegy Inc., unless the context clearly indicates otherwise. The year-end condensed consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America.  These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2011, filed on September 17, 2012, which we refer to as our “Form 10-K”.

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.

The Gas segment includes Dynegy Power, LLC ("DPC"), which owns, directly and indirectly, substantially all of our wholly-owned natural gas-fired power generation facilities. DPC, a bankruptcy remote entity, and its direct and indirect subsidiaries are organized into a ring-fenced group for the benefit of the creditors of DPC.

The Coal segment includes Dynegy Midwest Generation, LLC ("DMG"), which owns directly and indirectly, substantially all of the coal-fired power generation facilities. DMG, a bankruptcy remote entity, and its direct and indirect subsidiaries are organized into a ring-fenced group for the benefit of the creditors of DMG. On September 1, 2011, we sold 100% of the outstanding membership interests of Dynegy Coal Holdco ("Coal Holdco") to Dynegy (the "DMG Transfer"). On June 5, 2012, we reacquired the Coal segment (including DMG) from Dynegy (the"DMG Acquisition"). Therefore, the results of our Coal segment are only included in our consolidated results for the period from June 5, 2012 through June 30, 2012. Please read Note 4—DMG Acquisition for further discussion.

Chapter 11 Filing by Certain Subsidiaries. On November 7, 2011, the DH Debtor Entities filed the DH Chapter 11 Cases. The DH Chapter 11 Cases were assigned to the Honorable Cecelia G. Morris and are being jointly administered for

6

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

procedural purposes only. 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. Only the DH Debtor Entities and our parent Dynegy filed voluntary petitions for relief under the Bankruptcy Code, and none of our other direct or indirect subsidiaries are debtors thereunder. Consequently, they continue to operate their business in the ordinary course. 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, the Settlement Agreement and the Plan Support Agreement (each as defined and described in Note 3—Chapter 11 Cases), including the planned merger of Dynegy and DH (the “Merger”).

We are a wholly-owned subsidiary of Dynegy and we have historically been consolidated by Dynegy in its consolidated financial statements. However, as a result of the DH Chapter 11 Cases, on November 7, 2011, Dynegy deconsolidated its investment in us and, instead, began accounting for its investment in us as an equity method investment.

Going Concern

Our accompanying unaudited condensed consolidated financial statements were prepared assuming that we would continue as a going concern, and therefore contemplate realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these unaudited condensed consolidated financial statements. However, continued low power prices over the past several years have had a significant adverse impact on our business and continue to negatively impact our projected future liquidity.

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. Only the DH Debtor Entities and our parent Dynegy filed voluntary petitions for relief, and none of our other direct or indirect subsidiaries are debtors under Chapter 11 of the Bankruptcy Code. Please read Note 3—Chapter 11 Cases for further information.

Our ability to continue as a going concern is dependent on many factors, including, among other things, the generation by DPC and DMG of sufficient positive operating results to enable DPC and DMG to make certain restricted distributions to their parents, the terms and conditions of an approved plan of reorganization that allows us to emerge from bankruptcy (as described in Note 3—Chapter 11 Cases), execution of any further restructuring strategies, and the successful execution of the company-wide cost reduction initiatives that are ongoing. The accompanying unaudited condensed consolidated financial statements do not include any adjustments that might be necessary if the Settlement Agreement and Plan of Reorganization are not successful.

7

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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 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 our fair value disclosures.

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.

Accounting Principles Not Yet Adopted

Disclosures about Offsetting Assets and Liabilities.  In December 2011, the FASB issued ASU 2011-11—Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities.  This statement requires entities to disclose both gross and net information about instruments and transactions eligible for offsetting in the statement of financial position, as well as instruments and transactions subject to an agreement similar to a master netting arrangement.  Implementation of this guidance would affect disclosures around financial derivative contracts, however would have no impact on the statement of financial position or the statement of operations.  This guidance is effective for the quarter ending March 31, 2013

Note 3—Chapter 11 Cases

On November 7, 2011, the DH Debtor Entities commenced the DH Chapter 11 Cases.  On July 6, 2012, our parent, 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”).

Only the Debtor Entities sought relief under the Bankruptcy Code, and none of our other direct or indirect subsidiaries are debtors thereunder. Coal Holdco and Dynegy GasCo Holdings, LLC and their indirect, wholly-owned subsidiaries (including DMG and 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 continue without interruption. The commencement of the Chapter 11 Cases did not constitute an event of default under either the DMG Credit Agreement or the

8

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

DPC Credit Agreement.

Lease Rejection. 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 Resource 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 the 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 rejection damages claim of RCM was stipulated and allowed by the Bankruptcy Court in the amount of $110 million. The applicable DH Debtor Entities have operated and plan to continue operating the 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 Danskammer, 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 Roseton and 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 Danskammer, Roseton, and DH.

Danskammer, Roseton and DH contested the claims made in the Adversary Proceeding, including the attempt to re-characterize 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 "Reorganization"), (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 (as defined and discussed below). 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 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

9

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

or arising from disputes with respect to the matters investigated by the Examiner, including, among other things, the Reorganization and including, without limitation, any claims that have been or could have been brought in connection with the DMG Transfer, the related Undertaking Agreement or the DH note.

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 our 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 our 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, 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, DH and Dynegy 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, 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 and discussed below). 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 entered into in connection with the filing of the DH Chapter 11 Cases, and 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 contributed and assigned to us all of its right, title, and interest in and to one hundred percent (100%) of the issued and outstanding membership interests of Coal Holdco (the "DMG Acquisition"). In full consideration for such contribution and in accordance with the terms of the Settlement Agreement and the Approval Order, (i) Dynegy received an allowed administrative claim pursuant to sections 503(b) and 507(a) of the Bankruptcy Code in an unliquidated amount against us 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, 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 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, and (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

10

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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, and (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 such documents 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 our 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, and (b) warrants with a 5-year term 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.

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.

On August 27, 2012, the results of the vote on the Plan were filed with the Bankruptcy Court, with creditors holding

11

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

over $3.5 billion of claims, or more than 99% of the value of the claims that voted, approving the Plan (this reflects approximately 87% of the number of creditors who voted). Further, Dynegy announced that the Consenting Senior Noteholders, the Lease Trustee and the Creditors' Committee selected the initial directors to be appointed to Dynegy's Board. At a hearing on September 5, 2012, the Bankruptcy Court found that DH and Dynegy had met all Plan confirmation requirements under the Bankruptcy Code. Accordingly, on September 10, 2012, the Bankruptcy Court entered its order confirming the Plan (the "Confirmation Order"). The occurrence of the Effective Date of the Plan and the emergence of the Surviving Entity from bankruptcy remain subject to certain conditions precedent set forth in Section 11.2 of the Plan, including, among other things, that no “Non-Conforming Plan Assertion” (as defined in the Amended Plan Support Agreement) has been made, or the Bankruptcy Court has ruled on such Non-Conforming Plan Assertion and determined that the Plan is a “Conforming Plan” (as defined in the Amended Plan Support Agreement). As mentioned above, the Plan addressed claims against and interests in Dynegy and DH only and did not address claims against and interests in the other DH Debtor Entities. The remaining DH Debtor Entities, with the cooperation of the PSEG Entities, will use commercially reasonable efforts to sell the Facilities with the proceeds of any sale to pay transaction expenses and to be distributed as set forth in the Settlement Agreement and Amended Plan Support Agreement.

Financial Obligations.  The direct financial obligations of the DH Debtor Entities and obligations under their off-balance sheet arrangements, and the approximate principal amount of debt currently outstanding thereunder, include the following:

• The following outstanding unsecured notes and debentures issued by us: (i) 8.75 percent senior unsecured notes due February 15, 2012; (ii) 7.5 percent senior unsecured notes due June 1, 2015; (iii) 8.375 percent senior unsecured notes due May 1, 2016; (iv) 7.75 percent senior unsecured notes due June 1, 2019; (v) 7.125 percent senior debentures due May 15, 2018; and (vi) 7.625 percent senior debentures due October 15, 2026 (collectively, the “Old Notes”), issued under the Indenture dated September 26, 1996, as amended and restated as of March 14, 2001, and under the First through Sixth Supplemental Indentures thereto (the "Old Notes Indenture"), between us and Wilmington Trust Company (as successor to JP Morgan Chase Bank, N .A., successor to Bank One Trust Company, National Association), as trustee, in the outstanding aggregate principal amount of approximately $3,370 million;

• Our Series B 8.316 percent Subordinated Capital Income Securities issued under the Indenture dated May 28, 1997, between NGC Corporation (a predecessor of ours) and the First National Bank of Chicago, as trustee, as amended and restated, in the outstanding aggregate principal amount of $200 million (the "Subordinated Capital Income Securities");

• Our approximately $26 million cash collateralized letter of credit facility, which is collateralized by $27 million in restricted cash; and

• The sale-leaseback arrangements for the Roseton and Danskammer power generation facilities under which the rent payments paid by each of them are assigned to an indenture trustee for the respective facility.  The indenture trustee then pays a portion of those payments to each of two pass-through trusts, and such pass-through trusts pay these amounts to holders of certificates in the pass-through trusts.  The current total outstanding principal of the certificates is approximately $550 million. 

Upon the commencement of the DH Chapter 11 Cases, we reclassified our senior notes and debentures, including the Subordinated Capital Income Securities reflected as Liabilities subject to compromise on our unaudited condensed consolidated balance sheet. Please read Note 12 - Liabilities subject to Compromise for further discussion.

Note 4—DMG Acquisition

On June 5, 2012, pursuant to the Settlement Agreement, we completed the DMG Acquisition. We accounted for the DMG Acquisition as a business combination, as although we are a wholly-owned subsidiary of Dynegy, we are not controlled by Dynegy as a result of the DH Chapter 11 Cases. Accordingly, assets acquired and liabilities assumed were recognized at their fair value as of the acquisition date.

12

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

The purchase price was approximately $466 million which consists of (i) approximately $402 million for the fair value of the Undertaking receivable, affiliate that was extinguished in connection with the transaction and (ii) approximately $64 million for the fair value of the Administrative Claim issued to Dynegy.

The following table summarizes the preliminary fair values of the assets acquired and liabilities assumed at the date of acquisition (in millions):

Cash	$	256
Restricted cash (including $75 million current)	117
Accounts receivable	3
Inventory	69
Assets from risk management activities (including $84 million current)	85
Prepaids and other current assets	46
Property, plant and equipment	514
Intangible assets (including $162 million current)	257
Total assets acquired	1,347
Current liabilities and accrued liabilities	(60		)
Liabilities from risk management activities (including $66 million current)	(76		)
Long-term debt (including $9 million current)	(610		)
Asset retirement obligations	(53		)
Unfavorable coal contract (including $15 million current)	(38		)
Pension liabilities	(44		)
Total liabilities assumed	(881		)
Net assets acquired	$	466

Pro Forma Results.

Revenue and net loss attributable to the DMG Acquisition is included in our consolidated condensed statements of income since the date of the acquisition of June 5, 2012. For the six months ended June 30, 2012, the DMG Acquisition contributed approximately $40 million to our revenue and increased our net loss by approximately $20 million.

The unaudited pro forma financial results for the six months ended June 30, 2012 show the effect of the DMG Acquisition as if the acquisition had occurred as of January 1, 2012. We did not include pro forma financial results for the six months ended June 30, 2011 as DMG is included in our consolidated results for that period. DH completed the DMG Transfer effective September 1, 2011. The pro forma financial results presented below do not include any anticipated synergies or other expected benefits of the acquisition. This is presented for informational purposes only and is not indicative of future operations or results that would have been achieved had the acquisitions been completed as of January 1, 2012.

	Six months ended June 30,
	2012
	(in millions)
Revenue	$	793
Net loss	$	(408	)

Note 5—Condensed Combined Financial Statements of the Debtor Entities

Condensed combined financial statements of the Debtor Entities are set forth below (in millions):

13

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Condensed Combined Balance Sheet

	June 30, 2012			December 31, 2011
Cash	$	53		$	33
Restricted cash and investments (including $27 million current)	27			27
Accounts receivable	7			8
Inventory	31			34
Investment in consolidated subsidiaries	4,712			5,568
Risk management, affiliate	3			—
Accrued interest from affiliate	—			8
Undertaking receivable from affiliate	—			1,250
Deferred income taxes	50			44
Other	8			14
Total assets	$	4,891		$	6,986
Current liabilities and accrued liabilities	$	34		$	10
Risk management, affiliate	2			—
Liabilities subject to compromise	4,315			4,012
Intercompany payable	1,514			1,587
Long-term debt to affiliates	12			1,262
Deferred income taxes	50			50
Other	128			33
Total liabilities	$	6,055		$	6,954
Total member's equity	$	(1,164	)	$	32
Total liabilities and member's equity	$	4,891		$	6,986

See Note 13—Liabilities Subject to Compromise for additional discussion of liabilities subject to compromise.

Condensed Combined Statement of Operations

	Three Months Ended June 30, 2012			Six Months Ended June 30, 2012
Revenues	$	19		$	26
Cost of sales	(8		)	(14		)
Operating expenses	(15		)	(30		)
General and administrative expenses	(2		)	(4		)
Operating loss	(6		)	(22		)
Bankruptcy reorganization charges	(22		)	(269		)
Equity losses	(1,310		)	(1,327		)
Interest expense, affiliate	(1		)	(1		)
Other income and expense, net	1,269			461
Income tax expense	1			7
Net loss	$	(69	)	$	(1,151	)

14

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Condensed Combined Statement of Cash Flows

	Six Months Ended June 30, 2012
Net cash provided by (used in):
Operating activities	$	20
Investing activities	—
Financing activities	—
Net increase in cash and cash equivalents	20
Cash and cash equivalents, beginning of period	33
Cash and cash equivalents, end of period	$	53

Basis of Presentation.    The condensed combined financial statements only include the financial statements of the Debtor Entities. Transactions and balances of receivables and payables among the Debtor Entities are eliminated in consolidation. However, the condensed combined balance sheet includes receivables from related parties and payables to related parties that are not Debtor Entities. Actual settlement of these related party receivables and payables is, by historical practice, made on a net basis.

Interest Expense.    The Debtor Entities have discontinued recording interest on unsecured or undersecured liabilities subject to compromise ("LSTC"). Contractual interest on LSTC not reflected in the condensed combined financial statements was approximately$70 million and $141 million for the three and six month periods ended June 30, 2012, respectively.

Bankruptcy Reorganization Charges.    Bankruptcy reorganization charges represent the direct and incremental costs of bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Bankruptcy reorganization charges, as shown in the condensed combined statement of operations above, consist of expense or income incurred or earned as a direct and incremental result of the bankruptcy filings. The table below lists the significant items within this category for the three and six months ended June 30, 2012.

	Three Months Ended June 30, 2012		Six Months Ended June 30, 2012
	(in millions)
Adjustments of estimated allowable claims:
DNE Leases (1)	$	—	$	395
Subordinated notes (1)	—		(161		)
Write-off of note payable, affiliate (2)	—		(10		)
Other	—		4
Total adjustments for estimated allowable claims	—		228
Change in value of Administrative Claim (3)	8		8
Professional fees (4)	14		33
Total Bankruptcy reorganization charges	$	22	$	269

_______________________________________________________________

(1) The estimated allowable claims related to the Facilities and the Subordinated Capital Income Securities were adjusted based on the terms of the Settlement Agreement. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

(2) It was determined that no claim related to a Note payable, affiliate would be made. Therefore, the estimated amount was reduced to zero.

(3) The Administrative Claim was issued on the effective date of the Settlement Agreement. Please read Note 7—Fair Value Measurements—Fair Value of Financial Instruments and Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

15

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

(4) Professional fees relate primarily to the fees of attorneys and consultants working directly on the Chapter 11 Cases.

Note 6—Risk Management Activities, Derivatives and Financial Instruments

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

Our commodity risk management strategy gives us the flexibility to sell energy and capacity through a combination of spot market sales and near-term contractual arrangements (generally over a rolling 1 to 3 year time frame).  Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term.  Increasing collateral requirements and our liquidity position could impact our ability to effectively employ our risk management strategy.

Many of our contractual arrangements are derivative instruments and must be accounted for at fair value 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 the delivery occurs.

Quantitative Disclosures Related to Financial Instruments and Derivatives

The following disclosures and tables present information concerning the impact of derivative instruments on our unaudited condensed consolidated balance sheets and statements of operations.  In the table below, commodity contracts primarily consist of derivative contracts related to our power generation business that we have not designated as accounting hedges that are entered into for purposes of economically hedging future fuel requirements and sales commitments and securing commodity prices. We elect not to designate any of our commodity instruments as accounting hedges.  As of June 30, 2012, our commodity derivatives were comprised of both purchases and sales of commodities.  As of June 30, 2012, we had net purchases and sales of commodity derivative contracts and notional interest swaps outstanding in the following quantities:

Contract Type	Hedge Designation	Quantity		Unit of Measure	Net Fair Value
		(in millions)			(in millions)
Commodity contracts:
Electric energy (1)	Not designated	(34	)	MWh	$	49
Natural gas (1)	Not designated	15		MMBtu	$	(140	)
Heat rate derivatives	Not designated	(3)/22		MWh/MMBtu	$	(8	)
Crude oil	Not designated	—		BBL	$	1
Interest rate contracts:
Interest rate swaps	Not designated	1,100		Dollars	$	(27	)
Interest rate caps	Not designated	1,400		Dollars	$	2

_______________________________________________________________

(1) Mainly comprised of swaps, options and physical forwards.

Derivatives on the Balance Sheet.  We execute a significant volume of transactions through futures clearing managers.  Our daily cash payments (receipts) to (from) our futures clearing managers consist of three parts: (i) fair value of open

16

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

positions (exclusive of options) (“Daily Cash Settlements”); (ii) initial margin requirements of open positions (“Initial Margin”); and (iii) fair value related to options (“Options”, and collectively with Daily Cash Settlements and Initial Margin, “Collateral”).  We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we do not elect to offset the fair value amounts recognized for the Daily Cash Settlements paid or received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.  As a result, our unaudited condensed consolidated balance sheets present derivative assets and liabilities, as well as related Collateral, as applicable, on a gross basis.

In addition to the transactions we execute through the futures clearing managers, we also execute transactions through multiple bilateral counterparties.  Our transactions with these counterparties are collateralized using only cash collateral.  As of June 30, 2012, we had $98 million posted with these counterparties, which is included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets.

The following table presents the fair value and balance sheet classification of derivatives in the unaudited condensed consolidated balance sheet as of June 30, 2012, and December 31, 2011 segregated by type of contract segregated by assets and liabilities.

Contract Type	Balance Sheet Location	June 30, 2012			December 31, 2011
		(in millions)
Derivative Assets:
Commodity contracts	Assets from risk management activities	1,286			2,639
Commodity contracts, affiliates	Assets from risk management activities, affiliates	—			2
Interest rate contracts	Assets from risk management activities	2			2
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities	(1,373		)	(2,810		)
Commodity contracts, affiliates	Liabilities from risk management activities, affiliates	—			(7		)
Interest rate contracts	Liabilities from risk management activities	(38		)	(8		)
Total derivatives, net		$	(123	)	$	(182	)

Impact of Derivatives on the Consolidated Statements of Operations

The following discussion and table presents the location and amount of gains and losses on derivative instruments in our consolidated statements of operations segregated between designated, qualifying hedging instruments and those that are not, by type of contract. We had no derivatives that were designated in qualifying hedging relationships during the three and six months ended June 30, 2012.

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

For the three-month period ended June 30, 2012, our revenues included approximately $2 million of unrealized mark-to-market losses related to this activity compared to $129 million of unrealized mark-to-market losses in the same period in the prior year.  For the six months ended June 30, 2012, our revenues included approximately $70 million of unrealized mark-to-

17

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

market gains related to this activity compared to $127 million of unrealized mark-to-market losses in the same period in the prior year.

The impact of derivative financial instruments, including realized and unrealized gains and losses, that have not been designated as hedges on our unaudited condensed consolidated statements of operations for the three and 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.

Derivatives Not Designated as Hedging	Location of Gain ( Loss) Recognized in Income on Derivatives	Amount of Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended June 30,						Amount of Gain (Loss) Recognized in Income on Derivatives for the Six Months Ended June 30,
		2012			2011			2012			2011
		(in millions)
Commodity contracts	Revenues	$	(48	)	$	(89	)	$	9		$	(70	)
Interest rate contracts	Interest Expense	(13		)	—			(17		)	—

Note 7—Fair Value Measurements

The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2012 and 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 fair value assets and liabilities and their placement within the fair value hierarchy levels.

18

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	Fair Value as of June 30, 2012
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—	$	248		$	11		$	259
Electricity derivatives, affiliates	—		—			—			—
Natural gas derivatives	—		1,024			—			1,024
Other derivatives	—		3			—			3
Total assets from commodity risk management activities	$	—	$	1,275		$	11		$	1,286
Assets from interest rate contracts	—		—			2			2
Total	$	—	$	1,275		$	13		$	1,288
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(207	)	$	(3	)	$	(210	)
Electricity derivatives, affiliates	—		—			—			—
Natural gas derivatives	—		(1,164		)	—			(1,164		)
Heat rate derivatives	—		—			(8		)	(8		)
Other derivatives	—		(2		)	—			(2		)
Total liabilities from commodity risk management activities	$	—	$	(1,373	)	$	(11	)	$	(1,384	)
Liabilities from interest rate contracts	—		—			(27		)	(27		)
Administrative Claim (1)	—		—			(73		)	(73		)
Total	$	—	$	(1,373	)	$	(111	)	$	(1,484	)

_______________________________________________________________

(1) Amount represents the fair value of the Administrative Claim that was issued to Dynegy upon the effective date of the Settlement Agreement. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

19

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	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	$	—	$	211		$	26		$	237
Electricity derivatives, affiliates	—		1			1			$	2
Natural gas derivatives	—		2,387			—			2,387
Other derivatives	—		15			—			15
Total assets from commodity risk management activities:	$	—	$	2,614		$	27		$	2,641
Assets from interest rate contracts	—		—			2			2
Total	$	—	$	2,614		$	29		$	2,643
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(169	)	$	(2	)	$	(171	)
Electricity derivatives, affiliates	—		(2		)	(5		)	(7		)
Natural gas derivatives	—		(2,607		)	—			(2,607		)
Heat rate derivatives	—		—			(17		)	(17		)
Other derivatives	—		(15		)	—			(15		)
Total liabilities from commodity risk management activities	$	—	$	(2,793	)	$	(24	)	$	(2,817	)
Liabilities from interest rate contracts	—		—			(8		)	(8		)
Total	$	—	$	(2,793	)	$	(32	)	$	(2,825	)

Level 3 valuation methods:

The electricity contracts classified within level 3 are primarily financial swaps executed in illiquid trading locations and capacity contracts.  The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed.  Additionally, FTRs are classified within the electricity contracts, which are also an illiquid product.  The forward market price of FTRs is derived using historical congestion patterns within the marketplace.  Heat rate option valuations are derived using a Black-Sholes spread model, which uses forward natural gas and power prices, market implied volatilities and modeled power/natural gas correlation values. The interest rate contracts classified within Level 3 include an implied credit fee that impacted the day one value of the instruments.  We revalue the credit fee each quarter in conjunction with revaluing the actual interest rate derivative.  The interest rate derivatives are revalued using the forward LIBOR curve each period and the credit fee is revalued by determining the change in credit factors, such as credit default swaps, period over period.

Sensitivity to Changes in Significant unobservable inputs for level 3 valuations:

The significant unobservable inputs used in the fair value measure of our commodity instruments categorized within Level 3 of the fair value hierarchy are estimates of future price correlation, future market volatility, estimates of forward congestion power price spreads, assumptions of illiquid power location pricing basis to liquid locations, and estimates of counterparty credit risk and our own non-performance risk. These assumptions are generally independent of each other. Volatility curves and power prices spreads are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price or volatility of the spread on a long/short position in isolation would result in a higher/lower fair value measurement. A change in the assumption used for the probability of default is accompanied by a directionally similar change in the adjustment to reflect the estimated default risk of counterparties on their contractual obligations, or the estimated risk of default on our own contractual obligations to

20

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

counterparties.  Any change in the value of the unobservable inputs used for level 3 valuations could have a significant impact on the calculated fair value.

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

The finance organization monitors commodity risk through the CRCG.  The EMT monitors interest rate risk.  The EMT has delegated the responsibility for managing interest rate risk to the CFO.  The CRCG is independent of our commercial operations and has direct access to the Audit and Compliance Committee of our parent. The Finance and Risk Management Committee, chaired by the CFO, 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:

21

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	Three Months Ended June 30, 2012
	Electricity Derivatives			Heat Rate Derivatives			Administrative Claim			Interest Rate Swaps			Total
	(in millions)
Balance at March 31, 2012	$	22		$	(11	)	$	—		$	(9	)	$	2
Total losses included in earnings	(18		)	1			(9		)	(9		)	(35		)
Settlements	—			2			—			—			2
Issuance of Administrative Claim	—			—			(64		)				(64		)
DMG Acquisition	4			—			—			(7		)	(3		)
Balance at June 30, 2012	$	8		$	(8	)	$	(73	)	$	(25	)	$	(98	)
Unrealized gains (losses) relating to instruments (net of affiliates) held as of June 30, 2012	$	7		$	1		$	(9	)	$	(17	)	$	(18	)

	Six Months Ended June 30, 2012
	Electricity Derivatives			Heat Rate Derivatives			Administrative Claim			Interest Rate Swaps			Total
	(in millions)
Balance at December 31, 2011	$	20		$	(17	)	$	—		$	(6	)	$	(3	)
Total gains (losses) included in earnings	(16		)	3			(9		)	(17		)	(39		)
Settlements	—			6			—			—			6
Issuance of Administrative Claim	—			—			(64		)	—			(64		)
DMG Acquisition	4			—			—			(2		)	2
Balance at June 30, 2012	$	8		$	(8	)	$	(73	)	$	(25	)	$	(98	)
Unrealized gains (losses) relating to instruments (net of affiliates) held as of June 30, 2012	$	10		$	1		$	(9	)	$	(17	)	$	(15	)

	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 (net of affiliates) held as of June 30, 2011	$	(5	)	$	(4	)	$	(2	)	$	(11	)

22

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	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 (net of affiliates) held as of June 30, 2011	$	2		$	(3	)	$	—		$	(1	)

Gains and losses (realized and unrealized) for Level 3 recurring items are included in Revenues, Interest expense and Bankruptcy reorganization charges on the unaudited condensed consolidated statements of operations for commodity derivatives, interest rate swaps and the Administrative Claim, respectively.  We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio.  We did not have any transfers between Level 1, Level 2 and Level 3 for the three and six months ended June 30, 2012 and 2011.

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

The carrying values of financial assets and liabilities (cash, accounts receivable, restricted cash and investments, short-term investments and accounts payable) not presented in the table below approximate fair values due to the short-term maturities of these instruments.  The $846 million Accounts receivable, affiliate balance with Dynegy classified within member's equity as of December 31, 2011 does not have a fair value as there are no defined payment terms, are not evidenced by any promissory notes, and there has never been an intent for payment to occur. The Accounts receivable, affiliate balance was settled on June 5, 2012. Please read Note 14—Related Party Transactions—Accounts receivable, 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 periods ending June 30, 2012 and December 31, 2011, respectively.

	June 30, 2012						December 31, 2011
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(in millions)
Undertaking receivable, affiliate (1)	$	—		$	—		$	1,250		$	728
Interest rate derivatives not designated as accounting hedges(2)	(36		)	(36		)	(6		)	(6		)
Commodity-based derivative contracts not designated as accounting hedges (2)	(87		)	(87		)	(176		)	(176		)
DPC Credit Agreement due 2016 (3)	(1,073		)	(1,138		)	(1,076		)	(1,118		)
DMG Credit Agreement due 2016 (4)	(608		)	(611		)	—			—
Administrative Claim (5)	(73		)	(73		)	—			—

_______________________________________________________________

(1) The fair value of the Undertaking receivable is classified within Level 3 of the fair value hierarchy. Our December 31, 2011 estimate of the fair value of the Undertaking receivable represents the $750 million fair value 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. Please read Note 3—Chapter 11 Cases and Note 4—DMG Acquisition for further discussion.

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

23

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

(3) Carrying amount includes unamortized discounts of $19 million and $21 million at June 30, 2012 and December 31, 2011.

(4) Includes unamortized premiums of $12 million as of June 30, 2012. We completed the DMG Acquisition on June 5, 2012.

(5) Amount represents the fair value of the Administrative Claim that was issued to Dynegy upon the effective date of the Settlement Agreement. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

We recorded the Administrative Claim granted in the DMG Acquisition 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 DMG Acquisition. 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 our emergence from bankruptcy. The Administrative Claim can be settled in cash under certain circumstances, as such we account for the Administrative Claim as a liability and adjust the carrying amount of the claim to its estimated fair value each reporting period. As of June 30, 2012, the fair value of the Administrative claim was approximately $73 million; therefore, we recorded a charge of approximately $9 million in Other income and expense, net on our consolidated statement of operations for the three and six months ended June 30, 2012. 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.

Note 8—Accumulated Other Comprehensive Income

Accumulated other comprehensive income, net of tax, is included in member's equity on our unaudited condensed consolidated balance sheets as follows:

	June 30, 2012			December 31, 2011
	(in millions)
Cash flow hedging activities, net	$	—		$	1
Unrecognized prior service cost and actuarial loss, net	(40		)	—
Accumulated other comprehensive loss, net of tax	$	(40	)	$	1

Note 9—Inventory

A summary of our inventories is as follows:

	June 30, 2012		December 31, 2011
	(in millions)
Materials and supplies	$	60	$	40
Coal	62		16
Fuel	9		8
Emissions allowances	1		1
Total	$	132	$	65

Note 10—Property, Plant, & Equipment

A summary of our property, plant and equipment is as follows:

24

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	June 30,			December 31,
	2012			2011
	(in millions)
Generation assets:
Coal (1)	$	523		$	—
Gas	3,528			3,532
DNE	268			268
IT systems and other	97			111
Property, plant and equipment	4,416			3,911
Accumulated depreciation	(1,126		)	(1,090		)
Property, plant and equipment, net	$	3,290		$	2,821

_______________________________________________________________________________

(1) Amounts related to the Coal segment (including DMG) were acquired effective June 5, 2012. Please read Note 4—DMG Acquisition for further discussion.

Total interest costs incurred were $30 million and $56 million for the three and six months ended June 30, 2012 and $86 million and $173 million for the three and six months ended June 30, 2011, respectively. Interest capitalized related to costs of construction projects in process totaled $1 million and $1 million for the three and six months ended June 30, 2012 and $5 million and $9 million for the three and six months ended June 30, 2011, respectively.

Note 11—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 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 our bondholders (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 DMG 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

25

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Litigation, the Lease Trustee Litigation and the PSEG Litigation are collectively referred to as the "Prepetition Litigation".    

The Prepetition Litigation challenged the DMG Transfer. Plaintiffs in all three actions alleged, among other claims, breach of contract, breach of fiduciary duties, and violations of prohibitions on fraudulent transfers in connection with the DMG Transfer and also sought to have the DMG Transfer set aside, and requested 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.

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.

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 which has set oral argument for October 19, 2012.

Pacific Northwest Refund Proceedings. Dynegy Power Marketing, LLC (“DYPM”), along with numerous other companies that sold power in the Pacific Northwest in 2000-2001, are parties to a complaint filed in 2001 with FERC challenging bilateral contract pricing by claiming manipulation of the electricity market in California produced unreasonable prices in the Pacific Northwest.  DYPM previously settled all California refund claims, but did not settle with certain complainants seeking refunds in the Pacific Northwest.  In December 2011, DYPM received a Notice of Settlement from The City of Seattle (“Seattle”) claiming that it paid approximately $2 million to DYPM above the mitigated market clearing price set for the California market in 2000-2001.  In May 2012, Seattle made an initial settlement demand of $744 thousand plus interest.  Trial has been set for April 2013 and the parties are currently engaged in discovery. DYPM intends to continue to defend its position in the proceeding vigorously.  In addition to Seattle's claim, there is the risk for “ripple claims” from other sellers, but the efficacy of these claims is currently being litigated and any potential impact to DYPM from ripple claims is impossible to predict at this stage. 

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

26

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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.

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.

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.  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.

In July 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at the Baldwin and Vermilion facilities. In response, we have submitted to the Illinois EPA a proposed compliance agreement for each facility.  For Vermilion, we proposed to implement the previously submitted corrective action plans and, for Baldwin, we proposed to perform additional studies of hydrogeologic conditions and apply for a groundwater management zone in preparation for submittal, as necessary, of a corrective action plan.  

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

The environmental groups that participate in our NPDES and SPDES permit proceedings generally argue that only closed

27

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

cycle cooling meets the BTA requirement.  The issuance and renewal of NPDES or SPDES permits for three of our power generation facilities (Danskammer, Roseton and Moss Landing) have been challenged on this basis.  The Danskammer SPDES permit, which was renewed and issued in June 2006, does not require installation of a closed cycle cooling system; however, it does require aquatic organism mortality reductions resulting from NYSDEC's determination of BTA requirements under its regulations.  All appeals of this permit have been exhausted.  The Moss Landing NPDES permit, which was issued in 2000, does not required closed cycle cooling and was challenged by a local environmental group. In August 2011, the Supreme Court of California affirmed the appellate court's decision upholding the permit. One permit challenge is still pending.

Roseton SPDES Permit - In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton plant.  The permit is opposed by environmental groups challenging the BTA determination.  In October 2006, various holdings in the administrative law judge's ruling admitting the environmental group petitioners to party status and setting forth the issues to be adjudicated in the permit renewal hearing were appealed to the Commissioner of NYSDEC by the petitioners, NYSDEC staff and us.  The permit renewal hearing will be scheduled after the Commissioner rules on those appeals.  We believe that the petitioners' claims lack merit and we have opposed those claims vigorously. In connection with the DH Chapter 11 Cases, the DH Debtor Entities rejected these long-term leases at the Roseton and Danskammer facilities. The applicable 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 Settlement Agreement and Plan Support Agreement and in compliance with applicable federal and state regulatory requirements. Please see Note 3—Chapter 11 Cases for further information.

Other future NPDES or SPDES proceedings could have a material effect on our financial condition, results of operations and cash flows; however, given the numerous variables and factors involved in calculating the potential costs associated with installing a closed cycle cooling system, any decision to install such a system at any of our facilities would be made on a case-by-case basis considering all relevant factors at such time.  If capital expenditures related to cooling water systems become great enough to render the operation of the plant uneconomical, we could, at our option, and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate that facility and forego the capital expenditures.

SCE Termination. In May 2012, Southern California Edison (“SCE”) notified Dynegy Morro Bay, LLC (“Morro Bay”)  and Dynegy Moss Landing, LLC (“Moss Landing”) that it was terminating certain energy and capacity contracts with those entities.  The validity of the purported terminations and subsequent actions by SCE are being disputed by Dynegy. We intend to vigorously pursue all remedies and amounts due to us under these contracts.

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 approximately $1 million as of June 30, 2012.

LS Power Indemnities.  In connection with the LS Power Transactions we agreed in the purchase and sale agreement to indemnify LS Power against claims regarding any breaches in our representations and warranties and certain other potential liabilities.  Claims for indemnification shall survive until twelve months subsequent to closing with exceptions for tax claims, which shall survive for the applicable statute of limitations plus 30 days, and certain other representations and potential liabilities, which shall survive indefinitely.  The indemnifications provided to LS Power are limited to $1.3 billion in total; however, several categories of indemnifications are not available to LS Power until the liabilities incurred in the aggregate are equal to or exceed $15 million and are capped at a maximum of $100 million.  Further, the purchase and sale agreement provides in part that we may not reduce or avoid liability for a valid claim based on a claim of contribution.  In addition to the

28

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

above indemnities related to the LS Power Transactions, we have agreed to indemnify LS Power against claims related to the Riverside/Foothills Project for certain aspects of the project.  Namely, LS Power has been indemnified for any disputes that arise as to ownership, transfer of bonds related to the project, and any failure by us to obtain approval for the transfer of the payment in-lieu of taxes program already in place.  The indemnities related solely to the Riverside/Foothills Project are capped at a maximum of $180 million and extend until the earlier of the expiration of the tax agreement or December 26, 2026.  At this time, we have incurred no significant expenses under these indemnities.  Please read Note 5—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—LS Power Transactions in our Form 10-K for further discussion.

West Coast Power Indemnities.  In connection with the sale of our 50 percent interest in West Coast Power to NRG on March 31, 2006, an agreement was executed to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation.  The indemnification agreement in relevant part provides that NRG assumes responsibility for all defense costs and any risk of loss, subject to certain conditions and limitations, arising from a February 2002 complaint filed at FERC by the California Public Utilities Commission alleging that several parties, including West Cost Power subsidiaries, overcharged the State of California for wholesale power.  FERC found the rates charged by wholesale suppliers to be just and reasonable; however, this matter was appealed and ultimately remanded back to FERC for further review.  On May 24, 2011 and May 26, 2011, FERC issued two orders in these dockets.  The first order denied the request of the California Parties for consolidation of various dockets and denied their request for summary disposition on market manipulation issues.  The second order addressed treatment of settled parties and the scope of hearing issues in the ongoing proceedings. 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 our midstream business (“DMSLP”), we agreed to indemnify Targa Resources, Inc. (“Targa”) against losses it may incur under indemnifications DMSLP provided to purchasers of certain assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP.  We have incurred no material expense under these prior indemnities.  We have recorded an accrual of less than $1 million for remediation of groundwater contamination at the Breckenridge Gas Processing Plant sold by DMSLP in 2001.  The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million.

Black Mountain Guarantee.  Through one of our subsidiaries, we hold a 50 percent ownership interest in Black Mountain (Nevada Cogeneration) (“Black Mountain”), in which our partner is a Chevron subsidiary.  Black Mountain owns the Black Mountain power generation facility and has a power purchase agreement with a third party that extends through April 2023.  In connection with the power purchase agreement, pursuant to which Black Mountain receives payments which decrease in amount over time, we agreed to guarantee 50 percent of certain payments that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement.  At June 30, 2012, if an event of default due to early termination had occurred under the terms of the mortgage on the facility entered into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $53 million under the guarantee.

Other Indemnities.  We entered into indemnifications regarding environmental, tax, employee and other representations when completing asset sales such as, but not limited, to the Rolling Hills, Calcasieu, CoGen Lyondell and Heard County power generating facilities.  As of June 30, 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 12—Debt

A summary of our long-term debt is as follows:

29

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	June 30, 2012				December 31, 2011
	Carrying Amount			Fair Value	Carrying Amount			Fair Value
	(in millions)
DPC Credit Agreement, due 2016 (1)	1,091			1,138	1,097			1,118
DMG Credit Agreement, due 2016 (2)	596			611	—			—
	1,687				1,097
Unamortized premium (discount) on debt, net	(6		)		(21		)
	1,681				1,076
Less: Amounts due within one year, including non-cash amortization of basis adjustments	16				7
Total Long-Term Debt	$	1,665			$	1,069

_______________________________________________________________________________

(1) Please read Note 20—Debt in our Form 10-K for further discussion.

(2) Please read DMG Credit Agreement below for further discussion.

DMG Credit Agreement.  As a result of the DMG Acquisition, we recorded DMG's senior secured term loan facility with an aggregate outstanding principal amount of $597 million. The DMG Credit Agreement will mature on August 5, 2016 and will amortize in equal quarterly installments in aggregate annual amounts equal to 1.00 percent of the original principal amount of the DMG Credit Agreement with the balance payable on the fifth anniversary of the closing date.

All obligations of DMG under (i) the DMG Credit Agreement (the “DMG Borrower Obligations”) and (ii) at the

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

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

The DMG Credit Agreement bears interest, at DMG's option, at either (a) 7.75 percent per annum plus LIBOR, subject to a LIBOR floor of 1.50 percent, with respect to any Eurodollar term loan or (b) 6.75 percent per annum plus the alternate base rate with respect to any ABR term loan. DMG may elect from time to time to convert all or a portion of the term loan from any ABR Borrowing into a Eurodollar Borrowing or vice versa. With some exceptions, the DMG Credit Agreement is non-callable for the first 2 years and is subject to a prepayment premium.

The DMG Credit Agreement contains mandatory prepayment provisions. The outstanding loan under the DMG Credit Agreement is to be prepaid with (a) 100 percent of the net cash proceeds of all asset sales by DMG and its subsidiaries, subject to the right of DMG to reinvest such proceeds if such proceeds are reinvested (or committed to be reinvested) within 12 months and, if so committed to reinvestment, reinvested within 6 months after such initial 12 month period, (b) 50 percent of the net cash proceeds of issuance of equity securities of DMG and its subsidiaries (except to the extent used (x) to prepay the Loans, (y) for capital expenditures and (z) for permitted acquisitions), (c) commencing with the first full fiscal year of DMG to occur after the closing date, 100 percent of excess cash flow; provided that (i) excess cash flow shall be determined after reduction for amounts used for capital expenditures, and restricted payments made and (ii) any voluntary prepayments of the term loans shall be credited against excess cash flow prepayment obligations and (d) 100 percent of the net cash proceeds of issuances, offerings or placements of debt obligations of DMG and its subsidiaries (other than all permitted debt).

The DMG Credit Agreement contains customary events of default and affirmative and negative covenants including, subject to certain specified exceptions, limitations on amendments to constitutive documents, liens, capital expenditures,

30

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

acquisitions, subsidiaries and joint ventures, investments, the incurrence of debt, fundamental changes, asset sales, sale-leaseback transactions, hedging arrangements, restricted payments, changes in nature of business, transactions with affiliates, burdensome agreements, amendments of debt and other material agreements, accounting changes and prepayment of

indebtedness or repurchases of equity interests.

The DMG Credit Agreement contains a requirement that DMG shall establish and maintain a segregated account,

subject to the control of the Collateral Trustee (the “DMG Collateral Posting Account”), into which a specified collateral posting amount shall be deposited. DMG may withdraw amounts from the DMG Collateral Posting Account: (i) for the purpose of meeting collateral posting requirements of DMG and the DMG Guarantors; (ii) to prepay the term loan under the DMG Credit Agreement; (iii) to repay certain other permitted indebtedness; and (iv) to the extent any excess amounts are determined to be in the DMG Collateral Posting Account.

The DMG Credit Agreement limits distributions to $90 million per year provided the borrower and its subsidiaries

possess at least $50 million of cash and cash equivalents and short-term investments as of the date of the proposed distribution.

Letter of Credit Facility. We also acquired DMG's $100 million fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement pursuant to which letters of credit will be issued at DMG’s request provided that DMG deposits in an account an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereof.

Restricted Cash and Investments

The following table depicts our restricted cash:

	June 30, 2012		December 31, 2011
	(in millions)
DPC LC facilities (1)	$	297	$	455
DH LC facility (1)	27		27
DPC Collateral Posting Account (2)	167		132
DMG LC Facility (3)	42		—
DMG Collateral Posting (2)	65		—
Total restricted cash	$	598	$	614

_______________________________________________________________________________

(1) Includes cash posted to support the respective letter of credit reimbursement and collateral agreement.

(2) Amounts are restricted and may be used for future collateral posting requirements or released per the terms of the applicable credit agreement.

(3) Includes cash posted to support the letter of credit reimbursement and collateral agreements under the DMG LC facility. Please read "Letter of Credit Facility" above for further discussion.

Note 13—Liabilities Subject to Compromise

A summary of our LSTC as of June 30, 2012 and December 31, 2011 is as follows:

31

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	June 30, 2012		December 31, 2011
	(in millions)
DNE lease termination claim (1)	$	695	$	300
Senior Notes:
8.75 percent due 2012	88		88
7.5 percent due 2015	785		785
8.375 percent due 2016	1,047		1,047
7.125 percent due 2018	175		175
7.75 percent due 2019	1,100		1,100
7.625 percent due 2026	175		175
Subordinated Debentures payable to affiliates, 8.316 percent, due 2027 (2)	55		200
Interest accrued on Senior Notes and Subordinated Debentures as of November 7, 2011 (2)	116		132
Note payable, affiliate (3)	—		10
Administrative Claim (4)	73		—
Other	6		—
Total Liabilities subject to compromise	$	4,315	$	4,012

_______________________________________________________________________________

(1) The estimated amount of the allowed claim related to the Facilities was increased to approximately $695 million during 2012 as a result of entering into the Settlement Agreement. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Note 4—DMG Acquisition for further discussion.

(2) The estimated amount of the allowed claim related to the Subordinated Capital Income Securities payable to affiliate, including accrued interest, was reduced to $55 million during the second quarter 2012 as a result of an amendment to the Settlement Agreement. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Note 4—DMG Acquisition for further discussion.

(3) During the first quarter 2012, it was determined that no claim related to the Note payable, affiliate would be made. Therefore, the estimated amount of the allowed claim was reduced to zero.

(4) Amount represents the fair value of the Administrative Claim that was issued to Dynegy upon the effective date of the Settlement Agreement.

Note 14—Related Party Transactions

The following tables summarize the Accounts receivable, affiliates, and Accounts payable, affiliates, on our consolidated balance sheet as of June 30, 2012 and December 31, 2011 and cash received for the three and six months ended June 30, 2012 related to various agreements with Dynegy Inc., as discussed below:

	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

32

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	December 31, 2011
	Accounts Receivable, Affiliates		Accounts Payable, Affiliates
	(in millions)
Service Agreements	$	4	$	6
EMA Agreements	22		41
Total	$	26	$	47

Service Agreements.    Dynegy and certain of our subsidiaries (collectively, the "Providers") provide certain services (the "Services") to Dynegy Coal Investments Holdings, LLC ("DCIH") and certain of its subsidiaries, and certain of our subsidiaries (collectively, the "Recipients"). Service Agreements between Dynegy and the Recipients, which were entered into in connection with the Reorganization, 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 Agreements, the Providers and the Recipients must agree on a budget for the Services, outlining, among other items, the contemplated scope of the Services to be provided in the following fiscal year and the cost of providing each Service. The Recipients will pay the Providers an annual management fee as agreed in the budget, which shall include reimbursement of out-of pocket costs and expenses related to the provision of the Services and will provide reasonable assistance, such as information, services and materials, to the Providers.

Energy Management Agreements.    Certain of our subsidiaries have entered into an Energy Management Agency Services Agreement (an "EMA") with DMG. Pursuant to the EMA, our subsidiaries will provide power management services to DMG, consisting of marketing power and capacity, capturing pricing arbitrage, scheduling dispatch of power, communicating with the applicable ISOs or RTOs, purchasing replacement power, and reconciling and settling ISO or RTO invoices. In addition, certain of our subsidiaries will provide fuel management services, consisting of procuring the requisite quantities of fuel and emissions credits, assisting with transportation, scheduling delivery of fuel, assisting DMG 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. Our subsidiaries will also assist DMG with risk management by entering into one or more risk management transactions, the purpose of which is to set the price or value any commodity or to mitigate or offset any change in the price or value of any commodity. Our subsidiaries may from time to time provide other services as the parties may agree. Our consolidated statement of operations includes $69 million and $198 million of power purchased from affiliates, which is reflected in Revenues for the three and six months ended June 30, 2012, respectively. Our consolidated statement of operations also includes $24 million and $79 million of coal sold to affiliates, which is reflected in Costs of sales, for the three and six months ended June 30, 2012, respectively. This affiliate activity is presented net of third party activity within revenue and cost of sales. Also, please read Note 6—Risk Management Activities, Derivatives and Financial Instruments for derivative balances with affiliates. As a result of the DMG Acquisition, transactions executed under the Energy Management Agreement are not considered related party transactions subsequent to June 5, 2012.

Tax Sharing Agreement.    Under U.S. federal income tax law, Dynegy is responsible for the tax liabilities of its subsidiaries, because Dynegy files consolidated income tax returns, which will necessarily include the income and business activities of the ring-fenced entities and Dynegy's other affiliates. To properly allocate taxes among Dynegy and each of its entities, Dynegy and certain of its entities, including us and our subsidiaries, have entered into a Tax Sharing Agreement under which Dynegy agrees to prepare consolidated returns on behalf of itself and its entities and make all required payments to relevant revenue collection authorities as required by law. Additionally, DPC agreed to make payments to Dynegy of the tax amounts for which DPC and its respective subsidiaries would have been liable if such subsidiaries began business on the restructuring date (August 5, 2011) and were eligible to, and elected to, file a consolidated return on a stand-alone basis beginning on the restructuring date. Further, each of Dynegy GasCo Holdings, LLC, Dynegy Gas Holdco, LLC, and Dynegy Gas Investments Holdings, LLC, agreed to make payments to Dynegy of amounts representing the tax that each such subsidiary would have paid if each began business on the restructuring date and filed a separate corporate income tax return (excluding from income any subsidiary distributions) on a stand-alone basis beginning on the restructuring date.

33

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Cash Management.    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 with the ring-fenced group without independent manager approval.

Pursuant to our Cash Management Agreement, 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 for the three and six months ended June 30, 2012 related to the Cash Management Agreement.

DMG Transfer and Undertaking Agreement.    During the six months ended June 30, 2012, we recognized $24 million in interest income related to the Undertaking Agreement which is included in Other income and expense, net, in our consolidated statement of operations. We did not recognize any interest income during the three months ended June 30, 2012 as we impaired the value of the Undertaking as of March 31, 2012 and the valuation as of that date considered the interest payments received during the second quarter of 2012. We received payments of $48 million from Dynegy during the three and six months ended June 30, 2012 related to the Undertaking Agreement. We had approximately $8 million as of December 31, 2011 in interest receivable related to the undertaking, which is reflected in Interest receivable, affiliates on our consolidated balance sheet. The Undertaking Agreement was terminated on June 5, 2012 in connection with the Settlement Agreement. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

Note payable, affiliates.    On August 5, 2011, Dynegy Coal Holdco, LLC made a loan to the company of $10 million with a maturity of 3 years and an interest rate of 9.25 percent per annum.

The Note payable, affiliate was written off during the first quarter 2012 as it was determined that no claim would be filed related to the note.

Accounts receivable, 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 and adjusted over time an affiliate receivable balance in the amount of $846 million at December 31, 2011. This receivable is classified within equity as there are no defined payment terms, it is not evidenced by any promissory note, and there was never an intent for payment to occur. The Accounts receivable, affiliate was settled on June 5, 2012. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement for further discussion.

Employee benefits.    Our employees participate in the pension plans of our parent, Dynegy.

Note 15—Income Taxes

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

34

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions, except rates)
Income tax benefit	$	1		$	75		$	7		$	133
Effective tax rate	1		%	39		%	1		%	41		%

For the three months ended June 30, 2012 and 2011, our overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due primarily to the impact of state taxes.

For the six month period ended June 30, 2012, the difference between the effective rate of 1 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 month period ended June 30, 2011, the difference between the effective rates of 41 percent and the statutory rate of 35 percent resulted primarily from the impact of state taxes including a benefit of $6 million related to an increase in state NOLs due to the acceptance of amended returns, which we filed as a result of a change in a tax position, partially offset by an expense of $2 million related to an increase in the Illinois statutory rate. 

Note 16—Employee Compensation, Savings and Pension Plans

Our parent, Dynegy, sponsors and administers defined benefit plans and defined contribution plans for the benefit of our employees and also provides other post retirement benefits to retirees who meet age and service requirements which are more fully described in Note 24—Employee Compensation, Savings and Pension Plans in our Form 10-K.

The following are inclusive of net periodic benefit costs related to the Dynegy multi-employer pension and other post-retirement benefit plans. For the three and six months ended June 30, 2012, one month of Dynegy multi-employer plans are included within net periodic benefit costs. For the three and six months ended June 30, 2011 six months of Dynegy multi-employer pension and other post-retirement benefit plans are included within net periodic benefit costs. Please read Note 4—DMG Acquisition for further discussion.

Components of Net Periodic Benefit Cost.  The components of net periodic benefit cost were:

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

35

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

Contributions.  During the six months ended June 30, 2012 we made $7 million in contributions through certain service agreements to our pension plans and less than $1 million to our other post-retirement benefit plans.  We made $6 million in contributions to our pension plans or other post-retirement benefit plans during the six months ended June 30, 2011.  We expect to make no contributions to our pension plans and to our other benefit plans during the remainder of 2012.

Note 17—Segment Information

As reflected in this report, we have changed our reportable segments.  Prior to this report, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE.  Beginning with the third quarter 2011, as a result of the Reorganization, 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, on September 1, 2011, we completed the DMG Transfer; therefore, the results of our Coal segment were not included as of September 1, 2011. On June 5, 2012, we completed the DMG Acquisition; therefore the results of our Coal segment were included for the period of June 6, 2012 through June 30, 2012. Please read Note 4—DMG Acquisition for further discussion of the DMG Acquisition.

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

36

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	40		$	230		$	20		$	—		$	290
Total revenues	$	40		$	230		$	20		$	—		$	290
Depreciation and amortization	$	(4	)	$	(36	)	$	—		$	(3	)	$	(43	)
General and administrative expense	(5		)	(15		)	(1		)	4			(17		)
Operating income (loss)	$	(22	)	$	13		$	(5	)	$	2		$	(12	)
Bankruptcy reorganization charges													(22		)
Other items, net													6
Interest expense													(42		)
Loss from continuing operations before income taxes													(70		)
Income tax benefit													1
Net loss													$	(69	)
Identifiable assets (domestic)	$	1,340		$	5,254		$	42		$	163		$	6,799
Capital expenditures	$	(11	)	$	(12	)	$	—		$	(5	)	$	(28	)

37

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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		)	2			(23		)
Operating loss	$	(47	)	$	(32	)	$	(24	)	$	(1	)	$	(104	)
Other items, net	2			1			—			—			3
Interest expense													(89		)
Loss from continuing operations before income taxes													(190		)
Income tax benefit													75
Net loss													$	(115	)
Identifiable assets (domestic)	$	3,617		$	4,265		$	520		$	1,394		$	9,796
Capital expenditures	$	(44	)	$	(17	)	$	(1	)	$	—		$	(62	)

38

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	40		$	498		$	27		$	—		$	565
Total revenues	$	40		$	498		$	27		$	—		$	565
Depreciation and amortization	$	(4	)	$	(56	)	$	—		$	(5	)	$	(65	)
General and administrative expense	(5		)	(30		)	(2		)	—			(37		)
Operating income (loss)	$	(22	)	$	32		$	(20	)	$	(4	)	$	(14	)
Impairment of Undertaking receivable, affiliate	—			—			—			(832		)	(832		)
Other items, net	5			2			—			23			30
Bankruptcy reorganization charges	—			—			(589		)	320			(269		)
Interest expense													(73		)
Loss from continuing operations before income taxes													(1,158		)
Income tax benefit													7
Net loss													$	(1,151	)
Identifiable assets (domestic)	$	1,340		$	5,254		$	42		$	163		$	6,799
Capital expenditures	$	(11	)	$	(20	)	$	—		$	(6	)	$	(37	)

39

DYNEGY HOLDINGS, LLC

(A LIMITED LIABILITY COMPANY)

DEBTOR-IN-POSSESSION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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		)	(11		)	(64		)
Operating loss	$	(79	)	$	(19	)	$	(39	)	$	(17	)	$	(154	)
Other items, net	2			1			—			1			4
Interest expense													(178		)
Loss from continuing operations before income taxes													(328		)
Income tax benefit													133
Net loss													$	(195	)
Identifiable assets (domestic)	$	3,617		$	4,265		$	520		$	1,394		$	9,796
Capital expenditures	$	(87	)	$	(40	)	$	(1	)	$	—		$	(128	)

40

DYNEGY HOLDINGS, LLC

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended June 30, 2012 and 2011

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 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 this report, 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) Coal; (ii) Gas and (iii) 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, on June 5, 2012, we reacquired the Coal segment (including DMG); therefore the results of our Coal segment were included for the period of June 6, 2012 through June 30, 2012.

Chapter 11 Cases.  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. Only the DH Debtor Entities and our parent Dynegy sought relief under the Bankruptcy Code, and none of our other direct or indirect subsidiaries are debtors thereunder. The normal day-to-day operations of the natural gas-fired power generation facilities held by DPC and the coal-fired power generation facilities held by DMG continue without interruption. The commencement of either of the Chapter 11 Cases did not constitute a default under the DPC Credit Agreement or DMG Credit Agreement. Please see Note 3—Chapter 11 Cases for further discussion of the Chapter 11 Cases and the related Settlement Agreement and Plan Support Agreement.

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 100% of the outstanding equity interests of Dynegy Coal Holdco, LLC (“Coal Holdco”) were transferred from Dynegy to DH (the "DMG Acquisition") 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 Promissory Note were terminated with no further obligations thereunder. 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.

Pursuant to the Settlement Agreement, we completed the DMG Acquisition. We accounted for this transaction as a business combination. Accordingly, assets acquired and liabilities assumed were recognized at their fair value as of the acquisition date. Please refer to Note 4—DMG Acquisition for further details regarding fair value of net assets acquired.

On July 12, 2012, the Plan Proponents filed the Plan for Dynegy and DH and the related Disclosure Statement with the Bankruptcy Court. On August 27, 2012, the results of the vote on the Plan were filed with the Bankruptcy Court, with creditors

41

holding over $3.5 billion of claims, or more than 99% of the value of the claims that voted, approving the Plan (this reflects approximately 87% of the number of creditors who voted). Further, Dynegy announced that the Consenting Senior Noteholders, the Lease Trustee and the Creditors' Committee selected the initial directors to be appointed to Dynegy's Board. At a hearing on September 5, 2012, the Bankruptcy Court found that DH and Dynegy had met all the Plan confirmation requirements under the Bankruptcy Code. Accordingly, on September 10, 2012, the Bankruptcy Court entered its Confirmation Order.

Going Concern. Our accompanying unaudited condensed consolidated financial statements were prepared assuming that we would continue as a going concern, and therefore contemplate realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these unaudited condensed consolidated financial statements.

Our ability to continue as a going concern is dependent on many factors, including, among other things, the generation by DPC and DMG of sufficient positive operating results to enable DPC and DMG to make certain restricted distributions to their parents, the terms and conditions of an approved plan of reorganization that allows the DH Debtor Entities to emerge from bankruptcy, execution of any further restructuring strategies, and the successful execution of the company-wide cost reduction initiatives that are ongoing. The accompanying unaudited condensed consolidated financial statements do not include any adjustments that might be necessary if the Plan is not successful.

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, 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.

As a result of the Reorganization, our primary sources of internal liquidity are cash flows from operations and cash on hand.  Please read Note 12—Debt for further information.  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. 

Current Liquidity.  The following tables summarize our liquidity position at September 7, 2012 and June 30, 2012.

	September 7, 2012
	DPC			DMG (1)			Other (2)			Total
	(in millions)
LC capacity, inclusive of required reserves (3)	252			34			27			$	313
Less: Required reserves (3)	(8		)	(1		)	(1		)	(10		)
Less: Outstanding letters of credit	(236		)	(29		)	(26		)	(291		)
LC availability	8			4			—			12
Cash and cash equivalents	59			60			561			680
Collateral posting account (4)	238			69						307
Total available liquidity (5)	$	305		$	133		$	561		$	999

42

	June 30, 2012
	DPC			DMG (1)			Other (2)			Total
	(in millions)
LC capacity, inclusive of required reserves (3)	$	298		$	41		$	27		$	366
Less: Required reserves (3)	(9		)	(1		)	(1		)	(11		)
Less: Outstanding letters of credit	(239		)	(29		)	(26		)	(294		)
LC availability	50			11			—			61
Cash and cash equivalents	47			67			542			656
Collateral Posting Account (4)	167			65			—			232
Total available liquidity (5)	$	264		$	143		$	542		$	949

_______________________________________________________________

(1) On June 5, 2012, Dynegy contributed and assigned to us all of its right, title, and interest in and to one hundred percent (100%) of the issued and outstanding membership interests of DMG. At such time, the Undertaking Agreement was terminated with no further obligations. As such, liquidity position amounts for DMG as of September 7, 2012 and June 30, 2012 , but not as of December 31, 2011 are presented.

(2) Other cash consists of $173 million and $173 million at Coal Holdco; $305 million and $305 million at Dynegy Gas Holdco, LLC; $14 million and $11 million at Dynegy Administrative Services Company; $49 million and $52 million at the Company; and $20 million and $1 million at Dynegy Northeast Generation, Inc. as of September 7, 2012 and June 30, 2012.

(3) The LC facilities were collateralized with cash proceeds received under the New Credit Agreements. The amount of the LC availability plus any unused required reserves of 3 percent of 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 September 7, 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.

(4) 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.

(5) 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 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 September 7, 2012, June 30, 2012, and December 31, 2011:

43

	September 7,  2012		June 30, 2012		December 31, 2011
	(in millions)
Dynegy Power, LLC:
Cash	$	91	$	117	$	44
Letters of credit	235		239		386
Total DPC	$	326	$	356	$	430
Dynegy Midwest Generation, LLC:
Cash (1)	$	20	$	23	$	—
Letters of credit	29		29		—
Total DMG	$	49	$	52	$	—
Dynegy Holdings, LLC:
Cash	$	2	$	2	$	—
Letters of credit	26		26		26
Total DH	$	28	$	28	$	26

_______________________________________________________________

(1) Includes Broker margin account on our unaudited condensed consolidated balance sheets, as well as other collateral postings included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets.

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 September 7, 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 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 $13 million and $11 million at September 7, 2012 and June 30, 2012, respectively. The fair value of DPC's derivatives collateralized by first priority liens included liabilities of $104 million and $84 million at September 7, 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 and the use of such instruments entails.

Operating Activities

Historical Operating Cash Flows.  Our cash flow used by operations totaled $107 million for the six months ended June 30, 2012.  During the period, our power generation business used cash of $100 million from the operation of our power generation facilities primarily due to increased collateral postings to satisfy our counterparty collateral demands and interest payments on the DPC Credit Agreement. Corporate and other operations included a use of cash of approximately $7 million primarily due to general and administrative expenses.

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

44

Future Operating Cash Flows.  Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the prices of natural gas, coal, and fuel oil and their correlation to power prices, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, our ability to achieve the cost savings contemplated in our cost reduction programs, our ability to capture value associated with commodity price volatility and the outcome of the Chapter 11 Cases.

Investing Activities

Capital Expenditures.  We had approximately $37 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)	$	11	$	87
Gas	20		40
DNE	—		1
Other and eliminations	6		—
Total	$	37	$	128

_______________________________________________________________

(1) On September 1, 2011, we completed the DMG Transfer. On June 5, 2012, we completed the Coal HoldCo Acquisition. Therefore, capital expenditures are included only from June 6, 2012 to June 30, 2012 for the sixth month period ended June 30, 2012.

Other Investing Activities.In connection with the DMG Acquisition on June 5, 2012, we acquired $256 million in cash and received $16 million related to the Undertaking. There was a $134 million cash inflow related to restricted cash balances during the six months ended June 30, 2012. Other also included $3 million of property insurance claim proceeds.

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

Financing Activities

Historical Cash Flow from Financing Activities.  Cash flow used by financing activities totaled $7 million for the six months ended June 30, 2012 due to repayments of borrowings on the DMG and the DPC Credit Agreements.

Cash flow provided by financing activities totaled $286 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 the Sithe senior debt and $1 million in fees associated with the DPC Credit Agreement and DMG Credit Agreement.

Financing Trigger Events.  The debt instruments and other financial obligations related to our subsidiaries which have not filed for bankruptcy 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 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 DH Debtor Entities included similar trigger events. The DH Debtor Entities do not currently pay interest or make other debt service payments on such pre-petition

45

obligations and the conditions necessary for certain of such trigger events may exist. The DH 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.

Credit Ratings

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

	Standard & Poor	Moody’s	Fitch
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 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 reflected in this report, we have changed our reportable segments. Prior to September 30, 2011, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Beginning with the third quarter 2011, as a result of the Reorganization in August 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 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.

 On September 1, 2011, we completed the DMG Transfer. On June 5, 2012, we completed the DMG Acquisition. Therefore the results of our Coal segment (including DMG) were included for the period of June 6, 2012 through June 30, 2012 and for the three and six month periods ended June 30, 2011.

Consolidated Summary Financial Information — Three Months Ended June 30, 2012

The following table provides summary financial data regarding our consolidated results of operations for the three month

46

periods ended June 30, 2012 and 2011, respectively:

	Three Months Ended June 30,
	2012			2011			$ Change			% Change
	(dollars in millions)
Revenues	$	290		$	326		$	(36	)	(11	)%
Cost of sales	(179		)	(225		)	46			20	%
Gross margin, exclusive of depreciation shown separately below	111			101			10			10	%
Operating and maintenance expense, exclusive of depreciation shown separately below	(63		)	(106		)	43			41	%
Depreciation and amortization expense	(43		)	(75		)	32			43	%
Impairment and other charges	—			(1		)	1			100	%
General and administrative expenses	(17		)	(23		)	6			26	%
Operating loss	(12		)	(104		)	92			88	%
Interest expense	(42		)	(89		)	47			53	%
Bankruptcy reorganization charges	(22		)	—			(22		)	(100	)%
Other income and expense, net	6			3			3			100	%
Loss before income taxes	(70		)	(190		)	120			63	%
Income tax benefit	1			75			(74		)	(99	)%
Net loss	$	(69	)	$	(115	)	$	46		40	%

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			Gas			DNE			Other			Total
	(in millions)
Revenues	$	40		$	230		$	20		$	—		$	290
Cost of sales	(39		)	(131		)	(9		)	—			(179		)
Gross margin, exclusive of depreciation shown separately below	1			99			11			—			111
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(14		)	(35		)	(15		)	1			(63		)
Depreciation and amortization expense	(4		)	(36		)	—			(3		)	(43		)
General and administrative expense	(5		)	(15		)	(1		)	4			(17		)
Operating income (loss)	$	(22	)	$	13		$	(5	)	$	2		$	(12	)

47

	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		)	2			(23		)
Operating loss	$	(47	)	$	(32	)	$	(24	)	$	(1	)	$	(104	)

Discussion of Consolidated Results of Operations

Revenues.  Revenues decreased by $36 million from $326 million for the second quarter 2011 to $290 million for the second quarter 2012.  Of this decrease, $51 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining change is an increase primarily due to higher volumes generated, other revenues and higher mark-to-market gains on forward sales of power and other derivatives for the second quarter 2012 compared to second quarter 2011, partially offset by lower market prices, as well as less revenue from premiums and the financial settlement of derivative instruments, as further described below.

Cost of Sales.  Cost of sales decreased by $46 million from $225 million for the second quarter 2011 to $179 million for the second quarter 2012.  Of this decrease, $57 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining increase is primarily due to the $12 million fair value adjustment of the freight and coal contracts in June 2012.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below.  Operating and maintenance expense decreased by $43 million from $106 million for the second quarter 2011 to $63 million for the second quarter 2012.  Of this decrease, $26 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining $18 million decrease is due primarily to a decrease in lease expense associated with the rejection of the leases of the Roseton and Danskammer power generation facilities.

Depreciation and Amortization Expense.  Depreciation expense decreased by $32 million from $75 million for the second quarter 2011 to $43 million for the second quarter 2012. The decrease is primarily due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012.

General and Administrative Expenses.  General and administrative expenses decreased by $6 million from $23 million for the three months ended June 30, 2011 to $17 million for the three months ended June 30, 2012. The decrease is primarily due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. 

Bankruptcy Reorganization Charges. Bankruptcy reorganization charges for the three months ended June 30, 2012 were approximately $22 million. These charges consist of approximately $14 million for expenses incurred related to our advisors and $8 million related to the change in the value of the Administrative Claim. There were no such charges during the three months ended June 30, 2011. Please read Note 3—Chapter 11 Cases and Note 17—Segment Information for further discussion.

Interest Expense.  Interest expense totaled $42 million and $89 million for the three months ended June 30, 2012 and 2011, respectively.  The decrease was primarily due to the absence of interest related to our unsecured notes and debentures in the three months ended June 30, 2012 as a result of the DH Chapter 11 Cases and the repayment of our prior credit agreement. These decreases were partially offset by interest related to the DPC and DMG Credit Agreements which have higher borrowing

48

rates.

Income Tax Benefit.  We reported an income tax benefit from continuing operations of $1 million for the three month period ended June 30, 2012, compared to an income tax benefit from continuing operations of $75 million for the three months ended June 30, 2011.  The effective tax rate in 2012 was 1 percent, compared to 39 percent for 2011.

For the three month period ended June 30, 2012, the difference between the effective rates of 1 percent and 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 39 percent and the statutory rate of 35 percent resulted primarily from the impact of state taxes.

Discussion of Segment Results of Operations

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 DMG Acquisition, 2012 results only include the results of the Coal segment for the period of June 6, 2012 through June 30, 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	$	42		$	174		$	(132	)	(76	)%
Capacity	—			1			(1		)	(100	)%
Financial transactions:
Mark-to-market loss	(2		)	(65		)	63			97	%
Financial settlements	(1		)	4			(5		)	(125	)%
Option premiums	1			16			(15		)	(94	)%
Total financial transactions	(2		)	(45		)	43			96	%
Other (1)	—			(2		)	2			100	%
Total revenues	40			128			(88		)	(69	)%
Cost of sales	(39		)	(86		)	47			55	%
Gross margin	$	1		$	42		$	(41	)	(98	)%
Million Megawatt Hours Generated	1.7			5.8			(4.1		)	(71	)%
In Market Availability for Coal Fired Facilities (2)	92		%	94		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):	0			0
Indiana (Indy Hub) (4)	$	38		$	44		$	(6	)	(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) The market reference for 2011 was Cinergy (Cin Hub).

Gross margin for Coal decreased by $41 million from $42 million for the three months ended June 30, 2011, to $1 million for the three months ended June 30, 2012.  Approximately $47 million of the decrease is due to the following:

49

• Energy revenue decreased by $19 million and the corresponding cost of sales decreased by $2 million, for a total decrease in energy margin of $17 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. The decrease in cost of sales is due to lower production partially offset by $12 million of amortization of intangible assets related to freight and coal contracts in June 2012.

• Mark-to-market revenue decreased by $10 million from income of $8 million in the second quarter 2011 to a loss of $2 million in the second quarter 2012.

• Premium revenue decreased by $8 million due to a reduction in the number of options sold in the second quarter 2012 compared to the second quarter 2011.

The above decreases were partially offset by an increase of approximately $6 million due to negative gross margin during the three months ended June 30, 2011 that was not repeated in the three months ended June 30, 2012 as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012.

Gas Segment.  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:

50

	Three Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	138		$	107		$	31		29	%
Capacity	54			53			1			2	%
Tolls	19			20			(1		)	(5	)%
RMR	3			1			2			200	%
Natural gas	30			31			(1		)	(3	)%
Financial transactions:
Mark-to-market income (loss)	21			(51		)	72			141	%
Financial settlements	(60		)	(21		)	(39		)	(186	)%
Option premiums	3			30			(27		)	(90	)%
Total financial transactions	(36		)	(42		)	6			14	%
Other (1)	22			8			14			175	%
Total revenues	230			178			52			29	%
Cost of sales	(131		)	(128		)	(3		)	(2	)%
Gross margin	$	99		$	50		$	49		98	%
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):	0			0
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	)%

_______________________________________________________________

(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 $49 million from $50 million for the three months ended June 30, 2011, to $99 million for the three months ended June 30, 2012.  This increase is driven by the following:

• Mark-to-market revenue increased by $72 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 $21 million in the second quarter 2012.

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• 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.

• Other revenue increased by $14 million primarily due to the termination of certain contractual arrangements related to our Gas assets in the West. Please read Note 11—Commitments and Contingencies—SCE Termination for further discussion.

The above increases were partially offset by the following decreases:

• Settlements revenue decreased by $39 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.

DNE Segment.  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:

	Three Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	14		$	18		$	(4	)	(22	)%
Capacity	5			5			—			—	%
Financial transactions:
Mark-to-market loss	(1		)	(13		)	12			92	%
Financial settlements	—			9			(9		)	(100	)%
Financial transactions	(1		)	(4		)	3			75	%
Other (1)	2			1			1			100	%
Total revenues	20			20			—			—	%
Cost of sales	(9		)	(11		)	2			18	%
Gross margin	$	11		$	9		$	2		22	%
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):	0			0
New York—Zone G	$	40		$	56		$	(16	)	(29	)%
Average Market Spark Spreads ($/MWh) (4):	0			0
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

52

fuel oil at a daily cash market price and does not reflect spark spreads available to us.

Gross margin for DNE increased by $2 million from $9 million for the three months ended June 30, 2011, to $11 million for the three months ended June 30, 2012. This increase is driven 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.

The above increase was partially offset by the following:

• Energy revenue and the corresponding cost of sales decreased by $4 million and $2 million respectively for a net decrease in energy margin of $2 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.

Consolidated Summary Financial Information — Six Months Ended June 30, 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	$	565		$	831		$	(266	)	(32	)%
Cost of sales	(365		)	(503		)	138			27	%
Gross margin, exclusive of depreciation shown separately below	200			328			(128		)	(39	)%
Operating and maintenance expense, exclusive of depreciation shown separately below	(112		)	(216		)	104			48	%
Depreciation and amortization expense	(65		)	(201		)	136			68	%
Impairment and other charges	—			(1		)	1			100	%
General and administrative expenses	(37		)	(64		)	27			42	%
Operating loss	(14		)	(154		)	140			91	%
Interest expense	(73		)	(178		)	105			59	%
Bankruptcy reorganization charges	(269		)	—			(269		)	(100	)%
Impairment of Undertaking receivable, affiliate	(832		)	—			(832		)	(100	)%
Other income and expense, net	30			4			26			650	%
Loss from continuing operations before income taxes	(1,158		)	(328		)	(830		)	(253	)%
Income tax benefit	7			133			(126		)	(95	)%
Loss from continuing operations	(1,151		)	(195		)	(956		)	(490	)%
Income from discontinued operations, net of taxes	—			—			—			—	%
Net loss	$	(1,151	)	$	(195	)	$	(956	)	(490	)%

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:

53

	Six Months Ended June 30, 2012
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	40		$	498		$	27		$	—		$	565
Cost of sales	(39		)	(311		)	(15		)	—			(365		)
Gross margin, exclusive of depreciation shown separately below	1			187			12			—			200
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(14		)	(69		)	(30		)	1			(112		)
Depreciation and amortization expense	(4		)	(56		)	—			(5		)	(65		)
General and administrative expense	(5		)	(30		)	(2		)	—			(37		)
Operating income (loss)	$	(22	)	$	32		$	(20	)	$	(4	)	$	(14	)

	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		)	(11		)	(64		)
Operating loss	$	(79	)	$	(19	)	$	(39	)	$	(17	)	$	(154	)

Discussion of Consolidated Results of Operations

Revenues.  Revenues decreased by $266 million from $831 million for the six months ended June 30, 2011 to $565 million for the six months ended June 30, 2012.  Of this decrease, $251 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining decrease is primarily related to lower market prices, as well as less revenue from premiums and the financial settlement of derivative instruments, as further described below. This decrease is offset by higher mark-to-market gains on forward sales of power and other derivatives in 2012 compared to 2011.

Cost of Sales.  Cost of sales decreased by $138 million from $503 million for the six months ended June 30, 2011 to $365 million for the six months ended June 30, 2012.  Of this decrease, $148 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining increase is primarily due to the $12 million fair value adjustment of the freight and coal contracts in June 2012.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below.  Operating and maintenance expense decreased by $104 million from $216 million for the six months ended June 30, 2011 to $112 million for the six months ended June 30, 2012.  Of this decrease, $65 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining decrease of $39 million is due primarily to a decrease in lease expense associated with the rejection of the leases of the Roseton and Danskammer power generation facilities.

Depreciation and Amortization Expense.  Depreciation expense decreased by $136 million from $201 million for the six months ended June 30, 2011 to $65 million for the six months ended June 30, 2012.  Of this decrease, $117 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent

54

DMG Acquisition on June 5, 2012. The remaining decrease of $19 million is primarily due to a $16 million reduction in our asset retirement obligations associated with the South Bay facility in 2012 that is reflected as a reduction in depreciation and amortization expense because South Bay is fully depreciated.

General and Administrative Expenses.  General and administrative expenses decreased $27 million from $64 million for the six months ended June 30, 2011 to $37 million for the six months ended June 30, 2012. Of this decrease, $11 million is due to only one month of Coal activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining decrease of $16 million is primarily the result of lower lease expense, salaries and benefits and other professional services.

Bankruptcy Reorganization Charges. Bankruptcy reorganization charges for the six months ended June 30, 2012 were approximately $269 million. These charges consist of charges of approximately $395 million related to increases in the estimated allowable claims related to the Roseton and Danskammer facilities leases partially offset by reductions of approximately $161 million and $6 million in the estimated allowable claims related to the subordinated debt and other items, respectively. The change in the estimated allowable claims related to the Roseton and Danskammer facilities leases and the subordinated debt are a result of the Settlement Agreement. Additionally, there is approximately $33 million included in the Chapter 11 Cases charges for expenses incurred related to our advisors and $8 million related to the change in the value of the Administrative Claim. There were no such charges during the six months ended June 30, 2011. Please read Note 3—Chapter 11 Cases for further discussion.

Interest Expense.  Interest expense totaled $73 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 related to our unsecured notes and debentures in the six months ended June 30, 2012 as a result of the DH Chapter 11 Cases and the repayment of our prior credit agreement. These decreases were partially offset by interest related to the DPC and DMG Credit Agreements which have higher borrowing rates than our prior credit agreement.

Impairment of Undertaking Receivable. As a result of entering into the Settlement Agreement, the Undertaking receivable was impaired to $418 million as of March 31, 2012, resulting in a charge of approximately $832 million. The carrying value of the Undertaking was adjusted to the value received in the DMG Acquisition plus interest payments received subsequent to March 31, 2012. There were no such charges during the three months ended June 30, 2011.

Other Income and Expense, Net. Other income and expense, net totaled $30 million and $4 million for the the six months ended June 30, 2012 and 2011, respectively. The increase is primarily due to interest income on the Undertaking receivable, affiliate during 2012. The Undertaking was executed on September 1, 2011; therefore, there is no interest income related to the Undertaking during the six months ended June 30, 2011.

Income Tax Benefit.  We reported an income tax benefit from continuing operations of $7 million for the six month period ended June 30, 2012, compared to an income tax benefit from continuing operations of $133 million for the six months ended June 30, 2011.  The effective tax rate in 2012 was 1 percent, compared to 41 percent in 2011.

For the six month period ended June 30, 2012, the difference between the effective rate of 1 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 month period ended June 30, 2011, the difference between the effective rates of 41 percent and the statutory rate of 35 percent resulted primarily from the impact of state taxes which included a benefit of $6 million related to an increase in state NOLs due to the acceptance of amended returns, partially offset by an expense of $2 million related to an increase in the Illinois statutory rate. 

Discussion of Segment Results of Operations

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, as a result of the DMG Acquisition, 2012 results only include the results of the Coal segment for the period of June 6, 2012 through June 30, 2012. 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:

55

	Six Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	42		$	363		$	(321	)	(88	)%
Capacity	—			2			(2		)	(100	)%
Financial transactions:	—			—			—			—
Mark-to-market loss	(2		)	(72		)	70			97	%
Financial settlements	(1		)	21			(22		)	(105	)%
Option premiums	1			16			(15		)	(94	)%
Total Financial transactions	(2		)	(35		)	33			94	%
Other (1)	—			(2		)	2			100	%
Total revenues	40			328			(288		)	(88	)%
Cost of sales	(39		)	(177		)	138			78	%
Gross margin	$	1		$	151		$	(150	)	(99	)%
Million Megawatt Hours Generated	1.7			11.8			(10.1		)	(86	)%
In Market Availability for Coal Fired Facilities (2)	92		%	93		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):	0			0
Indiana (Indy Hub) (4)	$	38		$	42		$	(4	)	(10	)%

_______________________________________________________________

(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 $150 million from $151 million for the six months ended June 30, 2011, to $1 million for the six months ended June 30, 2012.  Approximately $103 million of this decrease is due toonly one month of activity included in 2012 results as a result of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. The remaining decrease of $47 million is driven primarily by the following:

• Energy revenue decreased by $19 million and the corresponding cost of sales decreased by $2 million, for a total decrease in energy margin of $17 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. The decrease in cost of sales is due to lower production partially offset by $12 million of amortization of intangible assets related to freight and coal contracts in June 2012.

• Mark-to-market revenue decreased by $10 million from income of $8 million in the second quarter 2011 to a loss of $2 million in the second quarter 2012.

• Premium revenue decreased by $8 million due to a reduction in the number of options sold in the second quarter 2012 compared to the second quarter 2011.

Gas Segment.  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	101			109			(8		)	(7	)%
Tolls	39			39			—			—	%
RMR	4			2			2			100	%
Natural gas	62			95			(33		)	(35	)%
Financial transactions:
Mark-to-market income (loss)	64			(31		)	95			306	%
Financial settlements	(101		)	(34		)	(67		)	(197	)%
Option premiums	2			31			(29		)	(94	)%
Total financial transactions	(35		)	(34		)	(1		)	(3	)%
Other (1)	30			16			14			88	%
Total revenues	498			445			53			12	%
Cost of sales	(311		)	(293		)	(18		)	(6	)%
Gross margin	$	187		$	152		$	35		23	%
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):	0			0
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):	0			0
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		$	(1.90	)	(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 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 $35 million from $152 million for the six months ended June 30, 2011, to $187 million for the six months ended June 30, 2012.  This increase is driven by the following:

• 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

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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 $95 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 $64 million in the six months ended June 30, 2012.

• Other revenue increased by $14 million primarily due to the termination of certain contractual arrangements related to our Gas assets in the West. Please read Note 11—Commitments and Contingencies—SCE Termination for further discussion.

The above increases were partially offset by the following:

• Capacity revenue decreased by $8 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 $67 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.  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:

	Six Months Ended June 30,
	2012			2011			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	18		$	52		$	(34	)	(65	)%
Capacity	7			9			(2		)	(22	)%
Financial transactions:
Mark-to-market loss	(1		)	(23		)	22			96	%
Financial settlements	—			18			(18		)	(100	)%
Total financial transactions	(1		)	(5		)	4			80	%
Other (1)	3			2			1			50	%
Total revenues	27			58			(31		)	(53	)%
Cost of sales	(15		)	(33		)	18			55	%
Gross margin	$	12		$	25		$	(13	)	(52	)%
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):	0			0
New York—Zone G	$	39		$	60		$	(21	)	(35	)%
Average Market Spark Spreads ($/MWh) (4):
Fuel Oil	$	(156	)	$	(115	)	$	(41	)	(36	)%

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_______________________________________________________________

(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 decreased by $13 million from $25 million for the six months ended June 30, 2011, to $12 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 $34 million and $18 million, respectively, for a net decrease in energy margin of $16 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 us.

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. Only the DH Debtor Entities, and our parent Dynegy sought protection from creditors, and none of our other subsidiaries are debtors under Chapter 11 of the Bankruptcy Code. 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 of our other subsidiaries other than the applicable DH 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. On September 1, 2011, we completed the DMG Transfer. On June 5, 2012, the effective date of the Settlement Agreement, we completed the DMG Acquisition. Therefore, the results of our Coal segment (including DMG) were only included in our consolidated results for the period of June 6, 2012 through June 30, 2012. Please read Note 3—Chapter 11 Cases for further information.

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 unpriced contracted volumes are subject to a price collar structure.  Our coal transportation requirements are 100 percent contracted and priced through 2013 when our current contracts expire. In August 2012, we 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 78 percent hedged through 2012 and approximately 17 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.

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.

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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 process of 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.

Currently, our Gas portfolio is approximately 94 percent hedged volumetrically through 2012 and approximately 52 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

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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.

Environmental and Regulatory Matters

Please read Item 1. Business-Environmental Matters in our Form 10-K for the period ended December 31, 2011 for a detailed discussion of our environmental and regulatory matters.

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	$	(182	)
Risk-management losses recognized through the income statement in the period, net	(40		)
Cash paid related to risk-management contracts settled in the period, net	89
DMG Acquisition (2)	10
Fair value of portfolio at June 30, 2012	$	(123	)

_______________________________________________________________

(1) Our modeling methodology has been consistently applied.

(2)     On June 5, 2012, we completed the DMG Acquisition. Please read Note 4—DMG Acquisition for further discussion.

The net risk management liability of $123 million is the aggregate of the following line items on our unaudited condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures.  The following table provides an assessment of net contract values by year as of June 30, 2012, based on our valuation methodology:

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Net Fair Value of Risk-Management Portfolio

	Total			2012			2013			2014			2015			2016			Thereafter
	(in millions)
Market quotations (1) (2)	$	(98	)	$	(95	)	$	(3	)	$	—		$	—		$	—		$	—
Prices based on models (2)	(25		)	(8		)	8			(12		)	(9		)	(4		)	—
Total	$	(123	)	$	(103	)	$	5		$	(12	)	$	(9	)	$	(4	)	$	—

_______________________________________________________________

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

(2)   The market quotations and prices based on models categorization differ from the categories of Level 1, Level 2 and Level 3 used in our fair value disclosures due to the application of the different methodologies.  Please read Note 7—Fair Value Measurements for further discussion.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements”.  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 consummate one or more plans of reorganization 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;

• 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;

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• 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, including those set forth under and Item 1A-Risk Factors of our Form 10-K.

CRITICAL ACCOUNTING POLICIES

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

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 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

	June 30, 2012		December 31, 2011
	(in millions)
One day VaR—95 percent confidence level	$	9	$	8
One day VaR—99 percent confidence level	$	12	$	12
Average VaR for the year-to-date period—95 percent confidence level	$	10	$	5

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

Credit Exposure Summary

	Investment Grade Quality		Non-Investment Grade Quality		Total
	(in millions)
Type of Business:
Financial institutions	$	8	$	—	$	8
Oil and gas producers	—		—		—
Utility and power generators	34		—		34
Commercial / industrial / end users	1		9		10
Total	$	43	$	9	$	52

Interest Rate Risk.  We are exposed to fluctuating interest rates related to variable rate financial obligations.  As of June 30, 2012, all of our third party debt was considered variable rate debt. We use a variety of instruments, including interest rate swaps and caps, to mitigate this interest rate exposure.  Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of June 30, 2012, to the extent LIBOR remains below 1.5 percent, which represents the interest rate floor in DPC and DMG Credit Agreement, LIBOR changes will have no impact to interest expense over the twelve months ended March 31, 2013.  We estimate that increases in LIBOR to ranges between 1.5 percent and 2 percent will result in up to $8 million in increased interest expense over the twelve months ended June 30, 2013.  It is estimated that a one percentage point interest rate movement in the average market interest rates would change interest expense by up to an additional $3 million to the extent LIBOR exceeds 2 percent, which represents the interest rate when certain hedging instruments become effective.  This exposure would have been partially offset by an approximate $6 million increase or decrease in interest income related to the restricted cash balance of $597 million posted as collateral to support our letter of credit facilities.  Over time, we may seek to adjust the variable rate exposure in our debt portfolio through the use of swaps or other financial instruments.  Please read Note 3—Chapter 11 Cases for further discussion.

The absolute notional financial contract amounts associated with our interest rate contracts were as follows at June 30, 2012 and December 31, 2011, respectively:

	June 30, 2012		December 31, 2011
Interest rate risk-management contracts (in millions of U.S. dollars)	$	1,100	$	788
Fixed interest rate paid (percent)	2.22		2.21
Interest rate risk-management contracts (in millions of U.S. dollars)(1)	$	1,400	$	900
Interest rate threshold (percent) (1)	2.00		2.00

_______________________________________________________________

 (1) The $1,100 million interest rate contracts are not effective until the fourth quarter 2013.

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

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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 HOLDINGS, LLC

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

See Note 11—Commitments and Contingencies—Legal Proceedings to the accompanying unaudited condensed consolidated financial statements for a discussion of the legal proceedings that we believe could be material to us.

Item 1A—RISK FACTORS

Please read Item 1A—Risk Factors, of our Form 10-K, filed September 14, 2012, for factors, risks and uncertainties that may affect future results.

Item 3—DEFAULTS UPON SENIOR SECURITIES

The filing of the DH Chapter 11 Cases constitutes or may constitute an event of default or otherwise triggers or may trigger repayment obligations under the express terms of certain instruments and agreements relating to direct financial obligations of certain of the DH Debtor Entities or obligations under off-balance sheet arrangements (the “Debt Documents”).  As a result of such an event of default or triggering event, all obligations under the Debt Documents, by the terms of the Debt Documents, have or may become due and payable, subject to the provisions of the Bankruptcy Code.  The DH Debtor Entities believe that any efforts to enforce such payment obligations against the DH Debtor Entities under the Debt Documents are stayed as a result of the filing of the DH Chapter 11 Cases in the Bankruptcy Court.  The material Debt Documents, and the approximate principal amount of debt currently outstanding thereunder, include the following:

• Our (i) 8.75% senior unsecured notes due on February 15, 2012, (ii) 7.5% senior unsecured notes due on June 1, 2015, (iii) 8.375% senior unsecured notes due on May 1, 2016, (iv) 7.75% senior unsecured notes due on June 1, 2019, (v) 7.125% senior debentures due May 15, 2018 and (vi) 7.625% senior debentures due October 15, 2026, issued under the Indenture dated September 26, 1996, as amended and restated as of March 14, 2001, and under the First through Sixth Supplemental Indentures thereto, between us and Wilmington Trust Company (as successor to JP Morgan Chase Bank, N .A., successor to Bank One Trust Company, National Association), as trustee, in the outstanding aggregate principal amount of $3.37 billion.

• Our Series B 8.316% Subordinated Capital Income Securities issued under the Indenture dated May 28, 1997, between NGC Corporation (a predecessor of the Company) and the First National Bank of Chicago, as trustee, as amended and restated, in the outstanding aggregate principal amount of $200 million.

• Our $26 million cash collateralized letter of credit facility between us and Credit Suisse AG, Cayman Islands Branch, which is collateralized by an account maintained by Bank of New York Mellon holding the sum of $27 million.

• Roseton and Danskammer’s sale-leaseback arrangements under which the rent payments paid by each of them are assigned to an indenture trustee for the respective facility.  The indenture trustee then pays a portion of those payments to each of two pass-through trusts, and such pass-through trusts pay these amounts to holders of certificates in the pass-through trusts.  The current total outstanding principal of the certificates is approximately $550 million.

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Item 6—EXHIBITS

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

Exhibit Number	Description
2.1	Confirmation Order for Dynegy Inc. and Dynegy Holdings, LLC, as entered by the Bankruptcy Court on September 10, 2012 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on September 13, 2012, File No. 001-33443).
10.1	Assignment Agreement by and among Dynegy Gas Investments, LLC, Dynegy Holdings, LLC and Dynegy Inc. dated September 1, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings, LLC filed on September 8, 2011, File No. 000-29311).
10.2	Restructuring Support Agreement, dated November 7, 2011, among Dynegy Inc., Dynegy Holdings, LLC and certain beneficial holders of notes issued by Dynegy Holdings, LLC (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on November 8, 2011, File No. 001-33443).
10.3	Restructuring Support Agreement, dated November 7, 2011, among Dynegy Inc., Dynegy Holdings, LLC and certain beneficial holders of notes issued by Dynegy Holdings, LLC (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on November 8, 2011, File No. 001-33443).
10.4	First Amendment to the Restructuring Support Agreement, dated December 9, 2011 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings,  LLC filed on December 9, 2011, File No. 001-33443).
10.5	Second Amendment to the Restructuring Support Agreement, dated December 16, 2011 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings,  LLC filed on December 20, 2011, File No. 001-33443).
10.6	Amended and Restated Restructuring Support Agreement, dated December 26, 2011 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings,  LLC filed on December 27, 2011, File No. 001-33443).
10.7	Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC proposed by Dynegy Holdings, LLC and Dynegy Inc., dated December 1, 2011 (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on December 2, 2011, File No. 001-33443).
10.8	Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC proposed by Dynegy Holdings, LLC and Dynegy Inc., dated January 19, 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 January 23, 2012, File No. 001-33443).
10.9	Second Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC proposed by Dynegy Holdings, LLC and Dynegy Inc., dated March 6, 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 March 7, 2012, File No. 001-33443).
10.10	Description of the Plan Secured Notes, as Exhibit C to the Plan of Reorganization, dated December 23, 2011 (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on December 27, 2011, File No. 001-33443).
10.11	Description of the Plan Secured Notes, as Exhibit C to the Amended Plan of Reorganization, dated January 19, 2012 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on January 23, 2012, File No. 001-33443).
10.12	Description of the Plan Secured Notes, as Exhibit C to the Second Amended Plan of Reorganization, dated March 6, 2012 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on March 7, 2011, File No. 001-33443).

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10.13	Certificate of Designation for the Plan Preferred Stock, as Exhibit D to the Plan of Reorganization dated December 23, 2011 (incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on December 27, 2011, File No. 001-33443).
10.14	Certificate of Designation for the Plan Preferred Stock, as Exhibit D to the Second Amended Plan of Reorganization, dated March 6, 2012 (incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on March 7, 2012, File No. 001-33443).
10.15	Disclosure Statement Related to the Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC Proposed by Dynegy Holdings, LLC and Dynegy Inc. (incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on December 2, 2011, File No. 001-33443).
10.16	Disclosure Statement Related to the Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC Proposed by Dynegy Holdings, LLC and Dynegy Inc., dated January 19, 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 January 23, 2012, File No. 001-33443).
10.17	Disclosure Statement Related to the Second Amended Chapter 11 Plan of Reorganization for Dynegy Holdings, LLC Proposed by Dynegy Holdings, LLC and Dynegy Inc., dated March 6, 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 March 7, 2012, File No. 001-33443).
10.18	Dynegy Inc., Dynegy Holdings, LLC and certain of its affiliates and subsidiaries and Resources Capital Management Corporation and certain of its affiliates and subsidiaries Binding Term Sheet, dated December 13, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on December 14, 2011, File No. 001-33443).
10.19	Settlement Agreement, dated May 1, 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 2, 2012, File No. 0001-33443).
10.20	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).
10.21	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).
10.22	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).
10.23	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).
10.24	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).

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10.25	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).
10.26	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).
10.27	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).
10.28	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).
10.29	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 HOLDINGS, LLC

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 HOLDINGS, LLC
Date: September 17, 2012	By:	/s/ CLINT C. FREELAND
		Clint C. Freeland Executive Vice President and Chief Financial Officer

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