UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K


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

For the fiscal year ended December 31, 2011


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

For the transition period from ________ to ________

DYNEGY HOLDINGS, LLC

(Exact name of registrant as specified in its charter)

(713) 507-6400

(Registrant's telephone number, including area code)

Securities registered pursuant to Section12(b) of the Act:




Title of each class		Name of each exchange on which registered
None		-

Securities registered pursuant to Section12(g) of the Act:



		None
		(Title of Class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý

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

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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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 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 the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

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

All of the registrant’s outstanding membership interests are owned directly by Dynegy Inc.

DOCUMENTS INCORPORATED BY REFERENCE

None

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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 for a discussion of these developments. Further, additional disclosures regarding such developments can be found throughout each of these reports. For recent information regarding our financial condition and results of operations, please read our quarterly report on Form 10-Q for the second quarter of 2012.

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DYNEGY HOLDINGS, LLC

FORM 10-K

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		Page
PART I
Definitions		1
Item 1.	Business	4
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	33
Item 2.	Properties	33
Item 3.	Legal Proceedings	33
Item 4.	Mine Safety Disclosures	33
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 6.	Selected Financial Data	34
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	69
Item 8.	Financial Statements and Supplementary Data	72
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
Item 9A.	Controls and Procedures	73
	Report of Independent Registered Public Accounting Firm
Item 9B.	Other Information	73
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	74
Item 11.	Executive Compensation	74
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	74
Item 13.	Certain Relationships and Related Transactions, and Director Independence	74
Item 14.	Principal Accountant Fees and Services	74
PART IV
Item 15.	Exhibits and Financial Statement Schedules	74
Signatures		88

PART I

DEFINITIONS

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 as presented in our consolidated financial statements, unless the context clearly indicates otherwise. The term “Dynegy” refers to our parent company, Dynegy Inc., unless the context clearly indicates otherwise.

As used in this Form 10-K, the abbreviations listed below have the following meanings:



AMT	Alternative Minimum Tax
ARO	Asset retirement obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
BACT	Best Available Control Technology (air)
BART	Best Available Retrofit Technology
BTA	Best technology available (water intake)
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
CFTC	U.S. Commodity Futures Trading Commission
CSAPR	Cross State Air Pollution Rule
CAVR	The Clean Air Visibility Rule
CCR	Coal Combustion Residuals
CERCLA	The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CO2	Carbon dioxide
CO2e	The climate change potential of other GHGs relative to the global warming potential of CO2
CPUC	California Public Utility Commission
CRM	Our former customer risk management business segment
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
DCIH	Dynegy Coal Intermediate Holdings, LLC
DGIN	Dynegy Gas Investments, LLC
DH	Dynegy Holdings, LLC (formerly known as Dynegy Holdings Inc.)
DH Debtor Entities	DH, Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C. and Dynegy Roseton, L.L.C.
DMG	Dynegy Midwest Generation, LLC
DMSLP	Dynegy Midstream Services L.P.
DMT	Dynegy Marketing and Trade, LLC
DPC	Dynegy Power, LLC
DYPM	Dynegy Power Marketing Inc.
EGU	Electric generating unit
EPA	United States Environmental Protection Agency
ERISA	The Employee Retirement Income Security Act of 1974, as amended
EWG	Exempt Wholesale Generator

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FASB	Financial Accounting Standards Board
FCM	Forward Capacity Market
FERC	Federal Energy Regulatory Commission
FTR	Financial Transmission Rights
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
ICAP	Installed capacity
IMA	In-Market Availability
IRS	Internal Revenue Service
ISO	Independent System Operator
ISO-NE	Independent System Operator—New England
LMP	Locational Marginal Pricing
LPG	Liquefied petroleum gas
MACT	Maximum achievable control technology
MGGA	Midwest Greenhouse Gas Accord
MGGRP	Midwestern Greenhouse Gas Reduction Program
MISO	Midwest Independent Transmission System Operator
MMBtu	Millions of British thermal units
MRTU	Market Redesign and Technology Update
MW	Megawatts
MWh	Megawatt hour
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NGX	Natural Gas Exchange Inc.
NOL	Net operating loss
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NRG	NRG Energy, Inc.
NSPS	New Source Performance Standard
NYISO	New York Independent System Operator
NYSDEC	New York State Department of Environmental Conservation
NYSE	New York Stock Exchange
OCI	Other Comprehensive Income
OTC	Over-the-counter
PJM	PJM Interconnection, LLC
PPEA	Plum Point Energy Associates
PPEA Holding	Plum Point Energy Associates Holding Company, LLC
PRB	Powder River Basin
PSD	Prevention of Significant Deterioration
PURPA	The Public Utility Regulatory Policies Act of 1978
PY	Planning Year
QF	Qualifying Facility
RACT	Reasonably Available Control Technology
RCRA	The Resource Conservation and Recovery Act of 1976, as amended

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RFO	Request for offer
RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must Run
RPM	Reliability Pricing Model
RTO	Regional Transmission Organization
SCEA	Sandy Creek Energy Associates, LP
SEC	U.S. Securities and Exchange Commission
SCR	Selective Catalytic Reduction
SIP	State Implementation Plan
SO2	Sulfur dioxide
SPDES	State Pollutant Discharge Elimination System
VaR	Value at Risk
VIE	Variable Interest Entity
VLGC	Very large gas carrier
WCI	Western Climate Initiative
WECC	Western Electricity Coordinating Council

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Item 1. Business

THE COMPANY

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our primary business is the production and sale of electric energy, capacity and ancillary services from our fleet of ten operating power plants in six states totaling approximately 8,464 MW of generating capacity, as of December 31, 2011. Effective September 1, 2011, we transferred our Coal segment, which included approximately 3,100 MW, to our parent, Dynegy On June 5, 2012, the effective date of the Settlement Agreement (as defined and discussed below in Note 3 to our financial statements), we reacquired the Coal segment. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement and Note 27—Subsequent Events for further discussion.

We are a wholly-owned subsidiary of Dynegy, which began operations in 1984 and became incorporated in the State of Delaware in 2007. Our principal executive office is located at 601 Travis Street, Suite 1400, Houston, Texas 77002, and our telephone number at that office is (713) 507-6400.

We file annual, quarterly and current reports, and other information with the SEC. You may read and copy any document we file at the SEC's Public Reference Room at 100 F Street N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the SEC's Public Reference Room. Our SEC filings are also available to the public at the SEC's web site at www.sec.gov. No information from such web site is incorporated by reference herein. Our SEC filings are also available free of charge on Dynegy's web site at www.dynegy.com, as soon as reasonably practicable after those reports are filed with or furnished to the SEC. The contents of that website are not intended to be, and should not be considered to be, incorporated by reference into this Form 10-K.

We sell electric energy, capacity and ancillary services on a wholesale basis from our power generation facilities. Energy is the actual output of electricity and is measured in MWh. The capacity of a power generation facility is its electricity production capability, measured in MW. Wholesale electricity customers will, for reliability reasons and to meet regulatory requirements, contract for rights to capacity from generating units. Ancillary services are the products of a power generation facility that support the transmission grid operation, follow real-time changes in load and provide emergency reserves for major changes to the balance of generation and load. We sell these products individually or in combination to our customers under short-, medium- and long-term agreements and hedging arrangements.

Our customers include RTOs and ISOs, integrated utilities, municipalities, electric cooperatives, transmission and distribution utilities, industrial customers, power marketers, financial participants such as banks and hedge funds, other power generators and commercial end-users. All of our products are sold on a wholesale basis for various lengths of time from hourly to multi-year transactions. Some of our customers, such as municipalities or integrated utilities, purchase our products for resale in order to serve their retail, commercial and industrial customers. Other customers, such as some power marketers, may buy from us to serve their own wholesale or retail customers or as a hedge against power sales they have made.

Our Power Generation Portfolio

Our operating generating facilities at December 31, 2011 are as follows:

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Facility	Total Net Generating Capacity (MW)(1)	Primary Fuel Type	Dispatch Type	Location	Region
Moss Landing Units 1-2	1,020	Gas	Intermediate	Monterey County, CA	CAISO
Units 6-7	1,509	Gas	Peaking	Monterey County, CA	CAISO
Kendall	1,200	Gas	Intermediate	Minooka, IL	PJM
Ontelaunee	580	Gas	Intermediate	Ontelaunee Township, PA	PJM
Morro Bay(2)	650	Gas	Peaking	Morro Bay, CA	CAISO
Oakland	165	Oil	Peaking	Oakland, CA	CAISO
Casco Bay	540	Gas	Intermediate	Veazie, ME	ISO-NE
Independence	1,064	Gas	Intermediate	Scriba, NY	NYISO
Black Mountain(3)	43	Gas	Baseload	Las Vegas, NV	WECC
Total Gas Segment	6,771
Danskammer Units 1-2	123	Gas/Oil	Peaking	Newburgh, NY	NYISO
Units 3-4	370	Coal/Gas	Baseload	Newburgh, NY	NYISO
Roseton(4)	1,200	Gas/Oil	Peaking	Newburgh, NY	NYISO
Total DNE Segment	1,693
Total Fleet Capacity	8,464

_______________________________________________________________________________


(1)	Unit capabilities are based on winter capacity.

(2) Represents Units 3 and 4 generating capacity. Units 1 and 2, with a combined net generating capacity of 352 MW, are currently in mothball status and out of operation.

(3) We indirectly own a 50 percent interest in this facility. Total output capacity of this facility is 85 MW.

(4) The Roseton facility and Units 3 and 4 of the Danskammer facility were leased by the Company. Please read Note 3—Chapter 11 Cases for further discussion.

On June 5, 2012, the effective date of the Settlement Agreement, we reacquired the Coal segment constituting 3,132 MW. Please read Note 3—Chapter 11 Cases for further discussion.

Business Strategy

Our business strategy is to create value through the safe, reliable and cost-efficient operation of our power generation assets. During 2011, we completed the Reorganization (as defined and discussed below) to better align our business around our and Dynegy's generation assets and to more aggressively drive both financial and operational efficiencies across the Company. We manage our generation assets by fuel type with three primary reportable segments: (i) the Coal segment ("Coal"), (ii) the Gas segment ("Gas") and (iii) the Dynegy Northeast Segment ("DNE"). As further described below, we transferred the Coal segment to our parent, Dynegy, effective September 1, 2011 and subsequently transferred from Dynegy back to us, effective June 5, 2012. Please read Note 3—Chapter 11 Cases for further discussion.

There are four primary elements to our strategy:


•	Operational Excellence—Operating our power plants in a safe, reliable, and environmentally compliant manner with a particular focus on increasing cash flow and optimizing availability;


•	Commercial Execution—Optimizing the commercial results of the assets through proactive management of our power, fuel, capacity, and ancillary service positions with short-, medium-, and long-term agreements and hedging arrangements;


•	Corporate and Organizational Support—Maximizing organizational effectiveness and efficiency through continuous business process improvements, operational enhancements, and cost management; and


•	Capital Structure Management—Creating a sustainable and flexible capital structure with diversified liquidity sources to efficiently support our commercial activities.

Operational Excellence. We operate a portfolio of generation assets that is diversified in terms of dispatch profile, fuel type and geography. Our Coal segment, which was transferred on September 1, 2011 to Dynegy Inc, is primarily a fleet of baseload coal facilities, located in Illinois, that dispatch around the clock throughout the year. Our Gas segment operates both intermediate and peaking natural gas plants, located in the Midwest, Northeast and California. The intermediate gas plants tend to be dispatched during periods of elevated electricity demand because their operational flexibility enables them to respond quickly to changes in market conditions. In addition to generating power, these assets also generate capacity revenues through

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structured markets or bilateral tolling agreements, as local utilities and ISOs seek to ensure sufficient generation capacity is available to meet future market demands. Peaking facilities are generally dispatched to serve load only during the highest periods of power demand, such as hot summer and cold winter days. In addition to the peaking plants within our Gas segment, our DNE segment manages three peaking units as well as two coal-fired generation units in New York.

We have historically achieved strong plant operations and are committed to operating all of our facilities in a safe, reliable, cost-efficient and environmentally compliant manner. We have dedicated significant resources toward these priorities with approximately $1 billion invested over the past several years in our Coal segment for environmental compliance initiatives to meet contractual obligations and state and federal environmental standards. In addition, we continue to invest approximately $90 million annually across all segments to maintain and improve the safety, reliability, and efficiency of the fleet. The above described reorganization of our segments by fuel type helps facilitate and realize best operating practices across the respective portfolios, leading to additional cost efficiencies and improved operating practices.

Commercial Execution. Our commercial strategy seeks to optimize the value of our assets by locking in near-term cash flow while preserving the ability to capture higher values longer-term as power markets improve. We seek to capture both intrinsic as well as extrinsic value of the coal and gas portfolios. Intrinsic value is represented by cash flow generated from selling power at market prices; extrinsic value is represented by characteristics of our fleet that can generate incremental economics due to market volatility, differences in counterparties' views of forward prices and other market conditions. In order to execute our commercial strategy, we utilize a wide range of products and contracts such as tolling agreements, fuel supply contracts, capacity auctions, bilateral capacity contracts, power and natural gas swap agreements, power and natural gas options and other financial instruments.

Power prices have fallen significantly over the past few years primarily as a result of the decline in natural gas prices and a weakened national economy. Despite these near-term dynamics, we continue to believe that, over the longer-term, power demand and power pricing will improve as the economy rebounds, marginal generating units retire, and more stringent environmental regulations force the retirement of power generation units that have not invested in environmental upgrades. As a result, we believe our coal-fired baseload fleet, with its environmental upgrades, is positioned to benefit from higher power prices in the Midwest. We also believe these same factors will benefit our combined cycle units through increased run-times and higher power prices as heat rates expand resulting in improved margins and cash flows.

We volumetrically hedge the expected output from our facilities over a rolling one- to three-year time frame with the goal of stabilizing near-term earnings and cash flow while preserving upside potential should commodity prices or market factors improve. We manage our hedging program within the limits of our available liquidity sources. These sources include cash, letter of credit capacity, and the recently reinstituted first lien collateral structure with select counterparties, which have provided substantially more liquidity. We expect to broaden the use of this collateral structure to include additional counterparties in the future. While this initiative provides an alternative source of liquidity support, it also removes significant liquidity risk as fluctuations in commodity prices no longer impact cash balances and letter of credit availability. As a result, we have the ability to execute more sizeable and longer-term hedges when market opportunities arise.

Capital Structure Management. The power industry is a cyclical commodity business with significant price volatility and considerable capital investment requirements. As such, it is imperative to build and maintain a balance sheet characterized by manageable debt levels and a multi-faceted liquidity program. We have undertaken to restructure our long-term debt and lease obligations through the DH Chapter 11 Cases. We anticipate that the Debtor Entities (as defined below) will emerge from bankruptcy during 2012 having achieved a more sustainable leverage profile that provides sufficient flexibility to manage and grow the business throughout the commodity cycle. We are also focused on building a more diverse liquidity program to support our ongoing operations and commercial activities. In addition to our existing cash balances and letter of credit facilities, we are actively pursuing additional liquidity including the expansion of our first lien collateral program with additional hedging counterparties and other options that add liquidity for general corporate purposes to ensure that we have the financial resources to deliver on all of our strategic initiatives.

Reorganization

In August 2011, our parent, Dynegy, completed an internal reorganization of its subsidiaries, including us (the "Reorganization"), as a result of which (i) substantially all of the coal-fired power generation facilities are held by Dynegy Midwest Generation, LLC ("DMG"), (ii) substantially all of the natural gas-fired power generation facilities are held by Dynegy Power, LLC ("DPC"), an indirect wholly-owned subsidiary of the Company and (iii) we hold 100 percent of the ownership interests in Dynegy Northeast Generation, the entity that indirectly holds the equity interests in the subsidiaries that operate the Roseton and Danskammer power generation facilities, including the leased units. As a result of the Reorganization, DPC owns a portfolio of eight primarily natural gas-fired intermediate (combined cycle) and peaking (combustion and steam turbines) power generation facilities diversified across the West, Midwest and Northeast regions of the United States, totaling 6,771 MW of generating capacity. DMG owns a portfolio of six primarily coal-fired baseload power generation facilities

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located in the Midwest, totaling 3,132 MW of generating capacity.

The DPC and DMG asset portfolios were designed to (i) leverage best practices across our fleet and (ii) be separately financeable and bankruptcy remote. On August 5, 2011, DPC and its parent Dynegy Gas Investments Holdings, LLC ("DGIH"), each an indirect subsidiary of the Company, entered into a $1.1 billion, five-year senior secured term loan facility (the "DPC Credit Agreement"). The same day, DMG and its parent Dynegy Coal Investments Holdings, LLC, each then also an indirect subsidiary of the Company, entered into a $600 million, five-year senior secured term loan facility (the "DMG Credit Agreement" and together with the DPC Credit Agreement, the "Credit Agreements"). Proceeds from these Credit Agreements enabled us to repay our outstanding indebtedness under the Company's Fifth Amended and Restated Credit Agreement and Sithe Senior Notes, and are available to DPC and DMG to be used for general working capital and general corporate purposes. Please read Note 20—Debt—DMG Credit Agreement and —DPC Credit Agreement for further discussion of the Credit Agreements. Our remaining assets (including our leasehold interests in the Danskammer and Roseton facilities) are not a part of either DPC or DMG. Effective September 1, 2011, we transferred our Coal segment (including DMG) to Dynegy. Please read Note 3—Chapter 11 Cases for further discussion.

Overview of Bankruptcy Remote and Ring-Fencing Measures. The Reorganization 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 Reorganization, some companies within our portfolio were reorganized into “ring-fenced” groups. The upper-level companies in such ring-fenced groups are bankruptcy-remote entities governed by limited liability company operating agreements which, in addition to the bankruptcy remoteness provisions described above, contain certain additional restrictions prohibiting any material transactions with affiliates other than the direct and indirect subsidiaries within the ring-fenced group without independent manager approval.

DMG Transfer. On September 1, 2011, Dynegy and Dynegy Gas Investments, LLC ("DGIN"), a wholly-owned subsidiary, entered into a Membership Interest Purchase Agreement whereby DGIN transferred 100 percent of its outstanding membership interests of Dynegy Coal Holdco, LLC ("Coal Holdco") which, through DMG, owns the majority of our and our affiliates' portfolio of primarily coal-fired generation facilities, to Dynegy (the "DMG Transfer"). In exchange for Coal Holdco, Dynegy agreed to make certain specified payments (aggregating approximately $2.1 billion through October 15, 2026) to DGIN over time which coincide in timing and amount to the payments of principal and interest that we were obligated to make with respect to a portion of certain of our senior notes (the "Undertaking Agreement"). DGIN assigned its rights to receive payments under the Undertaking Agreement to us in exchange for a promissory note (the "Promissory Note") in the amount of $1.25 billion that matures in 2027 (the "Assignment"). As a condition to Dynegy's consent to the Assignment, the Undertaking Agreement was amended and restated to be between us and Dynegy and to provide for the reduction of Dynegy's obligations if the outstanding principal amount of the senior notes decreases as a result of any exchange offer, tender offer or other purchase or repayment by Dynegy or its subsidiaries (other than us and our subsidiaries, unless Dynegy guarantees our or our subsidiaries' debt securities in connection with such exchange offer, tender offer or other purchase or repayment); provided that such principal amount is retired, cancelled or otherwise forgiven. On June 5, 2012, the effective date of the Settlement Agreement, we reacquired Coal Holdco. At such time the Undertaking Agreement and Promissory Note were terminated with no further obligations thereunder. For further discussion, please read Note 21—Related Party Transactions—DMG Transfer and Undertaking Agreement and Note 3—Chapter 11 Cases.

Chapter 11 Cases

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 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, Case No. 12-36728. Only the DH Debtor Entities and our parent Dynegy (collectively, the "Debtor Entities") 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. 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 of reorganization, the amended and restated settlement agreement (the "Settlement Agreement") and the amended and restated plan support agreement (the "Plan Support Agreement") (as each described in Note 3—Chapter 11 Cases), including the planned merger of DH with and into Dynegy (the “Merger”).

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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 DPC Credit Agreement.

On August 27, 2012, the results of the vote on the Plan were filed with the Bankruptcy Court, with creditors 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 order confirming the Plan (the "Confirmation Order"). For detailed information on the Chapter 11 Cases including the plan of reorganization, Settlement Agreement and Plan Support Agreement and the related accounting impacts please read Note 3—Chapter 11 Cases.

MARKET DISCUSSION

Our business operations are focused primarily on the wholesale power generation sector of the energy industry. During 2011, we reorganized and manage and report the results of our power generation business based on fuel type with three segments on a consolidated basis: (i) Coal, (ii) Gas and (iii) DNE. As further described below, we transferred the Coal segment to our parent, Dynegy, effective September 1, 2011 and subsequently reacquired the Coal segment from Dynegy, effective June 5, 2012. Please read Note 3—Chapter 11 Cases for further discussion.

NERC Regions, RTOs and ISOs. In discussing our business, we often refer to NERC regions. The NERC and its regional reliability entities were formed to ensure the reliability and security of the electricity system. The regional reliability entities set standards for reliable operation and maintenance of power generation facilities and transmission systems. For example, each NERC region establishes a minimum operating reserve requirement to ensure there is sufficient generating capacity to meet expected demand within its region. Each NERC region reports seasonally and annually on the status of generation and transmission in each region.

Separately, RTOs and ISOs administer the transmission infrastructure and markets across a regional footprint in most of the markets in which we operate. They are responsible for dispatching all generation facilities in their respective footprints and are responsible for both maximum utilization and reliable and efficient operation of the transmission system. RTOs and ISOs administer energy and ancillary service markets in the short term, usually day ahead and real-time markets. Several RTOs and ISOs also ensure long-term planning reserves through monthly, semi-annual, annual and multi-year capacity markets. The RTOs and ISOs that oversee most of the wholesale power markets in which we operate currently impose, and will likely continue to impose, both bid and price limits. They may also enforce caps and other mechanisms to guard against the exercise of market dominance in these markets. NERC regions and RTOs/ISOs often have different geographic footprints, and while there may be geographic overlap between NERC regions and RTOs/ISOs, their respective roles and responsibilities do not generally overlap.

In RTO and ISO regions with centrally dispatched market structures, all generators selling into the centralized market receive the same price for energy sold based on the bid price associated with the production of the last MWh that is needed to balance supply with demand within a designated zone or at a given location (different zones or locations within the same RTO/ISO may produce different prices respective to other zones within the same RTO/ISO due to losses and congestion). For example, a less efficient and/or less economical natural gas-fired unit may be needed in some hours to meet demand. If this unit's production is required to meet demand on the margin, its bid price will set the market clearing price that will be paid for all dispatched generation in the same zone or location (although the price paid at other zones or locations may vary because of congestion and losses), regardless of the price that any other unit may have offered into the market. In RTO and ISO regions with centrally dispatched market structures and location-based marginal price clearing structures (e.g. PJM, NYISO, MISO, CAISO and ISO-NE), generators will receive the location-based marginal price for their output. The location-based marginal price, absent congestion, would be the marginal price of the most expensive unit needed to meet demand. In regions that are outside the footprint of RTOs/ISOs, prices are determined on a bilateral basis between buyers and sellers.

Market-Based Rates. Our ability to charge market-based rates for wholesale sales of electricity, as opposed to cost-based rates, is governed by FERC. We have been granted market-based rate authority for wholesale power sales from our EWG facilities, as well as wholesale power sales by our power marketing entities, DYPM and DMT. The Dynegy EWG facilities include all of our facilities except our investment in the Nevada Cogeneration Associates #2 ("Black Mountain") facility. This facility is known as a QF, and has various exemptions from federal regulation and sells electricity directly to purchasers under negotiated and previously approved power purchase agreements.

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Our market-based rate authority is predicated on a finding by FERC that our entities with market-based rates do not have market power, and a market power analysis is generally conducted once every three years for each region on a rolling basis (known as the triennial market power review).

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

Coal Segment

Our Coal segment is comprised of four operating coal-fired power generation facilities and two operating natural gas-fired peaker facilities in Illinois with a total generating capacity of 3,132 MW. On November 17, 2011, our parent, Dynegy, permanently retired the 176 MW Vermilion power generation facility. The Coal segment was transferred to our parent effective September 1, 2011. However, we reacquired the Coal segment effective June 5, 2012.

RTO/ISO Discussion

MISO. The MISO market includes all of Wisconsin and portions of Michigan, Kentucky, Indiana, Illinois, Nebraska, Kansas, Missouri, Iowa, Minnesota, North Dakota, Montana and Manitoba, Canada.

The MISO energy market is designed to ensure that all market participants have open-access to the transmission system on a non-discriminatory basis. MISO, as an independent RTO, maintains functional control over the use of the transmission system to ensure transmission circuits do not exceed their secure operating limits and become overloaded. MISO operates day-ahead and real-time energy markets using a LMP system which calculates a price for every generator and load point within MISO. This market is transparent, allowing generators and load serving entities to see real-time price effects of transmission constraints and the impacts of congestion at each pricing point. MISO administers a centralized capacity market that relies on bilateral transactions for all sales and purchases beyond one month forward and includes a monthly voluntary clearing auction that allows buyers to clear residual capacity requirements.

MISO also administers an FTR market holding monthly and annual auctions. FTRs allow users to manage the cost of transmission congestion (as measured by LMP differentials, between source and sink points on the transmission grid) and corresponding price differentials across the market area.

MISO implemented the Ancillary Services Market (Regulation and Operating Reserves) on January 6, 2009 and implemented an enforceable Planning Reserve Margin for each planning year effective June 1, 2009. A feature of the Ancillary Services Market is the addition of scarcity pricing that, during supply shortages, can raise the combined price of energy and ancillary services significantly higher than the previous cap of $1,000/MWh.

An independent market monitor is responsible for ensuring that MISO markets are operating competitively and without exercise of market power.

Contracted Capacity and Energy

We commercialize our Coal segment assets through a combination of physical participation in the MISO markets (as described above), bilateral physical and financial power sales, and fuel and capacity contracts.

Reserve Margins

MISO's actual reserve margins tightened during summer 2011 with a record peak load of 103,621 MW on July 20, 2011. The actual average reserve margin for summer 2011 was 22 percent versus a MISO planning reserve margin of 17 percent. In 2010, the actual average reserve margin was 29 percent and the planning reserve margin was 15 percent.

Gas Segment

Our Gas segment is comprised of seven operating natural gas-fired power generation facilities located in California (2), Nevada (1), Illinois (1), Pennsylvania (1), New York (1), and Maine (1), and one fuel-oil fired power generation facility located in California, totaling 6,771 MW of electric generating capacity. Our 309 MW South Bay facility was permanently retired in

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2010 and is currently in the process of being decommissioned.

RTO/ISO Discussion

PJM. The PJM market includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. Our Kendall and Ontelaunee facilities, located in Illinois and Pennsylvania, respectively, operate in PJM with an aggregate net generating capacity of 1,780 MW.

PJM administers markets for wholesale electricity and provides transmission planning for the region, utilizing the LMP system described above. PJM operates day-ahead and real-time markets into which generators can bid to provide electricity and ancillary services. PJM also administers markets for capacity. An independent market monitor continually monitors PJM markets for any exercise of market power or improper behavior by any entity. PJM implemented a forward capacity auction, the RPM, which established long-term markets for capacity in 2007. In addition to entering into bilateral capacity transactions, we have participated in RPM base residual auctions through PJM's planning year 2014-2015, which ends May 31, 2015, as well as ongoing incremental auctions to balance positions and offer residual capacity that may become available.

PJM, like MISO, dispatches power plants to meet system energy and reliability needs, and settles physical power deliveries at LMPs. This value is determined by an ISO-administered auction process, which evaluates and selects the least costly supplier offers or bids to create reliable and least-cost dispatch. The ISO-sponsored LMP energy markets consist of two separate and characteristically distinct settlement time frames. The first is a security-constrained, financially firm, day-ahead unit commitment market. The second is a security-constrained, financially-settled, real-time dispatch and balancing market. Prices paid in these LMP energy markets, however, are affected by, among other things, (i) market mitigation measures, which can result in lower prices associated with certain generating units that are mitigated because they are deemed to have the potential to exercise locational market power, and (ii) the existing $1,000/MWh energy market price caps that are in place.

NYISO. The NYISO market includes virtually the entire state of New York. Capacity pricing is calculated as a function of NYISO's annual required reserve margin, the estimated net cost of "new entrant" generation, estimated peak demand and the actual amount of capacity bid into the market at or below the demand curve. The demand curve mechanism provides for incrementally higher capacity pricing at lower reserve margins, such that "new entrant" economics become attractive as the reserve margin approaches required minimum levels. The intent of the demand curve mechanism is to ensure that existing generation facilities have enough revenue to recover their investment when capacity revenues are coupled with energy and ancillary service revenues. Additionally, the demand curve mechanism is intended to attract new investment in generation when and where that new capacity is needed most. To calculate the price and quantity of installed capacity, three ICAP demand curves are utilized: one for Long Island, one for New York City and one for Statewide (commonly referred to as Rest of State). Our Independence facility operates in the Rest of State market with an aggregate net generating capacity of 1,064 MW.

Due to transmission constraints, energy prices vary across New York and are generally higher in the Southeastern part of New York and in New York City and Long Island. Our Independence facility is located in the Northwestern part of the state.

ISO-NE. The ISO-NE market includes the six New England states of Vermont, New Hampshire, Massachusetts, Connecticut, Rhode Island and Maine. Much like regional zones in the NYISO, energy prices also vary among the participating states in ISO-NE, and are largely influenced by transmission constraints and fuel supply. ISO-NE implemented a FCM in June 2010, where capacity prices are determined through auctions. Our Casco Bay facility, located in Maine, operates in ISO-NE with an aggregate net generating capacity of 540 MW.

CAISO. CAISO covers approximately 90 percent of the State of California and operates a centrally cleared market for energy and ancillary services. Energy is priced at each location utilizing the LMP system described above. This market structure was implemented in April of 2009 as part of the MRTU. Currently the CAISO has a mandatory resource adequacy requirement but no centrally-administered capacity market. The Oakland facility has been designated as an RMR unit by the CAISO for 2012. Our Moss Landing, Morro Bay and Oakland facilities operate in CAISO with an aggregate net generating capacity of 3,344 MW.

Contracted Capacity and Energy

PJM. Our generation assets in PJM are natural gas-fired, combined-cycle, intermediate-dispatch facilities. We commercialize these assets through a combination of bilateral power, fuel and capacity contracts. We commercialize our capacity through either the RPM auction or on a bilateral basis. Our Kendall facility has two tolling agreements, one for 135 MW that expires in March 2012 and one for 85 MW that expires in 2017.

NYISO. At our Independence facility, 740 MW of capacity is contracted under a capacity sales agreement that runs through 2014. Revenue from this capacity obligation is largely fixed with a variable discount that varies each month based on

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the applicable LMP. Additionally, we supply steam and up to 44 MW of electric energy from our Independence facility to a third party at a fixed price.

Due to the standard capacity market operated by NYISO and liquid over-the-counter market for NYISO capacity products, we are able to sell substantially all of the Independence facility's remaining uncommitted capacity into the market.

ISO-NE. Five forward capacity auctions have been held to date with capacity clearing prices ranging from a high of $4.50 kW/month for the 2010/2011 market period to a low of $2.95 kW/month for the 2013/2014 market period. These capacity clearing prices represent the floor price; the actual rate paid to market participants was affected by pro-rationing due to oversupply conditions.

CAISO. In CAISO, where our assets include intermediate dispatch and peaking facilities, we seek to mitigate spark spread variability through RMR, tolling arrangements and physical and financial bilateral power and fuel contracts. All of the capacity of our Moss Landing Units 6 and 7 are contracted under tolling arrangements through 2013. As previously noted, our Oakland facility operates under an RMR contract.

Black Mountain. We have a 50 percent indirect ownership interest in the Black Mountain facility, which is a PURPA QF located near Las Vegas, Nevada, in the WECC. Capacity and energy from this facility are sold to Nevada Power Company under a long-term PURPA QF contract that expires in 2023.

Reserve Margins

PJM. Actual reserve margins are approximately 11 percent above PJM's current required installed reserve margin of 15.5 percent. The reserve margin based on deliverable capacity was 27 percent for Planning Year 2011/12 as compared to 26 percent for Planning Year 2010/11. PJM's required installed reserve margin can change annually and is 15.5 percent for Planning Year 2011/12.

NYISO. A reserve margin of 16 percent has been accepted by FERC for the New York Control Area for the period beginning May 1, 2012 and ending April 30, 2013, up from the current requirement of 15.5 percent. The actual amount of installed capacity is approximately 14 percent above NYISO's current required margin.

ISO-NE. Recommended improvements and modifications to the FCM design are currently in litigation at FERC, and discussions to address improvements to the FCM design are currently underway by the ISO and its stakeholders.

CPUC/CAISO. On the state level, there are numerous ongoing market initiatives that impact wholesale generation, principally the development of resource adequacy rules and capacity markets.

The CPUC requires a Resources Adequacy margin of 15 to 17 percent. As of the latest Summer Assessment for 2011, reserve margin was approximately 20.8 percent. Unlike other centrally cleared capacity markets, the CAISO Resource Adequacy market is a bi-laterally traded market.

DNE Segment

Our DNE segment 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 DH Chapter 11 Cases, the DH Debtor Entities rejected these long-term leases. 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 read Note 3—Chapter 11 Cases for further discussion.

Our Roseton and Danskammer facility sites are adjacent and share common resources such as fuel handling, a docking terminal, personnel and certain associated systems.

RTO/ISO Discussion

NYISO. For a full discussion of the NYISO market, see the "NYISO" section under "Gas—RTO/ISO Discussion" above. Our DNE facilities operate in the Rest of State market. Due to transmission constraints, energy prices vary across New York and are generally higher in the Southeastern part of New York, where our Roseton and Danskammer facilities are located, and in New York City and Long Island.

Contracted Capacity and Energy

We commercialize these assets through a combination of bilateral physical and financial power, fuel and capacity contracts. Due to the standard capacity market operated by NYISO and liquid over-the-counter market for NYISO capacity

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products, we are able to sell substantially all of the assets' capacity into the market.

Other

Corporate governance roles and functions, which are managed on a consolidated basis, and specialized support functions such as finance, accounting, commercial, risk control, tax, legal, regulatory, human resources, administration and information technology, are allocated to each reportable segment, in accordance with the relevant Service Agreements. Please read Note 21—Related Party Transactions—Service Agreements for further discussion. Corporate interest expense and income taxes are included in Other, as are corporate-related other income and expense items.

ENVIRONMENTAL MATTERS

Our business is subject to extensive federal, state and local laws and regulations governing discharge of materials into the environment. We are committed to operating within these regulations and to conducting our business in an environmentally responsible manner. The environmental, legal and regulatory landscape is subject to change and has become more stringent over time. The process for acquiring or maintaining permits or otherwise complying with applicable rules and regulations may create unprofitable or unfavorable operating conditions or require significant capital and operating expenditures. Any failure to acquire or maintain permits or to otherwise comply with applicable rules and regulations may result in fines and penalties or negatively impact our ability to advance projects in a timely manner, if at all. Further, changing interpretations of existing regulations may subject historical maintenance, repair and replacement activities at our facilities to claims of noncompliance.

Our aggregate expenditures (both capital and operating) for compliance with laws and regulations related to the protection of the environment were approximately $180 million in 2011 compared to approximately $225 million in 2010 and approximately $320 million in 2009. The 2011 expenditures included approximately $150 million for projects related to our Consent Decree (which is defined and discussed below) compared to approximately $200 million for Consent Decree projects in 2010. We estimate that total expenditures in 2012 related to our Coal segment will be approximately $100 million, including approximately $75 million in capital expenditures and $25 million in operating expenditures. In addition, we estimate that total environmental expenditures of the Company, which includes our Gas and DNE segments, will be approximately $10 million in 2012, consisting only of operating expenditures. Changes in environmental regulations or outcomes of litigation and administrative proceedings could result in additional requirements that would necessitate increased future spending and could create adverse operating conditions. Please read Note 23—Commitments and Contingencies for further discussion of this matter.

The Clean Air Act

The CAA and comparable state laws and regulations relating to air emissions impose responsibilities on owners and operators of sources of air emissions, including requirements to obtain construction and operating permits as well as compliance certifications and reporting obligations. The CAA requires that fossil-fueled electric generating plants have sufficient emission allowances to cover actual SO2 emissions and in some regions NOX emissions, and that they meet certain pollutant emission standards as well. Our power generation facilities, some of which have changed their operations to accommodate new control equipment or changes in fuel mix, are currently in compliance with these requirements.

In order to ensure continued compliance with the CAA and related rules and regulations, including ozone-related requirements, we have installed, are in the process of installing, or have plans to install additional emission reduction technology at our Coal segment facilities. Two coal-fired units at our Baldwin facility and the coal-fired unit at our Havana facility have installed and are operating dry flue gas desulphurization systems for the control of SO2 emissions, and electrostatic precipitators and baghouses for the control of particulate emissions. A third unit at Baldwin (Unit 2) currently utilizes an electrostatic precipitator and is scheduled to complete installation of a dry flue gas desulphurization system and baghouse by the end of 2012. Our coal-fired units at the Hennepin facility have electrostatic precipitators and baghouses for the control of particulate matter. The baghouses at our Coal segment facilities also control hazardous air pollutants in particulate form, such as most metals. Activated carbon injection or mercury oxidation systems for the control of mercury emissions have been installed and are operating on approximately 97 percent of our Coal segment's coal-fired capacity, and we will install controls on our final unit (Wood River Unit 4) by 2013. SCR technology to control NOX emissions has been installed and has been operating at Havana for several years; the remaining Coal segment units use low-NOX burners and overfire air to lower NOX emissions.

Multi-Pollutant Air Emission Initiatives

In recent years, various federal and state legislative and regulatory multi-pollutant initiatives have been introduced. In 2005, the EPA finalized the CAIR, which would require reductions of approximately 70 percent each in emissions of SO2 and NOx by 2015 from coal-fired power generation units across the eastern United States. The CAIR was challenged by several parties and ultimately remanded to the EPA by the U.S. Court of Appeals for the District of Columbia Circuit. The CAIR

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remained in effect in 2011 and, as a result of a court order staying the CAIR's intended replacement rule (i.e. the CSAPR), the CAIR will continue in effect in 2012 at least until the judicial challenges to the CSAPR are decided. Our facilities in Illinois and New York are subject to state SO2 and NOx limitations more stringent than those imposed by the CAIR.

Cross-State Air Pollution Rule. On July 6, 2011, the EPA issued its final rule on Federal Implementation Plans to Reduce Interstate Transport of Fine Particulate Matter and Ozone (the "Cross-State Air Pollution Rule," formerly known as the Transport Rule). Numerous petitions for judicial review of the CSAPR were filed and, on December 30, 2011, the U.S. Court of Appeals for the District of Columbia Circuit issued an order staying implementation of the CSAPR. In response, the EPA reinstated the CAIR pending judicial review. On August 21, 2012, the court vacated the CSAPR and ordered the EPA to continue administering the CAIR pending the promulgation of a valid replacement. The EPA has not yet announced how it will respond to the court's decision.

The CSAPR is intended to reduce emissions of SO2 and NOx from large EGUs in the eastern half of the United States. If the CSAPR is eventually upheld by the courts, the rule would impose cap-and-trade programs within each affected state that cap emissions of SO2 and NOx at levels predicted to eliminate that state's contribution to nonattainment in, or interference with maintenance of attainment status by, down-wind areas with respect to the NAAQS for particulate matter (PM2.5) and ozone. The rule would be implemented initially through federal implementation plans. Our generating facilities in Illinois, New York and Pennsylvania would be subject to the rule.

Under the CSAPR, Illinois, New York and Pennsylvania would be subject to new cap-and-trade programs capping emissions of NOx from May 1 through September 30 and capping emissions of SO2 and NOX on an annual basis. Requirements applicable to NOx emissions would have required compliance with the annual NOx reductions beginning January 1, 2012 and ozone season NOx reductions beginning May 1, 2012. The requirements applicable to SO2 emissions from electric generating units in Illinois, New York and Pennsylvania would have been implemented in two stages with compliance dates of January 1, 2012 and January 1, 2014. The SO2 emission budgets would be reduced in 2014, and existing EGUs in these states would be allocated fewer SO2 emission allowances beginning in 2014. States submitting a SIP to achieve the required reductions in place of the federal implementation plan would be allowed to use different allowance allocation methodologies beginning with vintage year 2013.

Electric generating units would be required to hold one emission allowance for every ton of SO2 and/or NOx emitted during the applicable compliance period. Electric generating units can comply with the required emission reductions by any combination of (i) installing emission control technologies, (ii) operating existing controls more often, (iii) switching fuels, or (iv) curtailing or ceasing operation. Allowance trading is generally allowed under the CSAPR among sources within the same state with limited interstate allowance trading. On February 6, 2012, the EPA issued technical revisions to the CSAPR, including a two-year delay in the assurance penalty provisions that is intended to promote liquidity in the CSAPR allowance markets and a smooth transition from the CAIR programs.

Based on the allowance allocations in the final CSAPR and our current projections of emissions in 2012, we anticipate that our Coal segment facilities would have an adequate number of allowances in 2012 under each of the three applicable CSAPR cap-and-trade programs (SO2, NOx annual, and NOx ozone season). For our Danskammer and Roseton facilities, we anticipate a shortfall of allocated allowances in 2012 under each of the three CSAPR programs.

Legislation also has been introduced in Congress that, if enacted, would void or delay the implementation of the CSAPR. However, the Obama Administration has indicated that it would veto any bill that would delay or void the CSAPR. Similar legislative efforts are expected to continue in 2012 but passage of such legislation in the next year is considered unlikely.

We will continue to monitor rulemaking, judicial and legislative developments regarding the CASPR, and evaluate any potential impacts on our operations.

Mercury/HAPs. In March 2005, the EPA issued the CAMR for control of mercury emissions from coal-fired power plants and established a cap-and-trade program requiring states to promulgate rules at least as stringent as the CAMR. In December 2006, the Illinois Pollution Control Board approved a state rule for the control of mercury emissions from coal-fired power plants that required additional capital and operating expenditures at our Illinois coal-fired plants beginning in 2007. The State of New York has also approved a mercury rule that will likely require us to incur additional capital and operating costs for the coal-fired units at our Danskammer power generating facility by January 1, 2015. In connection with the DH Chapter 11 Cases, the DH Debtor Entities rejected the lease at Danskammer. The applicable DH Debtor Entities have operated and plan to continue operating the leased facilities until such facilities can be sold in accordance with 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.

In February 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAMR; however, the Illinois and New York mercury regulations remain in effect. In March 2011, the EPA released a proposed rule to establish

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MACT emission standards for HAPs at coal- and oil-fired EGUs. On December 21, 2011, the EPA issued its EGU MACT final rule, the Mercury and Toxics Standards ("MATS") rule, which establishes numeric emission limits for mercury, non-mercury metals (filterable particulate may be used as a surrogate), and acid gases (hydrogen chloride used as a surrogate, with SO2 as an optional surrogate for coal-fired units using flue gas desulfurization; oil-fired units also would be subject to a hydrogen fluoride limit), and work practice standards for organic HAPs. Compliance would be required by April 16, 2015 (i.e. three years after the effective date of the final rule), unless an extension is granted in accordance with the CAA. Various parties have filed judicial appeals of the MATS rule.

Given the air emission controls already employed or planned for installation on our Coal segment facilities, we expect that our coal units in Illinois will be in compliance with the MATS rule emission limits without the need for significant additional investment. We continue to evaluate the final MATS rule, as well as related judicial and legislative developments, for potential impacts on our operations.

Visibility. The CAVR requires states to include BART requirements for individual facilities in their SIPs to address regional haze. The requirements apply to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain regulated pollutants in specific industrial categories, including utility boilers. States are required to submit regional haze implementation plans to the EPA detailing their plans to reduce emissions of visibility-impairing pollutants (NOx, SO2 and particulates) that affect visibility in downwind Federal Class I Areas (i.e. parks and wilderness) with a goal to restore natural visibility conditions in these areas by 2064.

The Roseton facilities and Unit 4 at our Danskammer facility have been identified as BART-eligible facilities. In compliance with the New York State BART Rule, our Danskammer and Roseton power generating facilities performed a comprehensive, unit-specific modeling analysis for their BART eligible units to determine their impact on visibility. In the fall of 2010, we submitted this analysis to NYSDEC along with a proposal to reduce relevant emission limits to address impacts on visibility. As approved by NYSDEC in a Title V permit modification issued in November 2011, BART compliance at our Roseton facility would be achieved, effective January 1, 2014, by reducing the sulfur content of our fuel oil and optimization of existing NOx emission controls. In November 2011, NYSDEC issued for public comment a proposed modified Title V permit for Danskammer, which would require the BART emission limits for Unit 4 be achieved, effective July 1, 2014, through optimization of existing NOx emission controls, co-firing with natural gas, use of alternative coal, and/or installation of additional emission controls. In April 2012, the EPA proposed to reject the Company's Danskammer Unit 4 SO2 BART determination because the Agency deemed that other control options evaluated by the Company were technically feasible, cost effective, and resulted in additional visibility improvement. The EPA further proposed to adopt a more stringent federal implementation plan SO2 emissions limit of 0.09 lbs/MMBtu for Danskammer Unit 4. The EPA also proposed to reject the Company's SO2 BART determination for Roseton and instead proposed a more stringent federal implementation plan SO2 emissions limit of 0.55 lb/mmBTU. For both Danskammer Unit 4 and Roseton, the EPA proposed to approve the Company's NOx and PM BART determinations. On August 16, 2012, the EPA issued a final rule federal implementation plan establishing SO2 BART emission limits for Roseton, and SO2, NOx and PM BART emission limits Danskammer Unit 4, in accordance with the Agency's proposed rule. We are continuing to review our compliance options at Danskammer Unit 4, options which could result in significant expenditures for emission control equipment or a switch to natural gas. In connection with the DH Chapter 11 Cases, the DH Debtor Entities rejected the leases at the Danskammer and Roseton 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 read Note 3—Chapter 11 Cases for further discussion.

Other Air Emission Initiatives

NAAQS. On April 30, 2012, the EPA designated as nonattainment with the 2008 ozone NAAQS the St. Louis-St. Charles-Farmington, Missouri-Illinois area, which includes Madison County, Illinois, the location of our Wood River station. The EPA classified the affected multi-state area as marginal nonattainment with an attainment deadline in 2015. On June 12, 2012, the EPA designated the multi-state area as attainment with the 1997 8-hour ozone NAAQS. While the nature and scope of potential future requirements concerning the 2008 ozone NAAQS cannot be predicted with confidence at this time, a requirement for additional NOx emission reductions at our Wood River facility, or any of our other facilities, for purposes of the 2008 ozone NAAQS, may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

In June 2010, the EPA adopted a new SO2 NAAQS, replacing the previous 24-hour and annual standards with a new short-term 1-hour standard. Areas initially designated nonattainment must achieve attainment no later than five years after initial designation. In July 2012, the EPA announced that will delay issuance of area designations by up to one year, i.e. until spring 2013. In June 2011, the Illinois EPA recommended a nonattainment designation for the new 1-hour SO2 NAAQS for the area where our Wood River power generating station is located. Our Wood River facility is one of several major SO2 emissions

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sources in the larger area. The NYSDEC recommended that all areas in New York State be designated attainment or unclassifiable with the new 1-hour SO2 NAAQS; however, in November 2011, the Sierra Club recommended to the NYSDEC and the EPA that, based on emissions modeling it had performed, certain areas in New York State be designated nonattainment due to SO2 emissions from the Danskammer generating station. While the nature and scope of potential future requirements concerning the 1-hour SO2 NAAQS cannot be predicted with confidence at this time, a requirement for additional SO2 emission reductions at our Danskammer facility, or any of our other facilities, for purposes of the 1-hour SO2 NAAQS may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

On June 15, 2012, the EPA proposed to lower the NAAQS for PM2.5. The EPA is required to take final action by December 14, 2012. The EPA intends to make initial nonattainment designations by December 2014, based on air quality data for 2011 to 2013. The earliest attainment deadlines would be in approximately 2020. The nature and scope of potential future requirements resulting from a more stringent PM2.5 NAAQS cannot be predicted with confidence at this time, but a requirement for additional emission reductions at any of our facilities for purposes of a more stringent PM2.5 NAAQS may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

New York NOx RACT Rule. In June 2010, New York State issued a final rule establishing revised RACT limits for emissions of NOx from stationary combustion sources. Compliance with the revised NOx RACT limits is required by July 1, 2014, and compliance plans were due to NYSDEC by January 1, 2012. Compliance options include meeting presumptive RACT limits, case-by-case RACT determinations, fuel switching during the ozone season (May 1 through September 30), and participation in a system averaging plan. In December 2011, we submitted RACT proposals for our Gas segment's Independence facility and DNE segment's Danskammer and Roseton facilities. For our Independence facility, we proposed to meet the presumptive RACT limits using the facility's existing SCR technology and currently applicable NOx BACT emission limits. For each of our DNE segment facilities, we proposed to meet the presumptive RACT limits with compliance to be achieved by a system averaging plan. We are continuing to review our NOx RACT compliance options at Roseton and Danskammer. In connection with the DH Chapter 11 Cases, the DH Debtor Entities rejected the leases at the Danskammer and Roseton 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 read Note 3—Chapter 11 Cases for further discussion.

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.

Please read Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for further discussion.

Information Request under Section 114 of the Clean Air Act. In March 2009, we received an information request from the EPA regarding maintenance, repair and replacement projects undertaken between January 2000 and the present at the Danskammer power generation facility. The information request is related to a nationwide enforcement initiative by the EPA targeting coal-fired power plants. We submitted responses to the information request in April and July 2009. While we have not since received any further substantive communication from the EPA on this matter, the EPA enforcement initiative against coal-fired power plants remains ongoing. The EPA's inquiry may lead to claims of CAA violations that could result in an enforcement action, the scope of which cannot be predicted with confidence at this time. In connection with the DH Chapter 11 Cases, the DH Debtor Entities rejected the lease at the Danskammer and Roseton 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.

The Clean Water Act

Our water withdrawals and wastewater discharges are permitted under the CWA and analogous state laws. The cooling water intake structures at several of our facilities are regulated under Section 316(b) of the CWA. This provision generally directs that standards set for facilities require that the location, design, construction and capacity of cooling water intake

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structures reflect BTA for minimizing adverse environmental impact. These standards are developed and implemented for power generating facilities through NPDES permits or SPDES permits. Historically, standards for minimizing adverse environmental impacts of cooling water intakes have been made by permitting agencies on a case-by-case basis considering the best professional judgment of the permitting agency.

In 2004, the EPA issued the Cooling Water Intake Structures Phase II Rules (the "Phase II Rules"), which set forth standards to implement the BTA requirements for cooling water intakes at existing facilities. The rules were challenged by several environmental groups and in 2007 were struck down by the U.S. Court of Appeals for the Second Circuit in Riverkeeper, Inc. v. EPA. The court's decision remanded several provisions of the rules to the EPA for further rulemaking. Several parties sought review of the decision before the U.S. Supreme Court. In April 2009, the U.S. Supreme Court ruled that the EPA permissibly relied on cost-benefit analysis in setting the national BTA performance standard and in providing for cost-benefit variances from those standards as part of the Phase II Rules.

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

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

The environmental groups that participate in our NPDES and SPDES permit proceedings generally argue that only closed cycle cooling meets the BTA requirement. The issuance and renewal of NPDES or SPDES permits for three of our power generation facilities (Danskammer, Roseton and Moss Landing) have been challenged on this basis. The Danskammer SPDES permit, which was renewed and issued in June 2006, does not require installation of a closed cycle cooling system; however, it does require aquatic organism mortality reductions resulting from NYSDEC's determination of BTA requirements under its regulations. All appeals of this permit have been exhausted. The Moss Landing NPDES permit, which was issued in 2000, does not require 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 the leases at the Roseton and Danskammer generation 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 read Note 3—Chapter 11 Cases for further discussion.

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 are 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.

California Water Intake Policy. The California State Water Board adopted its Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (the "Policy") in May 2010. The Policy requires that

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existing power plants: (i) reduce their water intake flow rate to a level commensurate with that which can be achieved by a closed cycle cooling system; or (ii) if it is not feasible to reduce the water intake flow rate to this level, reduce impingement mortality and entrainment to a level comparable to that achieved by such a reduced water intake flow rate using operational or structural controls, or both. Compliance with the Policy would be required at our Morro Bay power generation facility by December 31, 2015 and at our Moss Landing power generation facility by December 31, 2017. On October 27, 2010, Dynegy Morro Bay, LLC and Dynegy Moss Landing, LLC joined with other California power plant owners in filing a lawsuit in the Sacramento County Superior Court challenging the Policy. We cannot predict with confidence the outcome of the litigation at this time.

In September 2010, the State Water Board proposed to amend the Policy to allow an owner or operator of a power plant with previously installed combined-cycle power generating units to continue to use once-through cooling at combined-cycle units until the unit reaches the end of its useful life under certain circumstances. At its December 14, 2010, hearing on the proposed amendment, the State Water Board declined to approve the amendment and instead tabled it for consideration until after the Statewide Advisory Committee on Cooling Water Intake Structures ("SACCWIS") has reviewed facility compliance plans and made recommendations to the Board. In March 2012, SACCWIS reported its recommendations to the Board on the Policy's compliance deadlines, recommending that the Board recognize it may be necessary to modify final compliance dates for generating units due to projected capacity needs in the ISO balancing authority area. SACCWIS concluded that, based on the state's electric system needs, it is possible that additional reliability studies may justify revisions to the final compliance date for some or all of Moss Landing's capacity, but that it did not believe an extension of the final compliance date for Morro Bay is necessary at this time.

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

It may not be possible to meet the requirements of the Policy without installing closed cycle cooling systems. Given the numerous variables and factors involved in calculating the potential costs of closed cycle cooling systems, any decision to install such a system would be made on a case-by-case basis considering all relevant factors at the time. In addition, while the Policy is generally at least as stringent as the EPA's proposed rule for cooling water intake structures, compliance with the Policy may not meet all requirements of the forthcoming EPA final rule. If capital expenditure requirements related to cooling water systems are great enough to render the continued operation of a particular plant uneconomical, we could at our option, and subject to any applicable financing agreements and other obligations, reduce operations or cease to operate the plant and forego such capital expenditures.

New York Water Intake Policy. On July 10, 2011, the NYSDEC issued its final policy on BTA for Cooling Water Intake Structures (the "NYSDEC Policy"). The NYSDEC Policy establishes wet closed-cycle cooling or its equivalent (i.e. reductions in impingement mortality and entrainment from calculation baseline that are 90 percent or greater of that which would be achieved by wet closed-cycle cooling) as the performance goal for existing power plants. The NYSDEC Policy exempts existing power generation facilities operated at less than 15 percent of capacity over a current five-year averaging period from the entrainment performance goal, provided that the facility is operated in a manner that minimizes the potential for entrainment. For these low-capacity facilities, NYSDEC will determine site-specific performance goals for entrainment on a best professional judgment basis. For facilities for which a BTA determination was issued prior to adoption of the policy and which are in compliance with an existing BTA compliance schedule and verification monitoring, the NYSDEC Policy does not apply unless and until the results of verification monitoring demonstrate the necessity of more stringent BTA requirements. At this time we do not believe that the NYSDEC Policy will have a material impact on operations of the subject DNE segment facilities given the prior BTA determination for Danskammer and the entrainment exemption for low-capacity facilities. In connection with the DH Chapter 11 Cases, the DH Debtor Entities rejected the lease at the Danskammer and Roseton 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.

Other CWA Initiatives. The requirements applicable to water quality are expected to increase in the future. A number of efforts are under way within the EPA to evaluate water quality criteria for parameters associated with the by-products of fossil fuel combustion. These parameters relate primarily to arsenic, mercury and selenium. Under a consent decree, as modified, the EPA is required to propose revisions to the Effluent Guidelines for steam electric units by November 20, 2012 and to take final action on the proposal by April 28, 2014. Significant changes in these requirements could require installation of additional water treatment equipment at our facilities or require dry handling of coal ash. The nature and scope of potential future water quality requirements concerning the by-products of fossil fuel combustion cannot be predicted with confidence at this time, but

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could have a material adverse effect on our financial condition, results of operations and cash flows.

Coal Combustion Residuals

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

In response to the Kingston ash slurry release, the EPA initiated an investigation of the structural integrity of certain CCR surface impoundment dams including those at our Coal segment facilities. We responded to EPA requests for information, and our surface impoundment dams that the EPA has assessed and to date issues final reports were found to be in satisfactory condition with no recommendations. In May 2012, we received from the EPA draft dam safety assessment reports of the surface impoundments at our Baldwin and Hennepin facilities. The draft reports would rate the impoundments at each facility as “poor”, meaning that a deficiency is recognized for a required loading condition in accordance with applicable dam safety criteria. A poor rating also applies when further critical studies are needed to identify any potential dam safety deficiencies. The draft reports include recommendations for further studies, repairs, and changes in operational and maintenance practices. We provided comments to the EPA on the draft reports and continue to review the draft reports' recommendations. The nature and scope of potential required repairs cannot be predicted with confidence at this time, but may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

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

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

Certain environmental organizations have advocated designation of CCR as a hazardous waste; however, many state environmental agencies have expressed strong opposition to such designation. On September 30, 2011, the EPA released a notice of data availability (“NODA”) regarding its CCR proposed rule for the limited purpose of soliciting comment on additional information regarding the CCR proposal as identified in the NODA. The EPA has indicated plans to release a second NODA to gather additional data for the rulemaking record. The EPA is not expected to issue final regulations governing CCR management until late 2012 or thereafter. In April 2012, CCR marketers and environmental groups separately filed lawsuits seeking to force the EPA to complete its CCR rulemaking as soon as possible. Federal legislation to address CCR as non-hazardous waste also has been introduced in Congress.

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 requests by the Illinois EPA. Groundwater monitoring results indicate that the CCR surface impoundments at each site impact onsite groundwater.

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

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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 submitted for the old east and north CCR impoundments 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.

Climate Change

For the last several years, there has been a robust public debate about climate change and the potential for regulations requiring lower emissions of GHG, primarily CO2 and methane. We believe that the focus of any federal program attempting to address climate change should include three critical, interrelated elements: (i) the environment, (ii) the economy and (iii) energy security.

We cannot confidently predict the final outcome of the current debate on climate change nor can we predict with confidence the ultimate requirements of proposed or anticipated federal and state legislation and regulations intended to address climate change. These activities, and the highly politicized nature of climate change, suggest a trend toward increased regulation of GHG that could result in a material adverse effect on our financial condition, results of operations and cash flows. Existing and anticipated federal and state regulations intended to address climate change may significantly increase the cost of providing electric power, resulting in far-reaching and significant impacts on us and others in the power generation industry over time. It is possible that federal and state actions intended to address climate change could result in costs assigned to GHG emissions that we would not be able to fully recover through market pricing or otherwise. If capital and/or operating costs related to compliance with regulations intended to address climate change become great enough to render the operations of certain plants uneconomical, we could, at our option and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate such plants and forego such capital and/or operating costs.

Power generating facilities are a major source of GHG emissions—in 2011, our Gas and DNE segment facilities emitted approximately 5.3 million and 1.3 million tons of CO2e, respectively. The amounts of CO2e emitted from our facilities during any time period will depend upon their dispatch rates during the period.

Though we consider our largest risk related to climate change to be legislative and regulatory changes intended to slow or prevent it, we are subject to physical risks inherent in industrial operations including severe weather events such as hurricanes and tornadoes. To the extent that changes in climate effect changes in weather patterns (such as more severe weather events) or changes in sea level where we have generating facilities, we could be adversely affected. To the extent that climate change results in changes in sea level, we would expect such effects to be gradual and amenable to structural mitigation during the useful life of the facilities. However, if this is not the case it is possible that we would be impacted in an adverse way, potentially materially so. We could experience both risks and opportunities as a result of related physical impacts. For example, more extreme weather patterns—namely, a warmer summer or a cooler winter—could increase demand for our products. However, we also could experience more difficult operating conditions in that type of environment. We maintain various types of insurance in amounts we consider appropriate for risks associated with weather events.

Federal Legislation Regarding Greenhouse Gases. Several bills have been introduced in Congress since 2003 that if passed would compel reductions in CO2 emissions from power plants. Many of these bills have included cap-and-trade programs. However, with the political shift in the makeup of the 112th Congress (2011-2012), recently introduced legislation would instead either delay or prevent the EPA from regulating GHGs under the CAA. The passage of comprehensive GHG legislation in the next year is considered unlikely.

Federal Regulation of Greenhouse Gases. In April 2007, the U.S. Supreme Court issued its decision in Massachusetts v. EPA, holding that GHGs meet the definition of a pollutant under the CAA and that regulation of GHG emissions is authorized by the CAA.

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In response to that decision, the EPA issued a finding in December 2009 that GHG emissions from motor vehicles cause or contribute to air pollution that endangers the public health and welfare. The EPA has since also finalized several rules concerning GHGs as directly relevant to our facilities. In January 2010, the EPA rule on mandatory reporting of GHG emissions from all sectors of the economy went into effect and requires the annual reporting of GHG emissions. We have implemented processes and procedures to report these emissions and, as required, reported our 2010 GHG emissions by September 30, 2011 The EPA Tailoring Rule, which became effective in January 2011, phases in new GHG emissions applicability thresholds for the PSD permit program and for the operating permit program under Title V of the CAA. In general, the Tailoring Rule establishes a GHG emissions PSD applicability threshold at a net increase of 75,000 tons per year of CO2e for new and modified major sources. Application of the PSD program to GHG emissions will require implementation of BACT for new and modified major sources of GHG. In November 2010, the EPA issued its PSD and Title V Permitting Guidance for Greenhouse Gases. For coal-fired electric generating units, the guidance focuses on steam turbine and boiler efficiency improvements as a reasonable BACT requirement. The endangerment finding, including the EPA's denial of subsequent requests for reconsideration, and the Tailoring Rule were challenged in the U.S. Court of Appeals for the District of Columbia Circuit.

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

In March 2011, the EPA entered a settlement agreement of a CAA citizen suit under which the agency would propose NSPS under the CAA for control of GHG emissions from new and modified EGUs, as well as emission guidelines for control of GHG emissions from existing EGUs. The lawsuit, New York, et al. v. EPA, involves a challenge to the NSPS for EGUs, issued in 2006, because the rule did not establish standards for GHG emissions. The settlement, as amended, required the EPA to issue proposed GHG emissions standards for EGUs by September 30, 2011 and to finalize the standards by May 26, 2012. In September 2011, the EPA announced that it would delay the release of the proposed GHG standards. On March 27, 2012, the EPA released a proposed NSPS carbon pollution standard for new EGUs. The proposed NSPS issued would apply only to new fossil fuel-fired EGUs that start construction later than 12 months after the proposal. The proposal would not apply to modifications or reconstructions of existing EGUs. The proposed standard would allow new EGUs to burn any fossil fuel but would establish an output-based standard of 1,000 lbs of CO₂ per megawatt-hour, which the EPA believes is achievable by natural gas combined cycle units without add-on controls. New EGUs that burn other fuels, such as coal, would have to incorporate technology to reduce CO₂ emissions, such as carbon capture and storage. New coal plants using carbon capture and storage would be allowed to average their CO₂ emissions over 30 years to meet the standard, provided that CO₂ emissions were limited to 1,800 lb/MWh on an annual basis, which the EPA believes could be met by using super-critical boiler technology. The final carbon pollution standard is expected to be issued within one year. The EPA has not indicated its plans concerning a proposed GHG emission standard for existing EGUs.

In February 2012, the EPA proposed not to change its Tailoring Rule GHG permitting thresholds for the PSD and Title V operating permit programs. Under the approach that would be maintained by the proposal, existing sources that emit 100,000 tons per year (tpy) of CO₂e and make changes increasing GHG emissions by at least 75,000 tpy of CO₂e continue to require PSD permits. Facilities that must obtain a PSD permit for other pollutants must also address GHG emission increases of 75,000 tpy or more of CO₂e. The EPA's proposal notes that the agency will complete a subsequent rulemaking by April 30, 2016, to determine whether it would be appropriate to lower the thresholds at that time.

State Regulation of Greenhouse Gases. Many states where we operate generation facilities have, are considering, or are in some stage of implementing, state-only regulatory programs intended to reduce emissions of GHGs from stationary sources as a means of addressing climate change.

Our assets in Illinois may become subject to a regional GHG cap-and-trade program under the MGGA. The MGGA is an agreement among six states and one Canadian province to create the MGGRP to establish GHG reduction targets and timeframes consistent with member states' targets and to develop a market-based and multi-sector cap-and-trade mechanism to achieve the GHG reduction targets. Illinois has set a goal of reducing GHG emissions to 1990 levels by the year 2020, and to 60 percent below 1990 levels by 2050. The MGGA advisory group released a model rule in 2010, but implementation by the MGGA participants has not moved forward.

Our assets in California are subject to the California Global Warming Solutions Act ("AB 32"), which became effective in January 2007. AB 32 requires the CARB to develop a GHG emission control program that will reduce emissions of GHG in the state to their 1990 levels by 2020. In October 2011, the CARB adopted its final GHG cap-and-trade regulation, which became

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effective on January 1, 2012, but cap-and-trade compliance obligations do not begin until January 1, 2013 due to litigation. The emissions cap set by the CARB for 2013 is about two percent below the emissions level forecast for 2012, declines in 2014 by about two percent, and by about three percent annually from 2015 to 2020. The CARB's first allowance auction is scheduled for November 2012. The CARB has set the initial auction price floor at $10 per allowance, but expects allowance prices will be between $15 and $30 in 2020.

In late March 2012, several environmental groups filed a lawsuit in California state court challenging the cap-and-trade rule's offset provisions, which allow covered sources to comply by purchasing emissions reductions made by entities not otherwise participating in the cap-and trade program. CARB also released other GHG program proposals in June 2012 that address issues such as auction administration and revisions to the mandatory reporting rule.

The State of California is also a party to a regional GHG cap-and-trade program being developed under the WCI to reduce GHG emissions in the participating jurisdictions. The WCI started as a collaborative effort among seven states and four Canadian provinces, but California currently is the sole remaining state participant. California's implementation of AB 32 is expected to constitute the state's contribution to the WCI. In June 2012, CARB released proposed revisions to the cap-and-trade rule that would link the rule to WCI partner Quebec's GHG program and allow California entities to comply with the CARB cap-and-trade rule using Quebec-issued compliance instruments. We will continue to monitor developments regarding the California cap-and-trade program and evaluate any potential impacts on our operations.

On January 1, 2009, our assets in New York and Maine became subject to a state-driven GHG emission control program known as RGGI. RGGI was developed and initially implemented by ten New England and Mid-Atlantic states to reduce CO2 emissions from power plants. The participating RGGI states implemented rules regulating GHG emissions using a cap-and-trade program to reduce CO2 emissions by at least 10 percent of 2009 emission levels by the year 2018. Compliance with the allowance requirement under the RGGI cap-and-trade program can be achieved by reducing emissions, purchasing or trading allowances, or securing offset allowances from an approved offset project. While allowances are sold by year, actual compliance is measured across a three-year control period. The first control period covered 2009-2011. The second control period covers 2012-2014.

In December 2011, RGGI held its fourteenth auction, in which approximately 27.29 million allowances for the first control period were sold at a clearing price of $1.89 per allowance. No bids were submitted for allowances for a future control period.

RGGI quarterly auctions continue in 2012 but will RGGI offer only 2012 allocation year allowances in those auctions. On March 14, 2012, RGGI held its fifteenth auction, in which approximately 21.5 million allowances for the second control period were sold at a clearing price of $1.93 per allowance. On June 6, 2012, RGGI held its sixteenth auction, in which approximately 20.9 million allowances for the second control period were sold at a clearing price of $1.93 per allowance. RGGI's next quarterly auction is scheduled for September 2012. We have participated in each of the quarterly RGGI auctions (or in secondary markets, as appropriate) to secure some allowances for our affected assets.

Our generating facilities in New York and Maine emitted approximately 3.5 million tons of CO₂ during 2011. For the first RGGI compliance period (2009-2011), the actual cost of allowances required for our operations was $35 million. The average clearing price for future period allowances sold in all auctions held to date is $2.33. We believe that the current market price of $1.96 is indicative of future pricing and estimate our cost of allowances required to operate these facilities during 2012 would be approximately $7 million. RGGI will perform a comprehensive program review in 2012, including an evaluation of a possible additional reduction in the CO₂ emissions cap. The outcome of that program review and its potential impact on our affected assets are currently unknown.

In August 2011, the State of New York enacted the "Power NY Act of 2011," which requires the NYSDEC to promulgate, within 12 months, regulations targeting CO2 emission reductions from major electric generating facilities that commenced construction after the effective date of the regulations. In June 2012, NYSDEC adopted CO₂ emission standards for new major electric generating facilities and for increases in capacity of at least 25 MW at existing major electric generating facilities. The rule does not affect existing electric generating facilities that do not expand electrical output capacity.

Climate Change Litigation. There is a risk of litigation from those seeking injunctive relief from power generators or to impose liability on sources of GHG emissions, including power generators, for claims of adverse effects due to climate change. Recent court decisions disagree on whether the claims are subject to resolution by the courts and whether the plaintiffs have standing to sue.

On June 20, 2011, the U.S. Supreme Court issued its decision in AEP v. Connecticut, which reviewed the appellate court decision in Connecticut v. AEP. In September 2009, the U.S. Court of Appeals for the Second Circuit had held in Connecticut v. AEP that the U.S. District Court is an appropriate forum for resolving claims by eight states and New York City against six

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electric power generators related to climate change. The Supreme Court was equally divided by a vote of 4-4 on the question of whether the plaintiffs had standing to bring the suit and, therefore, affirmed the court's exercise of jurisdiction. On the merits the Court ruled by a vote of 8-0 that the CAA and EPA action authorized by the CAA displace any federal common law right to seek abatement of CO₂ emissions from fossil fuel-fired power plants. The Court did not reach the issue of whether the CAA preempts similar claims under state nuisance law.

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska initiated an action in federal court in the Northern District of California against DH and 23 other companies in the energy industry. In September 2009, the court dismissed all of the plaintiffs' claims based on lack of subject matter jurisdiction and because plaintiffs lacked standing to bring the suit. The plaintiffs appealed to the Ninth Circuit, which held oral argument on November 28, 2011. Following the filing of the DH Chapter 11 Cases, the Plaintiffs voluntarily dismissed DH with prejudice on February 2, 2012.

In October 2009, the U.S. Court of Appeals for the Fifth Circuit considered the appeal of Comer v. Murphy Oil and held that claims related to climate change by property owners along the Mississippi Gulf Coast against energy companies could be resolved by the courts. However, the Comer v. Murphy decision was subsequently vacated. In May 2011, the plaintiffs re-filed a substantially similar complaint in the United States District Court for the Southern District of Mississippi. In March 2012, the court dismissed the complaint on multiple alternative grounds, concluding, among other things, that the plaintiffs' claims were barred by collateral estoppel and res judicata, the plaintiffs lacked standing, the claims were non-justiciable political questions, and that the federal Clean Air Act displaced the federal common law nuisance claims.

The conflict in recent court decisions illustrates the unsettled law related to claims based on the effects of climate change. The decisions affirming the jurisdiction of the courts and the standing of the plaintiffs to bring these claims could result in an increase in similar lawsuits and associated expenditures by companies like ours.

Carbon Initiatives. We participate in several programs that partially offset or mitigate our GHG emissions. In the lower Mississippi River Valley, we have partnered with the U.S. Fish & Wildlife Service to restore more than 45,000 acres of hardwood forests by planting more than 8 million bottomland hardwood seedlings. In Illinois, we are funding prairie, bottomland hardwood and savannah restoration projects in partnership with the Illinois Conservation Foundation. We also have programs to reuse CCR produced at our coal-fired generation units through agreements with cement manufacturers that incorporate the material into cement products, helping to reduce CO2 emissions from the cement manufacturing process.

Remedial Laws

We are subject to environmental requirements relating to handling and disposal of toxic and hazardous materials, including provisions of CERCLA and RCRA and similar state laws. CERCLA imposes strict liability for contributions to contaminated sites resulting from the release of "hazardous substances" into the environment. Those with potential liabilities include the current or previous owner and operator of a facility and companies that disposed, or arranged for disposal, of hazardous substances found at a contaminated facility. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to public health or the environment and to seek recovery for costs of cleaning up hazardous substances that have been released and for damages to natural resources from responsible parties. Further, it is not uncommon for neighboring landowners and other affected parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. CERCLA or RCRA could impose remedial obligations with respect to a variety of our facilities and operations.

As a result of their age, a number of our facilities contain quantities of asbestos-containing materials, lead-based paint and/or other regulated materials. Existing state and federal rules require the proper management and disposal of these materials. We have developed a management plan that includes proper maintenance of existing non-friable asbestos installations and removal and abatement of asbestos-containing materials where necessary because of maintenance, repairs, replacement or damage to the asbestos itself.

COMPETITION

Demand for power may be met by generation capacity based on several competing generation technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as power generating facilities fueled by alternative energy sources, including hydro power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Our Coal, Gas and DNE power generation businesses compete with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions. We believe that our ability to compete effectively in the power generation business will be driven in large part by our ability to achieve and maintain a low cost of production, primarily by managing fuel costs and to provide reliable service to our customers. Our ability to compete effectively will also be impacted by various governmental and regulatory activities designed to reduce GHG emissions. For example, regulatory requirements for load-serving entities to acquire a percentage of their energy from renewable-fueled facilities will potentially

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reduce the demand for energy from gas-fired facilities such as those we own and operate. We believe our primary competitors consist of at least 20 companies in the power generation business.

SIGNIFICANT CUSTOMERS

For the year ended December 31, 2011, approximately 36 percent, 17 percent, 22 percent and 11 percent of our consolidated revenues were derived from transactions with MISO, NYISO, PJM and NGX, respectively. For the year ended December 31, 2010, approximately 30 percent, 15 percent and 13 percent of our consolidated revenues were derived from transactions with MISO, NYISO and PJM, respectively. For the year ended December 31, 2009, approximately 19 percent, 12 percent and 11 percent of our consolidated revenues were derived from transactions with MISO, NYISO and PJM, respectively. No other customer accounted for more than 10 percent of our consolidated revenues during 2011, 2010 or 2009.

EMPLOYEES

At December 31, 2011, we and Dynegy had approximately 274 employees at our corporate headquarters and approximately 988 employees at our facilities, including field-based administrative employees. Approximately 639 employees at our operating facilities are subject to collective bargaining agreements with various unions. Approximately 770 of our employees, including those located in our corporate headquarters, our natural gas facilities, and Dynegy's coal facilities that we acquired on June 5, 2012, are employed by our subsidiary, and approximately 147 of our employees are employed by the Debtor Entities. We believe relations with our employees are satisfactory.

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Item 1A. Risk Factors

FORWARD-LOOKING STATEMENTS

This Form 10-K 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 annual 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 power generation 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;


•	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;

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•	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 below.

FACTORS THAT MAY AFFECT FUTURE RESULTS

Risks Related to Restructuring

The Debtor Entities filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code and are subject to the risks and uncertainties associated with bankruptcy cases.

The Debtor Entities filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. For the duration of the Debtor Entities' Chapter 11 Cases, our business and operations will be subject to various risks, including but not limited to, the following:


•	The Debtor Entities' bankruptcy filings may cause customers, suppliers and others with whom we have commercial relationships to lose confidence in us and may make it more difficult for us to obtain and maintain such commercial relationships on competitive terms;


•	It may be more difficult to retain and motivate our key employees through the process of reorganization, and we may have difficulty attracting new employees;


•	Our senior management will be required to spend significant time and effort dealing with the bankruptcy and restructuring activities rather than focusing exclusively on business operations; and


•	There can be no assurance as to the Debtor Entities' ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations.

We will also be subject to risks and uncertainties with respect to the actions and decisions of creditors and other third parties who have interests in the Chapter 11 Cases that may be inconsistent with our plans. These risks and uncertainties could affect our business and operations in various ways and may increase the time the Debtor Entities have to operate under Chapter 11 bankruptcy protection. Because of the risks and uncertainties associated with the Debtor Entities' Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases will have on our business, financial condition and results of operations.

We may not be able to successfully implement the restructuring set forth in the Settlement Agreement, Plan Support Agreement and the Plan.

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


•	federal and state regulators may not approve certain elements of the Plan; and

•the Agreements may be terminated.

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

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

We may not be able to consummate the Plan.

The consummation of the Plan is subject to the satisfaction of certain conditions precedent. There can be no assurance that such conditions will be satisfied, and therefore, that the Plan will be consummated.

Furthermore, although we believe that the Plan will become effective reasonably soon after the date on which the Bankruptcy Court's order confirming the Plan is entered on the Bankruptcy Court's docket, there can be no assurance as to the timing or that the Plan will become effective. If the Plan does not become effective or if a protracted reorganization or liquidation were to occur, there is a substantial risk that holders of claims would receive less than they would receive under the Plan and we and our affiliates, including Dynegy, may continue to face ongoing litigation at significant costs.

The Plan contemplates the Merger and although the Bankruptcy Court has already authorized DH and Dynegy to enter into the Merger pursuant to the terms and conditions set forth in the Bankruptcy Court's July 10, 2012 order authorizing the Merger, the Plan also requires that the Merger and all material documents, instruments and agreements necessary to implement the Merger, be in form and substance reasonably acceptable to Dynegy, DH, the majority of the Consenting Senior Noteholders, the Lease Trustee and the Creditors' Committee. If the Merger is not consummated for any reason and we decide to prosecute a standalone plan of reorganization on similar terms to those set forth in the Plan, including in particular the extinguishment of all equity interests in DH and, as a result, we and our subsidiaries cease to be subsidiaries of Dynegy, there could be an adverse impact on each of DH and Dynegy. Specifically, such an occurrence may constitute a “Change of Control” as such term is defined in the Credit Agreements. A Change of Control is an “Event of Default” under the Credit Agreements and, as a result, amounts outstanding under the Credit Agreements may be declared immediately due and payable. This could have a negative impact on our financial condition and future operations if we are unable to timely obtain waivers under or refinance the Credit Agreements on reasonable terms, and recoveries to holders of claims against DH may be negatively impacted. If the Effective Date does not occur, it may become necessary to amend the Plan to provide alternative treatment of claims and equity interests. There can be no assurance that any such alternative treatment would be on terms as favorable to the holders of claims and equity interests as the treatment provided under the Plan. If any modifications to the Plan are material, it would be necessary to re-solicit votes from holders of claims and equity interests adversely affected by the modifications with respect to such amended Plan.

Upon effectiveness of the Merger, the investments of our noteholders and other creditors will be subject to any liabilities of Dynegy as a result of our merger with and into Dynegy.

There are significant risks associated with mergers. Our counterpart to the Merger, Dynegy Inc,, is subject to its own set of liabilities, as well as claims with respect to the Dynegy Chapter 11 Case (other than those discharged in bankruptcy). The investments of our noteholders and other creditors will be subject to the liability of, and claims against, Dynegy upon the effectiveness of the Merger.

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

Dynegy's (and our) ability to use previously incurred federal net operating loss carryforwards ("NOLs") and alternative minimum tax credit carryforwards ("AMT Credits"), which, respectively, have a maximum balance of $1,419 million ($1,228 million with respect to us and our affiliates) and $271 million at December 31, 2011, will likely be limited or modified on the Effective Date as a result of section 382 of the Internal Revenue Code and at the close of Dynegy's taxable year after the Effective Date as a result of cancellation of indebtedness income (“COD Income”). In addition, Dynegy (and we) had an Ownership Change (as defined below) in the second quarter of 2012 and thus its (and our) ability to utilize its federal NOLs and AMT Credits that existed at the time of the Ownership Change will be significantly limited (in an amount yet to be determined).

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

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percent shareholders at any time during the applicable testing period (an “Ownership Change”).

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

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

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

Risks Related to Our Financial Structure, Level of Indebtedness and Access to Capital Markets

We have significant indebtedness that could adversely affect our financial health and prevent us from fulfilling certain of our financial obligations.

We have and will continue to have a significant amount of debt outstanding. As of December 31, 2011, we had debt of approximately $4.7 billion (including $3.6 billion in unsecured senior notes and debentures that are subject to compromise in the bankruptcy process and $1.1 billion outstanding under the DPC Credit Agreement). Such amount of indebtedness could:


•	make it difficult to satisfy our financial obligations, including debt service requirements;


•	limit our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other purposes on acceptable terms, on a timely basis or at all;


•	limit our financial flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;


•	impact the evaluation of our creditworthiness by counterparties to commercial agreements, both for hedging as well as operating contracts, such as for fuel and transportation, and affect their willingness to transact with us and/or the level of collateral we are required to post under such agreements;


•	place us at a competitive disadvantage compared to our competitors that have less debt;


•	increase our vulnerability to general adverse economic and industry conditions, and


•	require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions and other general corporate purposes.

Further, if gas, power, and capacity prices, where applicable, do not improve, our ability to service our debt obligations will be adversely affected and may require significant operational and balance sheet restructurings.

Restrictive covenants may adversely affect operations.

The Credit Agreements contain various covenants that limit DMG's or DPC's ability to, among other things:


•	incur additional indebtedness;


•	pay dividends, repurchase or redeem stock or make investments in certain entities;

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•	enter into related party transactions;


•	create certain liens;


•	enter into sale and leaseback transactions;


•	enter into any agreements which limit the ability of such subsidiaries to make dividends or otherwise transfer cash or assets to us or certain other subsidiaries;


•	create unrestricted subsidiaries;


•	impair the security interests;


•	issue certain capital stock;


•	consolidate, merge, sell or otherwise dispose of all or substantially all of its assets; and


•	sell and acquire assets.

These restrictions may affect the ability of DMG, DPC, Dynegy or us to operate our respective businesses, may limit our ability to take advantage of potential business opportunities as they arise and may adversely affect the conduct of our current businesses, including restricting our ability to finance future operations and capital needs and limiting our ability to engage in other business activities.

Our access to the capital markets may be limited.

Because of our non-investment grade credit rating, the Chapter 11 Cases of the Debtor Entities, and/or general conditions in the financial and credit markets, Dynegy's and our access to the capital markets may be limited. Moreover, the urgency of a capital-raising transaction may require us to pursue additional capital at an inopportune time. Our ability to obtain capital and the costs of such capital are dependent on numerous factors, including:


•	covenants in our existing credit agreements;


•	the outcome of the bankruptcy proceedings for the Debtor Entities;


•	investor confidence in us and the regional wholesale power markets;


•	our financial performance and the financial performance of our subsidiaries;


•	our levels of debt;


•	our requirements for posting collateral under various commercial agreements;


•	our credit ratings;


•	our cash flow;


•	our long-term business prospects; and


•	general economic and capital market conditions, including the timing and magnitude of any market recovery.

We may not be successful in obtaining additional capital for these or other reasons. An inability to access capital may limit our ability to meet our operating needs and, as a result, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our non-investment grade status may adversely impact our commercial operations, increase our liquidity requirements and increase the cost of refinancing opportunities. We may not have adequate liquidity to post required amounts of additional collateral.

Our corporate family credit rating is currently below investment grade and we cannot assure you that our credit ratings will improve, or that they will not decline, in the future. Our credit ratings may affect the evaluation of our creditworthiness by trading counterparties and lenders, which could put us at a disadvantage to competitors with higher or investment grade ratings.

In carrying out our commercial business strategy, our current non-investment grade credit ratings have resulted and will likely continue to result in requirements that we either prepay obligations or post significant amounts of collateral to support

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our business. Although the implementation of our commercial business strategy was modified in connection with the Reorganization to leverage the benefits of the Credit Agreements at our separately financed, bankruptcy-remote portfolios, various commodity trading counterparties may nevertheless be unwilling to transact with us or may make collateral demands that reflect our non-investment grade credit ratings, the counterparties' views of our creditworthiness, as well as changes in commodity prices. We use a portion of our capital resources, in the form of cash, short-term investments, lien capacity, and letters of credit, to satisfy these counterparty collateral demands. Our commodity agreements are tied to market pricing and may require us to post additional collateral under certain circumstances. If market conditions change such that counterparties are entitled to additional collateral, our liquidity could be strained and may have a material adverse effect on our financial condition, results of operations and cash flows. Factors that could trigger increased demands for collateral include changes in our credit rating or liquidity and changes in commodity prices for power and fuel, among others.

Additionally, our non-investment grade credit ratings may limit our ability to obtain additional sources of liquidity, refinance our debt obligations or access the capital markets at the lower borrowing costs that would presumably be available to competitors with higher or investment grade ratings. Should our ratings continue at their current levels, or should our ratings be further downgraded, we would expect these negative effects to continue and, in the case of a downgrade, become more pronounced.

Risks Related to the Operation of Our Business

Because wholesale power prices are subject to significant volatility and because many of our power generation facilities operate without long-term power sales agreements, our revenues and profitability are subject to wide fluctuations.

Because we largely sell electric energy, capacity and ancillary services into the wholesale energy spot market or into other power markets on a term basis, we are not guaranteed any rate of return on our capital investments. Rather, our financial condition, results of operations and cash flows will depend, in large part, upon prevailing market prices for power and the fuel to generate such power. Wholesale power markets are subject to significant price fluctuations over relatively short periods of time and can be unpredictable. Such factors that may materially impact the power markets and our financial results include:


•	economic conditions;


•	the existence and effectiveness of demand-side management;


•	conservation efforts and the extent to which they impact electricity demand;


•	regulatory constraints on pricing (current or future) or the functioning of the energy trading markets and energy trading generally;


•	the proliferation of advanced shale gas drilling increasing domestic natural gas supplies;


•	fuel price volatility; and


•	increased competition or price pressure driven by generation from renewable sources.

Many of our facilities operate as "merchant" facilities without long-term power sales agreements. Consequently, there can be no assurance that we will be able to sell any or all of the electric energy, capacity or ancillary services from those facilities at commercially attractive rates or that our facilities will be able to operate profitably. This could lead to less favorable financial results as well as future impairments of our property, plant and equipment or to the retirement of certain of our facilities resulting in economic losses and liabilities.

Given the volatility of commodity power prices, to the extent we do not secure long-term power sales agreements for the output of our power generation facilities, our revenues and profitability will be subject to increased volatility, and our financial condition, results of operations and cash flows could be materially adversely affected. Further, declines in the market prices of natural gas and wholesale electricity have reduced the outlook for cash flow that can be expected to be generated by us in the next several years.

Our commercial strategy may not be executed as planned or may result in lost opportunities.

We seek to commercialize our assets through sales arrangements of various types. In doing so, we attempt to balance a desire for greater predictability of earnings and cash flows in the short- and medium-terms with a belief that commodity prices will rise over the longer term, creating upside opportunities for those with unhedged generation volumes. Our ability to successfully execute this strategy is dependent on a number of factors, many of which are outside our control, including market liquidity, the availability of counterparties willing to transact with us or to transact with us at prices we believe are commercially acceptable, the availability of liquidity to post collateral in support of our derivative instruments, and the

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reliability of the systems comprising our commercial operations function. The availability of market liquidity and willing counterparties could be negatively impacted by poor economic and financial market conditions, including impacts on financial institutions and other current and potential counterparties as well as counterparties' views of our creditworthiness. If we are unable to transact in the short- and medium-terms, our financial condition, results of operations and cash flows will be subject to significant uncertainty and volatility. Alternatively, significant contract execution for any such period may precede a run-up in commodity prices, resulting in lost upside opportunities and mark-to-market accounting losses causing significant variability in net income and other GAAP reported measures.

We are exposed to the risk of fuel and fuel transportation cost increases and interruptions in fuel supplies.

We purchase the fuel requirements for many of our power generation facilities, primarily those that are natural gas-fired, under short-term contracts or on the spot market. As a result, we face the risks of supply interruptions and fuel price volatility, as fuel deliveries may not exactly match those required for energy sales, due in part to our need to pre-purchase fuel inventories for reliability and dispatch requirements.

Moreover, profitable operation of many of our coal-fired generation facilities is highly dependent on coal prices and coal transportation rates. Power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. We have entered into term contracts for PRB coal, which we use for our coal facilities in the Midwest. 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 contracted volumes remaining are unpriced but are subject to a price collar structure. Our coal transportation requirements are 100 percent contracted and priced through 2013 when our current contracts expire. 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.

Further, any changes in the costs of coal, fuel oil, natural gas or transportation rates and changes in the relationship between such costs and the market prices of power will affect our financial results. If we are unable to procure fuel for physical delivery at prices we consider favorable, our financial condition, results of operations and cash flows could be materially adversely affected.

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Our costs of compliance with existing environmental requirements are significant, and costs of compliance with new environmental requirements or factors could materially adversely affect our financial condition, results of operations and cash flows.

Our business is subject to extensive and frequently changing environmental regulation by federal, state and local authorities. Such environmental regulation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, use, transportation, treatment, storage and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances (including GHG) into the environment, and in connection with environmental impacts associated with cooling water intake structures. Existing environmental laws and regulations may be revised or reinterpreted, new laws and regulations may be adopted or may become applicable to us or our facilities, and litigation or enforcement proceedings could be commenced against us. Proposals being considered by federal and state authorities (including proposals regarding regulation of GHGs) could, if and when adopted or enacted, require us to make substantial capital and operating expenditures or consider retiring certain of our facilities. If any of these events occur, our financial condition, results of operations and cash flows could be materially adversely affected.

Many environmental laws require approvals or permits from governmental authorities before construction, modification or operation of a power generation facility may commence. Certain environmental permits must be renewed periodically in order for us to continue operating our facilities. The process of obtaining and renewing necessary permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Even where permits are not required, compliance with environmental laws and regulations can require significant capital and operating expenditures. We are required to comply with numerous environmental laws and regulations, and to obtain numerous governmental permits when we modify and operate our facilities. If there is a delay in obtaining any required environmental regulatory approvals or permits, if we fail to obtain any required approval or permit, or if we are unable to comply with the terms of such approvals or permits, the operation of our facilities may be interrupted or become subject to additional costs. Further, changed interpretations of existing regulations may subject historical maintenance, repair and replacement activities at our facilities to claims of noncompliance. As a result, our financial condition, results of operations and cash flows could be materially adversely affected. Certain of our facilities are also required to comply with the terms of the Consent Decree or other governmental orders.

With the continuing trend toward stricter environmental standards and more extensive regulatory and permitting requirements, our capital and operating environmental expenditures are likely to be substantial and may significantly increase in the future.

Our business is subject to complex government regulation. Changes in these regulations or in their implementation may affect costs of operating our facilities or our ability to operate our facilities, or increase competition, any of which would negatively impact our results of operations.

We are subject to extensive federal, state and local laws and regulations governing the generation and sale of energy commodities in each of the jurisdictions in which we have operations. Compliance with these ever-changing laws and regulations requires expenses (including legal representation) and monitoring, capital and operating expenditures. Potential changes in laws and regulations that could have a material impact on our business include: re-regulation of the power industry in markets in which we conduct business; the introduction, or reintroduction, of rate caps or pricing constraints; increased credit standards, collateral costs or margin requirements, as well as reduced market liquidity, as a result of potential OTC market regulation; or a variation of these. Furthermore, these and other market-based rules and regulations are subject to change at any time, and we cannot predict what changes may occur in the future or how such changes might affect any facet of our business.

The costs and burdens associated with complying with the increased number of regulations may have a material adverse effect on us if we fail to comply with the laws and regulations governing our business or if we fail to maintain or obtain advantageous regulatory authorizations and exemptions. Moreover, increased competition within the sector resulting from potential legislative changes, regulatory changes or other factors may create greater risks to the stability of our power generation earnings and cash flows generally.

Availability and cost of emission allowances could materially impact our costs of operations.

We are required to maintain, either through allocation or purchase, sufficient emission allowances to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet our obligations imposed by various applicable environmental laws, and the trend toward more stringent regulations (including regulations regarding GHG emissions) will likely require us to obtain new or additional emission allowances. If our operational needs require more than our allocated quantity of emission allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational

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needs, we may have to curtail our operations so as not to exceed our available emission allowances, or install costly new emissions controls. As we use the emissions allowances that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such allowances are available for purchase, but only at significantly higher prices, their purchase could materially increase our costs of operations in the affected markets and materially adversely affect our financial condition, results of operations and cash flows.

Competition in wholesale power markets, together with the age of certain of our generation facilities and an oversupply of power generation capacity in certain regional markets, may have a material adverse effect on our financial condition, results of operations and cash flows.

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions in the sale of electric energy, capacity and ancillary services, as well as in the procurement of fuel, transmission and transportation services. Moreover, aggregate demand for power may be met by generation capacity based on several competing technologies, as well as power generating facilities fueled by alternative or renewable energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste heat and solid waste sources. Regulatory initiatives designed to enhance renewable generation could increase competition from these types of facilities. In addition, a buildup of new electric generation facilities in recent years has resulted in an oversupply of power generation capacity in certain regional markets we serve.

We also compete against other energy merchants on the basis of our relative operating skills, financial position and access to credit sources. Electric energy customers, wholesale energy suppliers and transporters often seek financial guarantees, credit support such as letters of credit, and other assurances that their energy contracts will be satisfied. Companies with which we compete may have greater resources in these areas. In addition, certain of our current facilities are relatively old. Newer plants owned by competitors will often be more efficient than some of our plants, which may put these plants at a competitive disadvantage. Over time, some of our plants may become unable to compete because of the construction of new plants, and such new plants could have a number of advantages including: more efficient equipment, newer technology that could result in fewer emissions, or more advantageous locations on the electric transmission system. Additionally, these competitors may be able to respond more quickly to new laws and regulations because of the newer technology utilized in their facilities or the additional resources derived from owning more efficient facilities. Taken as a whole, the potential disadvantages of our aging fleet could result in lower run-times or even early asset retirement.

Other factors may contribute to increased competition in wholesale power markets. New forms of capital and competitors have entered the industry in the last several years, including financial investors who perceive that asset values are at levels below their true replacement value. As a result, a number of generation facilities in the United States are now owned by lenders and investment companies. Furthermore, mergers and asset reallocations in the industry could create powerful new competitors. Under any scenario, we anticipate that we will face competition from numerous companies in the industry, some of which have superior capital structures.

Moreover, many companies in the regulated utility industry, with which the wholesale power industry is closely linked, are also restructuring or reviewing their strategies. Several of those companies have discontinued or are discontinuing their unregulated activities and seeking to divest or spin-off their unregulated subsidiaries. Some of those companies have had, or are attempting to have, their regulated subsidiaries acquire assets out of their or other companies' unregulated subsidiaries. This may lead to increased competition between the regulated utilities and the unregulated power producers within certain markets. To the extent that competition increases, our financial condition, results of operations and cash flows may be materially adversely affected.

We do not own or control transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, these transmission facilities are operated by RTOs and ISOs, which are subject to changes in structure and operation and impose various pricing limitations. These changes and pricing limitations may affect our ability to deliver power to the market that would, in turn, adversely affect the profitability of our generation facilities.

We do not own or control the transmission facilities required to sell the wholesale power from our generation facilities. If the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. RTOs and ISOs provide transmission services, administer transparent and competitive power markets and maintain system reliability. Many of these RTOs and ISOs operate in the real-time and day-ahead markets in which we sell energy. The RTOs and ISOs that oversee most of the wholesale power markets impose, and in the future may continue to impose, offer caps and other mechanisms to guard against the potential exercise of market power in these markets as well as price limitations. These types of price limitations and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell energy and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar

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market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generating facilities. Rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. Additionally, if the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Furthermore, the rates for transmission capacity from these facilities are set by others and thus are subject to changes, some of which could be significant. As a result, our financial condition, results of operations and cash flows may be materially adversely affected.

Our financial condition, results of operations and cash flows would be adversely impacted by strikes or work stoppages by our unionized employees.

A majority of the employees at our facilities are subject to collective bargaining agreements with various unions. Additionally, unionization activities, including votes for union certification, could occur at our non-union generating facilities in our fleet. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strife or disruption, we could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor is uncertain. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our financial condition, results of operations and cash flows.

Our ability to comply with our Consent Decree may be materially adversely impacted by our future operating cash flows or unforeseen labor costs.

As a result of the Consent Decree, we are required to not operate certain of our coal-fired power generating facilities after specified dates unless certain emission control equipment is installed. As of December 31, 2011, 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 have incurred significant costs in complying with the Consent Decree and anticipate the remainder of the equipment installations to incur additional significant costs. Further, we are exposed to the risk of price increases in the costs of labor and to the risk that counterparties to the construction contracts may fail to perform, in which case we would be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices and possibly cause delays to the project timelines. Further, our production may be affected if we fail to meet certain performance standards under the Consent Decree.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

We have included descriptions of the location and general character of our principal physical operating properties by segment in "Item 1. Business," which is incorporated herein by reference. Substantially all of the assets of the Gas segment, including the power generation facilities owned by DPC, one of our indirect wholly-owned subsidiaries, are pledged as collateral to secure the repayment of, and other obligations under, the DPC Credit Agreement. Please read Note 20—Debt for further discussion.

Our principal executive office located in Houston, Texas, is held under a lease that expires in 2022. We also lease additional offices or warehouses in the states of California, Illinois, New York, and Texas.

Item 3. Legal Proceedings

Please read Note 23—Commitments and Contingencies—Legal Proceedings for a description of our material legal proceedings, which is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

All of our outstanding equity securities are held by our parent, Dynegy. There is no established trading market for such securities and they are not traded on any exchange.

Item 6. Selected Financial Data

The selected financial information presented below was derived from, and is qualified by, reference to our Consolidated Financial Statements, including the notes thereto, contained elsewhere herein. The selected financial information should be read in conjunction with the Consolidated Financial Statements and related notes and "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations."



	Year Ended December 31,
	2011(2)			2010			2009			2008			2007
	(in millions, except per share data)
Statement of Operations Data (1):
Revenues	$	1,437		$	2,323		$	2,468		$	3,324		$	2,918
Depreciation and amortization expense	(288		)	(392		)	(335		)	(346		)	(306		)
Goodwill impairment	—			—			(433		)	—			—
Impairment and other charges, exclusive of goodwill impairment shown separately above	(7		)	(148		)	(538		)	—			—
General and administrative expenses	(102		)	(158		)	(159		)	(157		)	(184		)
Operating income (loss)	(254		)	(6		)	(836		)	744			595
Bankruptcy reorganization charges	(666		)	—			—			—			—
Interest expense and debt extinguishment costs (3)	(370		)	(363		)	(461		)	(427		)	(384		)
Income tax (expense) benefit	315			184			313			(138		)	(105		)
Income (loss) from continuing operations	(940		)	(243		)	(1,046		)	222			165
Income (loss) from discontinued operations (4)	—			1			(222		)	(17		)	166
Net income (loss)	$	(940	)	$	(242	)	$	(1,268	)	$	205		$	331
Net income (loss) attributable to Dynegy Holdings, LLC	$	(940	)	$	(242	)	$	(1,253	)	$	208		$	324
Cash Flow Data:
Net cash provided by (used in) operating activities	$	(1	)	$	423		$	152		$	319		$	368
Net cash provided by (used in) investing activities	(229		)	(520		)	790			(87		)	(688		)
Net cash provided by (used in) financing activities	375			(69		)	(1,193		)	146			369
Capital expenditures, acquisitions and investments	(196		)	(517		)	(596		)	(626		)	(350		)



	December 31,
	2011(2)		2010		2009		2008		2007
	(in millions)
Balance Sheet Data:
Current assets	$	3,569	$	2,180	$	1,988	$	2,780	$	1,614
Current liabilities	3,051		1,562		1,848		1,681		999
Property and equipment, net	2,821		6,273		7,117		8,934		9,017
Total assets	8,311		9,949		10,903		14,174		13,107
Long-term debt (excluding current portion) (5)	1,069		4,626		4,775		6,072		5,939
Current portion of long-term debt	7		148		807		64		51
Capital leases not already included in long-term debt	—		—		4		4		5
Total equity	32		2,719		3,003		4,583		4,620

_______________________________________________________________________________

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(1)	The merger with LS Power (April 2, 2007) was accounted for in accordance with the purchase method of accounting and the results of operations attributable to the acquired business is included in our financial statements and operating statistics beginning on the acquisition's effective date for accounting purposes.


(2)	We completed the DMG Transfer effective September 1, 2011. Please read Note 3—Chapter 11 Cases for further discussion.


(3)	Includes $21 million and $46 million of debt extinguishment costs for the year ended December 31, 2011 and 2009, respectively.


(4)	Discontinued operations include the results of operations from the following businesses:


▪	The Arlington Valley and Griffith power generation facilities (collectively, the "Arizona power generation facilities") (sold fourth quarter 2009);


▪	Bluegrass power generating facility (sold fourth quarter 2009);


▪	Heard County power generating facility (sold second quarter 2009);


▪	Calcasieu power generating facility (sold first quarter 2008); and


▪	CoGen Lyondell power generating facility (sold third quarter 2007).

(5) As a result of the DH Chapter 11 Cases, we reclassified approximately $3.6 billion in long-term debt to LSTC. Total LSTC is approximately $4 billion. Please read Note 19—Liabilities Subject to Compromise for further discussion.

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Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the audited consolidated financial statements and the notes thereto included in this report.

OVERVIEW

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three segments in our consolidated financial statements: (i) the Coal segment ("Coal"); (ii) the Gas segment ("Gas") and (iii) the Dynegy Northeast segment ("DNE"). Prior to 2011, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. 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. Our investment in PPEA Holding Company, which was sold in the fourth quarter 2010, is included in Other for reporting purposes. As further described below, we transferred the Coal segment to our parent, Dynegy, effective September 1, 2011 and subsequently reacquired the Coal segment from Dynegy, effective June 5, 2012. Please read Note 3—Chapter 11 Cases for further discussion.

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 have continued without interruption. The commencement of the Chapter 11 Cases did not constitute a default under either of the Credit Agreements. Please Note 3—Chapter 11 Cases for further discussion of the Chapter 11 Cases and the related Settlement Agreement and Plan Support Agreement.

Reorganization Activity. On August 5, 2011, Dynegy completed the Reorganization to facilitate the execution of the Credit Agreements. The Credit Agreements include the DPC Credit Agreement, a $1,100 million, five year senior secured term loan facility available to DPC and the DMG Credit Agreement, a $600 million, five year senior secured term loan facility available to DMG. Please read Note 20—Debt for further discussion.

Services Agreements. In connection with the Reorganization, subsidiaries from Dynegy's Gas, Coal and DNE segments each entered into Services Agreements with other Dynegy entities to provide certain services. Please read Note 21—Related Party Transactions—Service Agreements for further discussion.

DMG Transfer. On September 1, 2011, Dynegy and DGIN, our subsidiary, completed the DMG Transfer. In exchange for the equity of Coal Holdco, Dynegy entered into an Undertaking Agreement with DGIN under which Dynegy agreed to make certain specified payments to DGIN aggregating approximately $2.1 billion through October 15, 2026. Subsequent to the exchange, DGIN assigned its rights to receive payments under the Undertaking Agreement to us in exchange for the Promissory Note in the amount of $1.25 billion that matures in 2027. As a condition to Dynegy's consent to the Assignment, the Undertaking Agreement was amended and restated to be between us and Dynegy and to provide for the reduction of Dynegy's obligations if the outstanding principal amount of the Senior Notes decreases as a result of any exchange offer, tender offer or other purchase or repayment by Dynegy or its subsidiaries (other than us or our subsidiaries, unless Dynegy guarantees the debt securities of us or such subsidiary in connection with such exchange offer, tender offer or other purchase or repayment); provided that such principal amount is retired, cancelled or otherwise forgiven. On June 5, 2012, the effective date of the Settlement Agreement, we reacquired Coal Holdco. At such time the Undertaking Agreement and Promissory Note were terminated with no further obligations thereunder. For further discussion, please read Note 1—Organization and Operations—Reorganization—DMG Transfer, Note 21—Related Party Transactions—DMG Transfer and Undertaking Agreement, and Note 27—Subsequent Events.

Sithe Senior Notes. On September 26, 2011, we completed the Sithe Tender Offer, in which we repurchased approximately $192 million of the Sithe Senior Notes for approximately $217 million. In connection with the Sithe Tender Offer and consent solicitation, we amended the indenture under which the Sithe Senior Notes were issued to eliminate or modify substantially all of the restrictive covenants, certain events of default and certain other provisions and satisfied and discharged the indenture and remaining Sithe Senior Notes. Please read Note 20—Debt—Sithe Senior Notes for further discussion.

Business Discussion

The following is a brief discussion of each of our segments, including a list of key factors that have affected, and are

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expected to continue to affect, their respective earnings and cash flows. We also present a brief discussion of our corporate-level expenses.

Power Generation Business

We generate earnings and cash flows in the three segments within our power generation business through sales of electric energy, capacity and ancillary services. Primary factors affecting our earnings and cash flows in the power generation business include:

•

Prices for power, natural gas, coal and fuel oil, which in turn are largely driven by supply and demand. Demand for power can vary due to weather and general economic conditions, among other things. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation. The proliferation of advanced shale gas drilling has increased domestic natural gas supplies which has caused a decline in power prices;


•	The relationship between electricity prices and prices for natural gas and coal, commonly referred to as the "spark spread" and "dark spread," respectively, which impacts the margin we earn on the electricity we generate; and


•	Our ability to enter into commercial transactions to mitigate short- and medium- term earnings volatility and our ability to manage our liquidity requirements resulting from potential changes in collateral requirements as prices move.

Other factors that have affected, and are expected to continue to affect, earnings and cash flows for this business include:


•	Transmission constraints, congestion, and other factors that can affect the price differential between the locations where we deliver generated power and the liquid market hub;


•	Our ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management;


•	Our ability to optimize our assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations;


•	Our ability to operate and market production from our facilities during periods of planned/unplanned electric transmission outages;


•	Our ability to post the collateral necessary to execute our commercial strategy;


•	The cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive (please read Item 1. Business—Environmental Matters for further discussion); and


•	Market supply conditions resulting from federal and regional renewable power mandates and initiatives.

Please read "Item 1A. Risk Factors" for additional factors that could affect our future operating results, financial condition and cash flows.

In addition to these overarching factors, other factors have influenced, and are expected to continue to influence, earnings and cash flows for our three reportable segments as further described below.

Coal. Our assets in Coal are primarily coal-fired facilities but also include two natural gas-fired peaking facilities. The Coal segment was transferred to Dynegy effective September 1, 2011 and reacquired from Dynegy effective June 5, 2012. The following specific factors affect or could affect the performance of this reportable segment:


•	Our ability to maintain sufficient coal inventories, which is dependent upon the continued performance of the mines and railroads for deliveries of coal in a consistent and timely manner, and its impact on our ability to serve the critical winter and summer on-peak loads;


•	Costs of transportation related to coal deliveries;


•	Our requirement to utilize a significant amount of cash for capital expenditures required to comply with the remaining Consent Decree work;


•	Regional renewable energy mandates and initiatives that may alter supply conditions within the ISO and our generating units' positions in the aggregate supply stack;

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•	Changes in the MISO market design or associated rules; and


•	Changes in the existing bilateral MISO capacity markets and any resulting effect on future capacity revenues.

Gas. Our assets in Gas are all natural gas-fired power generating facilities with the exception of our fuel oil-fired Oakland facility. The following specific factors impact or could impact the performance of this reportable segment:


•	Our ability to maintain and operate our plants in a manner that ensures we receive full capacity payments under our various tolling agreements;


•	Our ability to maintain the necessary permits to continue to operate our Moss Landing and Morro Bay facilities with once-through, seawater cooling systems;


•	The costs incurred to demolish and remediate the South Bay facility; and


•	Changes in the existing bilateral CAISO resource adequacy markets and any resulting effect on future capacity revenues.

DNE. Our assets in DNE include natural gas, fuel oil and coal-fired power generating facilities. To the extent our subsidiaries continue to be the operator and commercial manager of these assets, the following specific factors impact or could impact the performance of this reportable segment:


•	The amount of time that will be required to sell the leased Roseton and Danskammer facilities in accordance with the terms of the Settlement Agreement and Plan Support Agreement and the time to secure necessary applicable federal and state regulatory approvals;


•	Future operating costs, including property taxes and labor;


•	Our ability to maintain sufficient coal and fuel oil inventories, including continued deliveries of coal and oil in a consistent and timely manner, and continued access to uninterrupted natural gas supplies, to serve the winter and summer on-peak loads;


•	The additional costs imposed by state-driven environmental compliance initiatives aimed at reducing mercury emission levels and other constituents such as CO2, NOx and SO2 as well as more restrictive measures for cooling water intakes for fish protection;


•	Changes in NYISO market rules or state-specific mandates that favor and/or subsidize renewable energy sources and demand response initiatives; and


•	Our ability to preserve and/or capture value around planned transmission upgrades designed to improve transfer limits around known constraints.

Other

Other includes corporate expenses such as interest, depreciation and amortization and taxes. Significant items impacting future earnings and cash flows include:


•	Resolution of the Chapter 11 Cases and our ability to obtain support for the Plan;


•	Access to capital markets on reasonable terms, interest rates and other costs of liquidity;


•	Interest expense; and


•	Income taxes, which will be impacted by our ability to realize value from our NOLs and AMT credits.

General and administrative costs are allocated to each reportable segment in accordance with the relevant Services Agreement. They will be impacted by, among other things, (i) staffing levels and associated expenses; (ii) funding requirements under our pension plans; (iii) any future corporate-level litigation reserves or settlements and (iv) our ability to realize planned cost savings reflected in our financial forecasts.

Other also includes our legacy CRM operations, which primarily consists of a minimal number of legacy natural gas agreements that were novated to a third party in 2011.

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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. Cash on hand includes cash proceeds from the DPC Credit Agreement, which is limited in use and distribution as further described in footnote 1 to the liquidity table below. Please read Note 20—Debt for further information.

On September 1, 2011, we completed the DMG Transfer. Effective June 5, 2012, we reacquired the Coal segment (including DMG). Please read Note 27—Subsequent Events for further discussion.

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 December 31, 2011.



	September 7, 2012
	DMG (2)			DPC(1)			Other (3)			Total
	(in millions)
LC capacity, inclusive of required reserves (4)	$	34		$	252		$	27		$	313
Less: Required reserves (4)	(1		)	(8		)	(1		)	(10		)
Less: Outstanding letters of credit	(29		)	(236		)	(26		)	(291		)
LC availability	4			8			—			12
Cash and cash equivalents	60			59			561			680
Collateral posting account (5)	69			238			—			307
Total available liquidity (6)(7)	$	133		$	305		$	561		$	999



	December 31, 2011
	DPC(1)			Other (3)			Total
	(in millions)
LC capacity, inclusive of required reserves (4)	$	456		$	27		$	483
Less: Required reserves (4)	(13		)	(1		)	(14		)
Less: Outstanding letters of credit	(386		)	(26		)	(412		)
LC availability	57			—			57
Cash and cash equivalents	32			366			398
Collateral posting account (5)	132			—			132
Total available liquidity (6)(7)	$	221		$	366		$	587

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(1)

On August 5, 2011, we borrowed $1,100 million under the DPC Credit Agreement and repaid amounts outstanding and terminated our Fifth Amended and Restated Credit Agreement. A portion of the proceeds from the DPC Credit Agreement borrowing was used to make a $200 million restricted payment to a parent holding company of DPC. The DPC Credit Agreement limits further distributions by DPC to its parent to $135 million per fiscal year. Please read "DPC Restricted Payments below" and Note 20—Debt for further discussion.

(2)

On August 5, 2011, we borrowed $600 million under the DMG Credit Agreement. A portion of the proceeds from the DMG Credit Agreement borrowing was used to make a $200 million restricted payment to a parent holding company of DMG. The DMG Credit Agreement limits further distributions by DMG to its parent to $90 million per fiscal year. Please read "DPC Restricted Payments below" and Note 20—Debt for further discussion. On September 1, 2011, we completed the DMG Transfer. On June 5, 2012, Dynegy contributed and assigned to the Company all of its right, title,

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and interest in and to one hundred percent (100%) of the issued and outstanding membership interests of Coal Holdco ("DMG Acquisition"). As such, liquidity position amounts are presented for DMG as of September 7, 2012, but not as of December 31, 2011.

(3)

Other cash consists of $305 million and $305 million at Dynegy Gas HoldCo, LLC ("Gas HoldCo"); $14 million and $28 million at Dynegy Administrative Services Company; $49 million and $30 million at DH; and $20 million and $3 million at Dynegy Northeast Generation, Inc. as of September 7, 2012 and December 31, 2011, respectively. Other cash also consists of $173 million at Coal Holdco as of September 7, 2012.

(4)

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 on the unused capacity, may be withdrawn from the LC facilities with three days written notice for unrestricted use in the operations of the applicable entity. LC capacity as of September 7, 2012 reflects a reduction in capacity for DPC following the requested release of unused cash collateral from restricted cash. Actual commitment amounts under each of the New Credit Agreements have not been reduced, and we can increase the LC capacity up to the original commitment amount in the future by posting additional cash collateral.


(5)	The collateral posting account included in the above liquidity tables is restricted per the Credit Agreements and may be used for future collateral posting requirements or released per the terms of the applicable DPC Credit Agreement or DMG Credit Agreement. Please read Note 20—Debt for further discussion.

(6)

The DH Contingent LC Facility is not included in Total available liquidity as there is currently no capacity available under the facility. Under the terms of the Contingent LC Facility, up to $150 million of capacity can become available, contingent on specified changes in forward spark spreads and power prices for 2012. Our status as a Debtor Entity may limit availability. Please read Note 20—Debt for further discussion.


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

DPC Restricted Payments. In addition to the $400 million, in the aggregate, of proceeds from the DPC Credit Agreement that was initially distributed to Gas HoldCo, the DPC Credit Agreement limit distributions by DPC to its parent of $135 million per year, 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. In December 2011, DPC made a distribution of $135 million to its parent. Please read Note 20—Debt for further discussion.

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, December 31, 2011 and December 31, 2010.



	September 7, 2012		December 31, 2011		December 31, 2010
	(in millions)
Dynegy Midwest Generation, LLC (1)
Cash	$	20	$	—	$	—
Letters of Credit	29		—		—
Total DMG	49		—		—

Dynegy Power, LLC:
Cash	$	91	$	44	$	—
Letters of credit	235		386		—
Total DPC	326		430		—

Dynegy Holdings, LLC:
Cash and short-term investments (2)	$	2	$	—	$	87
Letters of credit	26		26		375
Total DH	28		26		462

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(1)	On June 5, 2012, Dynegy contributed and assigned to Dynegy Holdings all of its right, title, and interest in and to one hundred percent (100%) of the issued and outstanding membership interests of DMG. In consideration of such membership interests, all liens and the Undertaking Agreement and Note Payable by Dynegy were terminated with no

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further obligations. Please read Note 27—Subsequent Events for further discussion. As such, liquidity position amounts for DMG as of September 7, 2012, but not as of December 30, 2011 are presented.


(2)	As of December 31, 2010, we had $85 million of short-term investments in our Broker margin account on our consolidated balance sheet.

The change in letters of credit postings from December 31, 2010 to December 31, 2011 is primarily due to contractual obligations under certain operational agreements. Collateral postings decreased from December 31, 2011 to September 7, 2012 primarily due to increased usage of collateral efficient agreements, termination of certain contracts and decrease in collateral requirements due to the roll-off of certain positions.

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 our Credit Agreements. The additional liens were granted as collateral under certain of our commodity derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under the Credit Agreements. The fair value of DPC's commodity derivatives collateralized by first priority liens included liabilities of $104 million and $92 million at September 7, 2012 and December 31, 2011, respectively. The fair value of our derivatives, excluding those held by DPC, collateralized by first priority liens included liabilities of $13, zero and $30 million at September 7, 2012, December 31, 2011, and December 31, 2010, respectively.

We expect counterparties' future collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness. Our ability to use forward economic hedging instruments could be limited due to the collateral requirements the use of such instruments entails.

Operating Activities

Historical Operating Cash Flows. Our cash flow used in operations totaled $1 million for the twelve months ended December 31, 2011. During the period, our power generation business provided positive cash flow from operations of $348 million from the operation of our power generation facilities offset by a use of cash of $349 million from corporate and other operations primarily due to interest payments to service debt, employee related payments and restructuring costs.

Our cash flow provided by operations totaled $423 million for the twelve months ended December 31, 2010. During the period, our power generation business provided positive cash flow from operations of $938 million from the operation of our power generation facilities, primarily reflecting positive earnings for the period and approximately $290 million of cash received from our futures clearing manager. The receipt of this cash was partly due to lower commodity prices and a reduction of margin requirements; the remaining cash was returned as a result of the posting of $85 million of short-term investments in lieu of cash. Corporate and other operations included a use of cash of approximately $515 million, primarily due to interest payments to service debt and general and administrative expenses.

Our cash flow provided by operations totaled $152 million for the twelve months ended December 31, 2009. During the period, our power generation business provided positive cash flow from operations of $719 million. Cash provided by the operations of our power generation facilities was partly offset by a $173 million increase in cash collateral postings. Other included a use of cash of approximately $567 million, primarily due to interest payments to service debt and general and administrative expenses.

Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the 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 continue to tightly manage our operating costs and capital expenditures. We had approximately $196 million, $333 million and $612 million in capital expenditures during the twelve months ended December 31, 2011, 2010 and 2009, respectively. Our capital spending by reportable segment was as follows:

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	December 31,
	2011		2010		2009
	(in millions)
Coal (1)	$	115	$	274	$	502
Gas	79		50		91
DNE	2		3		8
Other and eliminations	—		6		11
Total	$	196	$	333	$	612

_______________________________________________________________________________


(1)	Only includes capital expenditures through August 31, 2011 when the DMG Transfer was completed. Please read Note 3—Chapter 11 Cases for further discussion. Capital expenditures for the period from September 1, 2011 to December 31, 2011 related to the legal entities included in Coal, but not shown in the table above, were $69 million.

Capital spending in our Coal segment primarily consisted of environmental and maintenance capital projects, as well as approximately $104 million spent on development capital related to the Plum Point Project during the year ended December 31, 2009. Capital spending in our Gas and DNE segments primarily consisted of maintenance projects.

We expect capital expenditures for 2012 to be approximately $79 million, which is comprised of $76 million and $3 million in Gas and Other, respectively. The capital budget is subject to revision as opportunities arise or circumstances change. Additionally, we expect capital expenditures for 2012 related to Coal subsequent to the DMG Acquisition on June 5, 2012 to approximate $79 million.

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.

The SPDES permit renewal application at our Roseton power generating facility has been challenged by local environmental groups which contend the existing once-through water cooling system should be replaced with a closed-cycle cooling system. A decision to install a closed-cycle cooling system at the Roseton facility would be made considering all relevant factors at such time, including any relevant costs or applicable remediation requirements. If mandated installation of a closed-cycle cooling system would result in a material capital expenditure that renders the operation of a plant uneconomical, we could, at our option, and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate such facility and forego these capital expenditures. In connection with the DH Chapter 11 Cases, the DH Debtor Entities have rejected the leases of the Roseton and Danskammer power generation facilities located in Newburgh, New York. 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 read Note 3—Chapter 11 Cases for further discussion regarding the Roseton lease.

Asset Dispositions. Proceeds from asset sales in 2009 totaled $1,095 million. Of the total $1,476 million in cash proceeds received at the closing of the LS Power Transactions, $990 million related to the disposition of assets, including our interest in the Sandy Creek Project. We also received $175 million from the release of restricted cash on our consolidated balance sheets that had been used to support our funding commitment to the Sandy Creek Project. Please read Note 5—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—LS Power Transactions for further information. The remaining $214 million of cash received upon closing the LS Power Transactions related to the issuance of $235 million of notes payable and is included in Financing Activities. Please read "—Financing Activities" below and Note 21—Related Party Transactions—Transactions with LS Power for further discussion.

Additionally, during 2009, we sold the Heard County power generation facility for approximately $105 million, net of transaction costs. Please read Note 5—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Heard County for further discussion.

Other Investing Activities. Cash inflows related to maturities of short-term investments for the twelve months ended December 31, 2011 totaled $419 million. Cash outflows for purchases of short-term investments during the twelve months ended December 31, 2011 totaled $244 million.

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Cash inflows related to short-term investments during the year ended December 31, 2010 totaled $302 million, reflecting maturities and early redemptions of short-term investments. Cash outflows related to purchases of short-term investments during the year ended December 31, 2010 totaled $477 million.

Cash inflows related to short-term investments during the year ended December 31, 2009 totaled $16 million, reflecting a distribution of our short-term investments.

There was a $222 million cash inflow related to restricted cash balances during the twelve months ended December 31, 2011 primarily due to (i) the release of $850 million upon the termination of the Company's former Fifth Amended and Restated Credit Agreement, (ii) the release of $43 million upon the completion of the Sithe Tender Offer, (iii) the return of $75 million cash collateral and (iv) the release of $50 million related to the expiration of a security and deposit agreement. These decreases in restricted cash were partially offset by increases of $662 million, $103 million and $27 million associated with the DPC Credit Agreement, the DMG Credit Agreement and a DH Letter of Credit Reimbursement and Collateral Agreement, respectively.

There was also a $441 million cash outflow as a result of the DMG Transfer on September 1, 2011.

There was a $15 million cash outflow related to our funding commitment obligation under the PPEA Sponsor Support Agreement and a $3 million cash outflow due to changes in restricted cash balances during the year ended December 31, 2010. There was a $190 million cash inflow during the year ended December 31, 2009 related to changes in restricted cash balances primarily due to the release of $175 million of restricted cash that was used to support our funding commitment to the Sandy Creek Project.

Other included $10 million and $3 million of property insurance claim proceeds during the twelve months ended December 31, 2011 and 2009, respectively.

Financing Activities

Historical Cash Flow from Financing Activities. Cash flow provided by financing activities totaled $375 million during the twelve months ended December 31, 2011. Proceeds from long-term borrowings of $2,022 million, net of $44 million of debt issuance costs, consisted of:


•	$1,078 million of cash proceeds from the $1,100 million DPC Credit Agreement;


•	$588 million of cash proceeds from the $600 million DMG Credit Agreement; and


•	$400 million from a borrowing under the revolving portion of our former Fifth Amended and Restated Credit Agreement.

These proceeds were partially offset by repayments of borrowings of $1,626 million, which consisted of the following:


•	$850 million term facility under our former Fifth Amended and Restated Credit Agreement;


•	$400 million under the revolving portion of our former Fifth Amended and Restated Credit Agreement;


•	$80 million in repayment of our 6.875 percent senior notes;


•	$68 million in repayment of our Tranche B term loan;


•	$225 million in repayment of borrowings on Sithe senior debt; and


•	$3 million in payments on the DPC Credit Agreement

We also paid debt extinguishment costs of $21 million in connection with the termination of the Sithe senior debt.

Net cash used in financing activities during the twelve months ended December 31, 2010 totaled $69 million due to the payments of $62 million in aggregate principal amount on our Sithe 9.00 percent secured bonds due 2013 and $6 million of financing fees.

Net cash used in financing activities during the twelve months ended December 31, 2009 totaled $1,193 million, including $585 million in aggregate dividend payments to Dynegy Inc. Repayments of borrowings were $890 million, and consisted of the following:


•	$421 million in aggregate principal amount on our 6.875 percent senior unsecured notes due 2011 ("2011 Notes");

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•	$412 million in aggregate principal amount on our 8.75 percent senior unsecured notes due 2012 ("2012 Notes"); and


•	$57 million in aggregate principal amount on our Sithe 9.00 percent secured bonds due 2013.

We also paid debt extinguishment costs of $46 million in connection with the repayment of the 2011 Notes and 2012 Notes.

These payments were partially offset by $328 million of net proceeds from the following borrowings:


•	$130 million under the PPEA Credit Agreement Facility; and


•	$214 million of cash proceeds from the LS Power Transactions allocated to the issuance of $235 million of 7.5 percent senior unsecured notes due 2015.

These borrowings were partly offset by $16 million of financing fees related to an amendment of our former Fifth Amended and Restated Credit Agreement.

Summarized Debt and Other Obligations. The following table depicts our third party debt obligations, and the extent to which they are secured as of December 31, 2011 and 2010:



	Year ended December 31,
	2011			2010
	(in millions)
First secured obligations	$	1,097		$	918
Unsecured obligations (1)	3,570			3,644
Lease obligations (2)	—			590
Sithe secured non-recourse obligation	—			225
Total obligations	4,667			5,377
Less: Lease obligations (2)	—			(590		)
Other (3)	(21		)	(13		)
Total notes payable and long-term debt (4)	$	4,646		$	4,774

_______________________________________________________________________________


(1)	Our unsecured obligations as of December 31, 2011 are subject to compromise as a result of our bankruptcy filing on November 7, 2011. Please read Note 3—Chapter 11 Cases for further discussion.


(2)	Represents present value of future lease payments associated with the leases of the Roseton and Danskammer facilities discounted at 10 percent at December 31, 2010. In December 2011, the Bankruptcy Court entered a stipulated order approving the rejection of the leases. For additional discussion please read Note 3—Chapter 11 Cases and "Contractual Obligations" below.


(3)	Consists of net discounts on debt.


(4)	Does not include letters of credit.

Please read Note 20—Debt for further discussion of these items. Our consolidated debt maturity profile as of December 31, 2011, excluding the senior notes and debentures that are subject to compromise in the bankruptcy process, as of December 31, 2011 includes $7 million in 2012, $7 million in 2013, $6 million in 2014, $6 million in 2015, $1,050 million in 2016 and zero thereafter, all of which relate to the DPC Credit Agreement.

Financing Trigger Events. The debt instruments and other financial obligations related to our subsidiaries which have not filed for bankruptcy protection include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events connected to the financing of our non-debtor subsidiaries include the violation of covenants, defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events, acceleration of other financial obligations and change of control provisions. Our non-debtor subsidiaries do not have any trigger events tied to specified credit ratings or stock price in 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 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

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covenants and requirements that, if not met, could require early payment or similar actions.

Financial Covenants. Following the termination of DH's Fifth Amended and Restated Credit Agreement on August 5, 2011, we are no longer 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's	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 and rating of our senior unsecured bonds after the DH Debtor Entities filed the Chapter 11 Cases. Standard & Poor's withdrew its Corporate family rating and the rating of our 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. Details on these obligations are set forth below.

Contractual Obligations

The following table summarizes the contractual obligations of the Company and its consolidated subsidiaries as of December 31, 2011. Cash obligations reflected are not discounted and do not include accretion or dividends.



	Expiration by Period
	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
	(in millions)
Debt subject to compromise	$	3,570	$	88	$	—	$	1,832	$	1,650
Interest payments on debt subject to compromise	1,763		278		548		409		528
Long-term debt (including current portion)	1,076		7		13		1,056		—
Interest payments on debt	464		101		199		164		—
Coal commitments (1)	449		179		184		86		—
Operating leases	378		324		35		12		7
Capacity payments	257		39		78		55		85
Interconnection obligations	16		1		2		2		11
Construction service agreements	258		29		95		94		40
Other obligations	61		14		37		1		9
Total contractual obligations	$	8,292	$	1,060	$	1,191	$	3,711	$	2,330

_______________________________________________________________________________


(1)	Included based on nature of purchase obligations under associated contracts.

Long-Term Debt (Including Current Portion) Subject to Compromise. Total amounts of Long-term debt (including current portion) include approximately $3.6 billion in senior notes and debentures issued by the Company that are subject to

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compromise in the bankruptcy process. Please read Note 3—Chapter 11 Cases and Note 19—Liabilities Subject to Compromise for further discussion.

Interest Payments on Debt Subject to Compromise. Interest payments on debt subject to compromise represent periodic interest payment obligations associated with our senior notes and debentures and subordinated notes that are subject to compromise in the bankruptcy process. However, we are not currently making interest payments on the debt due to our bankruptcy filing. Please read Note 3—Chapter 11 Cases for further discussion.

Long-Term Debt (Including Current Portion). Long-term debt includes amounts related to the DPC Credit Agreement. Please read Note 20—Debt—DPC Credit Agreement for further discussion.

Interest Payments on Debt. Interest payments on debt represent estimated periodic interest payment obligations associated with the DPC Credit Agreement. Please read Note 20—Debt—DPC Credit Agreement for further discussion.

Coal Commitments. At December 31, 2011, our subsidiaries had contracts in place to purchase coal for various generation facilities. Obligations related to the purchase of the coal are $449 million through 2015. Approximately $433 million of the coal purchased under these contracts will be sold to DMG, an indirect wholly-owned subsidiary of Dynegy.

Operating Leases. Operating leases include $300 million, which represented our best estimate of the amount of the allowed claim related to the termination of the DNE lease and is subject to compromise in the bankruptcy process as of December 31, 2011. Please read Note 3—Chapter 11 Cases and Note 19—Liabilities Subject to Compromise for further discussion. Operating leases also includes minimum lease payment obligations associated with office and office equipment leases.

In addition, a subsidiary of the Company is party to two charter party agreements relating to two VLGCs previously utilized in our former global liquids business. The aggregate minimum base commitments of the charter party agreements are approximately $18 million for 2012 and approximately $23 million in aggregate for the period from 2013 through lease expiration. The charter party rates payable under the two charter party agreements vary in accordance with market-based rates for similar shipping services. The $18 million and $23 million amounts set forth above are based on the minimum obligations set forth in the two charter party agreements. The primary terms of the charter party agreements expire September 2013 and September 2014, respectively. Both VLGCs have been sub-chartered to a wholly-owned subsidiary of Transammonia Inc. The terms of the sub-charters are identical to the terms of the original charter agreements. The subsidiary of the Company relies on the sub-charters with a subsidiary of Transammonia to satisfy the obligations of the two charter party agreements. To date, the subsidiary of Transammonia has complied with the terms of the sub-charter agreements.

Capacity Payments. Capacity payments include fixed obligations associated with transmission, transportation and storage arrangements totaling approximately $257 million.

Interconnection Obligations. Interconnection obligations represent an obligation with respect to interconnection services for the Ontelaunee facility. This agreement expires in 2027. The obligation under this agreement is approximately $1 million per year through the term of the contract.

Construction Service Agreements. Construction service agreements represent obligations with respect to long-term plant maintenance agreements. The obligation under these agreements is approximately $258 million.

Other Obligations. Other obligations primarily include the following items:


•	Demolition and restoration obligation associated with the South Bay facility of $37 million;


•	Payments associated with a capacity contract between Independence and Con Edison. The aggregate payments through the 2014 expiration are approximately $6 million as of December 31, 2011;


•	Obligations of $5 million for harbor support and utility work in connection with Moss Landing;


•	Reserves of $4 million recorded in connection with uncertain tax positions. Please read Note 22—Income Taxes—Unrecognized Tax Benefits for further discussion;


•	Obligations of $3 million primarily for water supply agreement and other contracts in connection with Ontelaunee;


•	Obligations of $2 million primarily for Morro Bay city improvements in connection with our Morro Bay facility;


•	Obligations of $2 million related to information technology related contracts; and


•	Severance and retention obligations of $2 million as of December 31, 2011 in connection with a reduction in

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workforce and the closure of certain power generation facilities. Please read Note 8—Impairment and Restructuring Charges—Restructuring Charges for further discussion.

Contingent Financial Obligations

The following table provides a summary of the contingent financial obligations of the Company and our consolidated subsidiaries as of December 31, 2011 on an undiscounted basis. These obligations represent contingent obligations that may require a payment of cash upon the occurrence of specified events. We were deconsolidated effective November 7, 2011 and subsequently accounted for under the equity method accounting. We have included the following disclosure because we believe it is meaningful to investors.



	Expiration by Period
	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
	(in millions)
Letters of credit(1)	$	412	$	412	$	—	$	—	$	—
Surety bonds(2)	9		9		—		—		—
Guarantees	2		2		—		—		—
Total financial commitments	$	423	$	423	$	—	$	—	$	—

_______________________________________________________________________________


(1)	Amount includes outstanding letters of credit.


(2)	Surety bonds are generally on a rolling 12-month basis. The $9 million of surety bonds are primarily supported by collateral.

Commitments and Contingencies

Please read Note 23—Commitments and Contingencies, which is incorporated herein by reference, for further discussion of our material commitments and contingencies.

RESULTS OF OPERATIONS

Overview and Discussion of Comparability of Results. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the years ended December 31, 2011, 2010 and 2009. At the end of this section, we have included our business outlook for each segment.

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, Dynegy and Dynegy Gas Investments, LLC ("DGIN") consummated the DMG Transfer; therefore, the results of our Coal segment are only included in our consolidated results through August 31, 2011. On June 5, 2012, the effective date of the Settlement Agreement, we reacquired Coal Holdco. Please read Note 3—Chapter 11 Cases—Settlement Agreement and Plan Support Agreement and Note 27—Subsequent Events for further discussion.

Consolidated Summary Financial Information—Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

The following tables provide summary financial data regarding our consolidated and segmented results of operations for the years ended December 31, 2011 and 2010, respectively.

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	Years Ended December 31,
	2011			2010			Change			% Change
Revenues	$	1,437		$	2,323		$	(886	)	(38	)%
Cost of sales	(931		)	(1,181		)	250			21	%
Gross margin, exclusive of depreciation shown separately below	506			1,142			(636		)	(56	)%
Operating and maintenance expense, exclusive of depreciation shown separately below	(364		)	(450		)	86			19	%
Depreciation and amortization expense	(288		)	(392		)	104			27	%
Impairment and other charges	(7		)	(148		)	141			95	%
Gain on sale of assets	1			—			1			100	%
General and administrative expenses	(102		)	(158		)	56			35	%
Operating loss	(254		)	(6		)	(248		)	(4,133	)%
Bankruptcy reorganization charges	(666		)	—			(666		)	(100	)%
Losses from unconsolidated investments	—			(62		)	62			100	%
Interest expense	(349		)	(363		)	14			4	%
Debt extinguishment costs	(21		)	—			(21		)	(100	)%
Other income and expense, net	35			4			31			775	%
Loss from continuing operations before income taxes	(1,255		)	(427		)	(828		)	(194	)%
Income tax benefit	315			184			131			71	%
Loss from continuing operations	(940		)	(243		)	(697		)	(287	)%
Income from discontinued operations, net of taxes	—			1			(1		)	(100	)%
Net loss	$	(940	)	$	(242	)	$	(698	)	(288	)%

The following tables provide summary financial data regarding our operating income (loss) by segment for the years ended December 31, 2011 and 2010, respectively:



	Year Ended December 31, 2011
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	460		$	872		$	104		$	1		$	1,437
Cost of sales	(237		)	(629		)	(65		)	—			(931		)
Gross margin, exclusive of depreciation shown separately below	223			243			39			1			506
Operating and maintenance expense, exclusive of depreciation shown separately below	(105		)	(148		)	(110		)	(1		)	(364		)
Depreciation and amortization expense	(156		)	(132		)	7			(7		)	(288		)
Impairment and other charges	—			—			(2		)	(5		)	(7		)
Gain on sale of assets, net	—			—			1			—			1
General and administrative expenses	(27		)	(62		)	(10		)	(3		)	(102		)
Operating loss	$	(65	)	$	(99	)	$	(75	)	$	(15	)	$	(254	)

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	Year Ended December 31, 2010
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	837		$	1,223		$	264		$	(1	)	$	2,323
Cost of sales	(355		)	(707		)	(121		)	2			(1,181		)
Gross margin, exclusive of depreciation shown separately below	482			516			143			1			1,142
Operating and maintenance expense, exclusive of depreciation shown separately below	(175		)	(153		)	(120		)	(2		)	(450		)
Depreciation and amortization expense	(256		)	(135		)	5			(6		)	(392		)
Impairment and other charges	(4		)	(136		)	(2		)	(6		)	(148		)
General and administrative expenses	(52		)	(69		)	(15		)	(22		)	(158		)
Operating income (loss)	$	(5	)	$	23		$	11		$	(35	)	$	(6	)

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $886 million from $2,323 million for the year ended December 31, 2010 to $1,437 million for the year ended December 31, 2011. Of this decrease, approximately $185 million is due to the DMG Transfer. The remaining decrease of $701 million is primarily due to:

•

Approximately $288 million related to the difference between mark-to-market losses on forward sales of power and other derivatives in 2011, compared to mark-to-market gains in 2010. Such losses totaled $188 million for the year ended December 31, 2011, compared to $100 million of mark-to-market gains for the year ended December 31, 2010. The mark-to-market losses for the year ended December 31, 2011 included fees of approximately $8 million paid to brokers in connection with the Reorganization.


•	Approximately $413 million related to lower generated volumes and market prices as well as less revenue from capacity sales, RMR agreements, option premiums and the financial settlement of derivative instruments, as further described below.

Cost of Sales. Cost of sales decreased by $250 million from $1,181 million for the year ended December 31, 2010 to $931 million for the year ended December 31, 2011. Of this decrease, approximately $123 million is due to the DMG Transfer. The remaining decrease of approximately $127 million is due to lower generated volumes and lower gas and coal prices, as further described below.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. Operating and maintenance expense decreased by $86 million from $450 million for the year ended December 31, 2010 to $364 million for the year ended December 31, 2011. Of this decrease, approximately $57 million is due to the DMG Transfer. The remaining decrease of approximately $29 million is due to the mothballing and subsequent retirement of the Vermilion facility in 2011, the retirement of the South Bay facility in late 2010 and a curtailment gain due to a change in Dynegy's post retirement benefit plan in 2011.

Depreciation and Amortization Expense. Depreciation expense decreased by $104 million from $392 million for the year ended December 31, 2010 to $288 million for the year ended December 31, 2011. Of this decrease, approximately $117 million is due to the DMG Transfer.

Impairment and Other Charges. Impairment and other charges for the year ended December 31, 2011 includes $2 million in impairment charges related to the Roseton and Danskammer facilities and $5 million restructuring costs. Impairment and other charges for the year ended December 31, 2010 included a pre-tax asset impairment of $134 million related to our Casco Bay power generation facility and related assets and $12 million related to severance charges for a reduction in workforce and the closure of our Vermilion and South Bay facilities. Please read Note 8—Impairment and Restructuring Charges for further discussion.

General and Administrative Expenses. General and administrative expenses decreased $56 million from $158 million for the year ended December 31, 2010 to $102 million for the year ended December 31, 2011. Of this decrease, approximately $18 million is due to the DMG Transfer. The remaining decrease of approximately $38 million was primarily driven by lower salary and benefits costs as a result of ongoing cost savings initiatives, and a reduction in the value of cash-settled stock-based compensation instruments partially offset by $5 million of severance costs and $15 million of restructuring costs in 2011.

Bankruptcy Reorganization Charges. Bankruptcy reorganization charges for the year ended December 31, 2011 were

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$666 million. These charges consisted of approximately $611 million related to the rejection of the DNE lease, approximately $55 million for the write-off of deferred financing costs related to our unsecured notes and debentures and costs related to bankruptcy advisors. We did not have any similar charges during the year ended December 31, 2010 as the Chapter 11 Cases commenced on November 7, 2011.

Losses from Unconsolidated Investments. Losses from unconsolidated investments for the year ended December 31, 2010 were $62 million related to our former investment in PPEA Holding. The losses consisted of $28 million related to the loss on sale of PPEA Holding, sold in the fourth quarter of 2010, and an impairment charge of approximately $37 million partially offset by $3 million in equity earnings primarily related to mark-to-market gains on interest rate swaps offset by financing expenses. Our investment in PPEA Holding was fully impaired at March 31, 2010 due to the uncertainty regarding PPEA's financing structure. Please read Note 16—Variable Interest Entities—PPEA Holding Company LLC for further discussion.

Interest Expense. Interest expense totaled $349 million and $363 million for the years ended December 31, 2011 and 2010, respectively. Interest expense decreased because we ceased accruing interest on our unsecured notes and debentures as a result of the commencement of the Chapter 11 Cases on November 7, 2011. This decrease was partially offset by an increase in interest expense due to higher borrowings and rates under the DMG Credit Agreement (through September 1, 2011) and the DPC Credit Agreement compared to our prior Fifth Amended and Restated Credit Agreement.

Debt Extinguishment Costs. Debt extinguishment costs totaled $21 million for the year ended December 31, 2011 and were incurred in connection with the termination of the Sithe senior debt. Please read Note 20—Debt—Sithe Senior Notes for further discussion.

Other income and expense, net. Other income and expense, net increased to $35 million of income for the year ended December 31, 2011 from income of $4 million for the year ended December 31, 2010. The increase is due to interest income on the Undertaking receivable, affiliate. Please read Note 21—Related Party Transactions—DMG Transfer and Undertaking Agreement for further discussion.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $315 million for the year ended December 31, 2011, compared to an income tax benefit from continuing operations of $184 million for the year ended December 31, 2010. The effective tax rate in 2011 was 25 percent, compared to 43 percent in 2010.

For the year ended December 31, 2011, the difference between the effective rate of 25 percent and the statutory rate of 35 percent is primarily due to the impact of state taxes partially offset by a change in our valuation allowance. For the year ended December 31, 2010, the difference between the effective rate of 43 percent and the statutory rate of 35 percent resulted primarily from a benefit of $18 million related to the release of reserves for uncertain tax positions, partially offset by the impact of state taxes.

In connection with the DMG Transfer, we recognized a deferred tax asset of approximately $466 million and subsequently recorded a valuation allowance for the full amount. We do not believe we will produce sufficient taxable income, nor are there tax planning strategies available to realize the tax benefit.

Discussion of Segment Results of Operations

Coal Segment. Effective September 1, 2011, we completed the DMG Transfer. Therefore, the results of the Coal segment (including DMG) were only included in our consolidated results of operations through August 31, 2011. Power prices were slightly lower in 2011 compared to 2010. On-peak prices were lower in 2011 compared to 2010, which was partly offset by higher off-peak prices in 2011 compared to 2010.

The following table provides summary financial data regarding our Coal segment results of operations for the years ended December 31, 2011 and 2010, respectively:

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	Year Ended December 31,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	512		$	699		$	(187	)	(27	)%
Capacity	8			17			(9		)	(53	)%
Financial transactions:
Mark-to-market income (loss)	(76		)	21			(97		)	(462	)%
Financial settlements	6			97			(91		)	(94	)%
Option premiums	14			7			7			100	%
Total financial transactions	(56		)	125			(181		)	(145	)%
Other(1)	(4		)	(4		)	—			—	%
Total revenues	460			837			(377		)	(45	)%
Cost of sales	(237		)	(355		)	118			33	%
Gross margin	$	223		$	482		$	(259	)	(54	)%
Million Megawatt Hours Generated	15.6			22.3			(6.7		)	(30	)%
In Market Availability for Coal Fired Facilities(2)	92		%	91		%
Average Quoted On-Peak Market Power Prices ($/MWh)(3):
Cinergy (Cin Hub)	$	45		$	42		$	3		7	%

_______________________________________________________________________________


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


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


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

Gross margin from the Coal segment decreased by $259 million from $482 million for the year ended December 31, 2010, to $223 million for the year ended December 31, 2011. Approximately $62 million of this decrease is the result of the DMG Transfer. The remaining decrease of $197 million was driven by the following:


•	Mark-to-market revenue decreased by $181 million due to a net change from mark-to-market revenue from $105 million in 2010 to a mark-to-market loss of $76 million in 2011.


•	Settlements revenue decreased by $26 million due to fewer volumes hedged in 2011 compared to 2010. Settlements revenue also decreased due to the average value of our hedging positions being lower in 2011 compared to 2010.


•	Capacity revenue decreased by $7 million due to lower capacity prices in the MISO capacity market in 2011 compared to 2010.

The above decreases were partially offset by an increase in energy revenue and the corresponding cost of sales by $14 million and $4 million, respectively, for a net increase in energy margin of $10 million. These increases were due to higher generation volumes. Generation volumes increased at Baldwin due to fewer outages in 2011 compared to 2010. In early 2010, Baldwin experienced a three month outage that reduced burns for 2010. While Baldwin did experience outages in 2011, they were not as significant as those in 2010.

Gas Segment. Spark-spreads in the Northeast were somewhat mixed in 2011 with improved spark-spreads in the first quarter offset by lower spark-spreads in the third quarter. Additionally, net generated volumes were lower at Casco Bay in 2011 compared to 2010 due to planned and unplanned outages. In PJM, net generated volumes were higher driven primarily by positive off-peak spark-spreads at Ontelaunee.

For the California facilities, spark-spreads were down in 2011 as compared to 2010. Robust snowpack in the Northwest United States and California led to strong hydro production; the Northwest United States recorded the second greatest hydro production since 1993. This coupled with a very mild summer, led to historical low spark-spreads. Generated volumes were down significantly due to competition with hydro generation as well as an unplanned outage.

The following table provides summary financial data regarding our Gas segment results of operations for the years ended

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December 31, 2011 and 2010, respectively.



	Year Ended December 31,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	489		$	619		$	(130	)	(21	)%
Capacity	213			231			(18		)	(8	)%
RMR	6			45			(39		)	(87	)%
Tolls	131			137			(6		)	(4	)%
Natural gas	193			169			24			14	%
Financial transactions:
Mark-to-market losses	(61		)	(11		)	(50		)	(455	)%
Financial settlements	(159		)	(117		)	(42		)	(36	)%
Option premiums	19			127			(108		)	(85	)%
Total financial transactions	(201		)	(1		)	(200		)	(20,000	)%
Other(1)	41			23			18			78	%
Total revenues	872			1,223			(351		)	(29	)%
Cost of sales	(629		)	(707		)	78			11	%
Gross margin	$	243		$	516		$	(273	)	(53	)%
Million Megawatt Hours Generated(2)	12.3			14.2			(1.9		)	(13	)%
Average Capacity Factor for Combined Cycle Facilities(3)	21		%	31		%
Average Quoted On-Peak Market Power Prices ($/MWh)(4):
Commonwealth Edison (NI Hub)	$	41		$	41		$	—		—	%
PJM West	$	51		$	54		$	(3	)	(6	)%
North of Path 15 (NP 15)	$	36		$	40		$	(4	)	(10	)%
New York—Zone A	$	42		$	44		$	(2	)	(5	)%
Mass Hub	$	53		$	56		$	(3	)	(5	)%
Average Market Spark Spreads ($/MWh)(5):
PJM West	$	19		$	19		$	—		—	%
North of Path 15 (NP 15)	$	4		$	6		$	(2	)	(33	)%
New York—Zone A	$	9		$	9		$	—		—	%
Mass Hub	$	18		$	18		$	—		—	%
Average natural gas price—Henry Hub ($/MMBtu)(6)	$	3.99		$	4.38		$	(0.39	)	(9	)%

_______________________________________________________________________________


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


(2)	Includes hours generated for the full year 2011 and 2010 and also includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility.


(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 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.


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

Gross margin for the Gas segment decreased by $273 million from $516 million for the year ended December 31, 2010, to $243 million for the year ended December 31, 2011. This decrease was driven by the following:


•	Premium revenue decreased by $108 million due to fewer options sold and fewer premiums collected in 2011 compared to 2010 due to a decline in price volatilities. Market volatilities have been in decline for the past two years,

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reducing the value of options on a unit basis and diminishing the revenue opportunities from their sale. Additionally, fewer option sales have resulted from our strategy of leaving more of our portfolio open to a market recovery expected over the next few years while we opportunistically hedge short-term cash flows.

•

Energy revenue and the corresponding cost of sales decreased by $130 million and $78 million, respectively, for a net decrease in energy margin of $52 million. Energy revenue and cost of sales decreased due to lower market pricing across the region and lower volumes generated. Volumes were down due to lower spark spreads at Moss Landing and Casco Bay in 2011 compared to 2010. Volumes were also down due to more outages at Moss Landing and Casco Bay in 2011 compared to 2010. Both plants experienced significant outages in 2011 due to required turbine blade repairs. These decreases were partially offset by increases in volumes at Kendall and Ontelaunee which both saw an increase in generation volumes due to fewer outages and derates in 2011 compared to 2010 as well as improved spark spreads in 2011.


•	Mark-to-market revenue decreased by $50 million due to a net change in mark-to-market losses from $11 million in 2010 compared to $61 million in 2011.


•	RMR revenue decreased by $39 million due to the expiration of the South Bay RMR agreement. The CAISO elected not to renew the agreement for 2011 and the facility was permanently retired on December 31, 2010.


•	Capacity revenue decreased by $18 million due to lower capacity prices in the NYISO, PJM and Mass Hub markets in 2011 compared to 2010. Capacity prices have decreased significantly year over year due to excess capacity in the market.


•	Tolling revenue decreased by $6 million due to the termination of the Kendall Constellation toll in 2010. In connection with the termination of the Kendall toll in 2010, we received a termination payment which was not repeated in 2011. The decrease from the 2010 cancellation payment was partially offset by higher revenues from the Moss Landing toll which was renewed with higher rates for 2011.

The above decreases were partially offset by the following increases:


•	Natural gas revenue increased by $24 million due to an increase in volumes sold in 2011 compared to 2010. The increase in volumes sold is due to lower 2011 power generation primarily at Independence. The decrease in power generation made more gas available to be sold back to the market as it was not required for production.


•	Other revenue increased by $18 million primarily due to an increase in ancillary pricing in the PJM market and increased 2011 off-peak generation at Ontelaunee which provided the opportunity to supply more ancillary services.

DNE Segment. Average spark spreads have stayed flat year over year. During the year, dark spreads at Danskammer were compressed by lower Zone G prices and increased coal prices. These compressed spark spreads more than offset the increases in spreads from earlier in the year. In addition, increased imports from the NE-ISO impacted our results.

The following table provides summary financial data regarding our DNE segment results of operations for the years ended December 31, 2011 and 2010, respectively.

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	Year Ended December 31,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	93		$	142		$	(49	)	(35	)%
Capacity	17			41			(24		)	(59	)%
Financial transactions:
Mark-to-market income (loss)	(46		)	18			(64		)	(356	)%
Financial settlements	35			32			3			9	%
Option premiums	2			7			(5		)	(71	)%
Total financial transactions	(9		)	57			(66		)	(116	)%
Other(1)	3			24			(21		)	(88	)%
Total revenues	104			264			(160		)	(61	)%
Cost of sales	(65		)	(121		)	56			46	%
Gross margin	$	39		$	143		$	(104	)	(73	)%
Million Megawatt Hours Generated(2)	1.2			2.2			(1.0		)	(45	)%
In Market Availability for Coal Fired Facilities(3)	97		%	95		%
Average Capacity Factor—Coal	21		%	53		%
Average Capacity Factor—Gas	3		%	4		%
Average Quoted On-Peak Market Power Prices ($/MWh)(4):
New York—Zone G	$	57		$	59		$	(2	)	(3	)%
Average Market Spark Spreads ($/MWh)(5):
Fuel Oil	$	(121	)	$	(72	)	$	(49	)	(68	)%

_______________________________________________________________________________


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


(2)	Includes hours generated for the full year 2011 and 2010.


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


(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 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 the DNE segment decreased by $104 million from $143 million for the year ended December 31, 2010, to $39 million for the year ended December 31, 2011. This decrease was driven by the following:


•	Mark-to-market revenue decreased by $64 million due to a net change in mark-to-market revenue of $18 million in 2010 to a mark-to-market loss of $46 million in 2011.


•	Capacity revenue decreased by $24 million due to lower capacity prices in the NYISO capacity market in 2011 compared to 2010.


•	Other revenue decreased by $21 million primarily due to the 2010 sale of Roseton fuel oil. There were no corresponding fuel oil sales in 2011.

•

Energy revenue and the corresponding cost of sales both decreased by $49 million and $56 million, respectively, for a net increase in energy margin of $7 million. Energy revenue and cost of sales decreased due to lower volumes generated. The decrease in volumes is due to the cycling of units at Danskammer and economic conditions. Danskammer began cycling units D3 and D4 to reduce generation in non-profitable off-peak hours which has decreased generation volumes but increased the average price per MWh sold. Volumes were also down due to generation costs associated with Roseton and Danskammer being higher than what could have been realized in the market for longer periods of time in 2011 compared to 2010. Also impacting Roseton volumes in 2010, was a third party nuclear facility located in the Northeast that was down for an extended period which resulted in Roseton being dispatched more in 2010 compared to 2011.

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Consolidated Summary Financial Information—Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

The following tables provide summary financial data regarding our consolidated and segmented results of operations for the years ended December 31, 2010 and 2009, respectively.



	Years Ended December 31,
	2010			2009			Change			% Change
Revenues	$	2,323		$	2,468		$	(145	)	(6	)%
Cost of sales	(1,181		)	(1,194		)	13			1	%
Gross margin, exclusive of depreciation shown separately below	1,142			1,274			(132		)	(10	)%
Operating and maintenance expense, exclusive of depreciation shown separately below	(450		)	(521		)	71			14	%
Depreciation and amortization expense	(392		)	(335		)	(57		)	(17	)%
Goodwill impairment	—			(433		)	433			100	%
Impairment and other charges	(148		)	(538		)	390			72	%
Loss on sale of assets, net	—			(124		)	124			100	%
General and administrative expenses	(158		)	(159		)	1			1	%
Operating loss	(6		)	(836		)	830			99	%
Losses from unconsolidated investments	(62		)	(72		)	10			14	%
Interest expense	(363		)	(415		)	52			13	%
Debt extinguishment costs	—			(46		)	46			100	%
Other income and expense, net	4			10			(6		)	(60	)%
Loss from continuing operations before income taxes	(427		)	(1,359		)	932			69	%
Income tax benefit	184			313			(129		)	(41	)%
Loss from continuing operations	(243		)	(1,046		)	803			77	%
Income (loss) from discontinued operations, net of taxes	1			(222		)	223			100	%
Net loss	(242		)	(1,268		)	1,026			81	%
Less: Net loss attributable to noncontrolling interests	—			(15		)	15			100	%
Net loss attributable to Dynegy Inc.	$	(242	)	$	(1,253	)	$	1,011		81	%

The following tables provide summary financial data regarding our operating income (loss) by segment for the years ended December 31, 2010 and 2009, respectively:



	Year Ended December 31, 2010
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	837		$	1,223		$	264		$	(1	)	$	2,323
Cost of sales	(355		)	(707		)	(121		)	2			(1,181		)
Gross margin, exclusive of depreciation shown separately below	482			516			143			1			1,142
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(175		)	(153		)	(120		)	(2		)	(450		)
Depreciation and amortization expense	(256		)	(135		)	5			(6		)	(392		)
Impairment and other charges	(4		)	(136		)	(2		)	(6		)	(148		)
General and administrative expenses	(52		)	(69		)	(15		)	(22		)	(158		)
Operating income (loss)	$	(5	)	$	23		$	11		$	(35	)	$	(6	)

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	Year Ended December 31, 2009
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	941		$	1,260		$	273		$	(6	)	$	2,468
Cost of sales	(345		)	(716		)	(134		)	1			(1,194		)
Gross margin, exclusive of depreciation shown separately below	596			544			139			(5		)	1,274
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(182		)	(217		)	(123		)	1			(521		)
Depreciation and amortization expense	(161		)	(148		)	(8		)	(18		)	(335		)
Goodwill impairments	—			(433		)	—			—			(433		)
Impairment and other charges	(42		)	(284		)	(212		)	—			(538		)
Loss on sale of assets, net	(6		)	(118		)	—			—			(124		)
General and administrative expenses	(49		)	(96		)	(13		)	(1		)	(159		)
Operating income (loss)	$	156		$	(752	)	$	(217	)	$	(23	)	$	(836	)

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $145 million from $2,468 million for the year ended December 31, 2009 to $2,323 million for the year ended December 31, 2010. Of this decrease $386 million related to less revenue generated from the financial settlement of derivative instruments. The decrease from financial settlements was partially offset by an increase of $201 million in mark-to-market revenue from forward sales of power and other derivatives. Such gains totaled $21 million for the year ended December 31, 2010, compared to $180 million in mark-to-market losses for the year ended December 31, 2009.

The decrease from financial settlements was further offset by increases from gas sales, RMR agreements and ancillary services which in turn were offset by decreases from capacity sales and tolling agreements, as further described below.

Cost of Sales. Cost of sales decreased by $13 million from $1,194 million for the year ended December 31, 2009 to $1,181 million for the year ended December 31, 2010. This decrease is primarily due to lower generated volumes, as further described below.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. Operating and maintenance expense decreased by $71 million from $521 million for the year ended

Commission
File Number

State of
Incorporation

I.R.S. Employer
Identification No.

Dynegy Holdings, LLC

601 Travis, Suite 1400
Houston, Texas
(Address of principal
executive offices)

77002
(Zip Code)

DYNEGY HOLDINGS, LLC 10-K