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, ~~2010~~2011

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

For the transition period from ________ to ________

DYNEGY HOLDINGS, ~~INC.~~LLC

DYNEGY HOLDINGS INC.

(Exact name of registrant as specified in its charter)

Entity	~~Commission~~CommissionFile ~~File~~ Number	State ~~of Incorporation~~ofIncorporation	I.R.S. ~~Employer~~EmployerIdentification ~~Identification~~ No.
Dynegy Inc. Dynegy Holdings Inc.	001-33443 000-29311	Delaware Delaware	20-5653152 94-3248415
Dynegy Holdings, LLC	000-29311	Delaware	94-3248415
1000 Louisiana, Suite 5800 Houston, Texas (Address of principal executive offices)			77002 (Zip Code)
601 Travis, Suite 1400Houston, Texas(Address of principalexecutive offices)			77002(Zip Code)

(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
Dynegy’s common stock, $0.01 par value		New York Stock Exchange




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

~~Dynegy~~Indicate ~~Inc.~~by ~~Yes~~check xmark Noif othe ~~Dynegy~~registrant ~~Holdings~~is ~~Inc.~~not ~~Yes~~required oto Nofile xreports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý

Indicate by check mark ifwhether the registrant is(1) has ~~not~~filed all reports required to ~~file~~be ~~reports~~filed ~~pursuant~~by to Section 13 or ~~Section~~ 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

~~Dynegy Inc. Yes o No x Dynegy Holdings Inc. Yes o No x~~1

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

~~Dynegy~~file ~~Inc.~~such ~~Yes~~reports), xand No(2) has obeen ~~Dynegy~~subject ~~Holdings~~to ~~Inc.~~such ~~Yes~~filing xrequirements Nofor 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~~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

~~Dynegy~~Indicate ~~Inc.~~by ~~Yes~~check omark Noif odisclosure ~~Dynegy~~of ~~Holdings~~delinquent ~~Inc.~~filers ~~Yes~~pursuant oto NoItem 405 oof 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 ifwhether ~~disclosure~~the ofregistrant ~~delinquent~~is ~~filers~~a ~~pursuant~~large toaccelerated ~~Item~~filer, ~~405~~an ofaccelerated ~~Regulation~~filer, Sa non-Kaccelerated ~~is not contained herein~~filer, ~~and~~or ~~will~~a ~~not~~smaller bereporting ~~contained,~~company. toSee the ~~best~~definitions of ~~registrant’s~~"large ~~knowledge~~accelerated filer," in"accelerated ~~definitive~~filer" ~~proxy~~and or"smaller ~~information~~reporting ~~statements~~company" ~~incorporated by reference~~ in ~~Part~~Rule 12b-2 ~~III~~ of ~~this~~the ~~Form~~Exchange ~~10-K or any amendment to this Form 10-K~~Act.

~~Dynegy~~Large ~~Inc.~~accelerated xfiler ~~Dynegy~~o ~~Holdings~~Accelerated ~~Inc.~~filer x¨ Non-accelerated filer ý Smaller reporting company o (Do not check if asmaller reporting company)

Indicate by check mark whether the registrant is a ~~large~~shell ~~accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting~~ company. ~~See~~(as ~~the~~defined ~~definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company”~~ in Rule 12b-2 of the Exchange Act). Yes o No ý

~~Large~~All ~~accelerated~~of ~~filer~~the ~~Accelerated~~registrant’s ~~filer~~outstanding ~~Non-accelerated~~membership ~~filer~~interests ~~(Do~~are ~~not~~owned ~~check~~directly ifby ~~a smaller reporting company) Smaller reporting company~~ Dynegy Inc. ~~o x o o Dynegy Holdings Inc. o o x o~~

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

~~Dynegy Inc. Yes o No x Dynegy Holdings Inc. Yes o No x~~None

As of June 30, 2010, the aggregate market value of the Dynegy Inc. common stock held by non-affiliates of the registrant was $463,782,138 based on the closing sale price as reported on the New York Stock Exchange.2

~~Number~~Table of shares outstanding of Dynegy Inc’s class of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 121,209,325 shares outstanding as of March 3, 2011. All of Dynegy Holdings Inc.’s outstanding common stock is owned indirectly by Dynegy Inc.Contents

~~This~~EXPLANATORY combined Form 10-K is separately filed by Dynegy Inc. and Dynegy Holdings Inc. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to a registrant other than itself.NOTE

~~DOCUMENTS~~As ~~INCORPORATED~~explained BYherein, ~~REFERENCE-~~on November 7, 2011, we and four of our wholly owned subsidiaries, Dynegy Northeast Generation, Inc. ~~Part~~ ~~III~~(“Dynegy Northeast Generation”), Hudson Power, L.L.C. (~~Items~~“Hudson”), 10Dynegy Danskammer, 11L.L.C. (“Danskammer”) and Dynegy Roseton, 12L.L.C. (“Roseton”, 13and together with us, DNE, Hudson and ~~14)~~Danskammer, ~~incorporates~~the by“DH ~~reference~~Debtor ~~portions~~Entities”) offiled voluntary petitions (the ~~Notice~~“DH ~~and~~Chapter ~~Proxy~~11 ~~Statement~~Cases”) for ~~the~~relief ~~registrant’s~~under ~~2011~~Chapter 11 ~~Annual~~of ~~Meeting~~Title 11 of ~~Stockholders,~~the ~~which~~United States Code (the ~~registrant~~"Bankruptcy ~~intends~~Code") toin ~~file~~the noUnited ~~later~~States ~~than~~Bankruptcy ~~120~~Court ~~days~~for ~~after~~the ~~December~~Southern 31District of New York, ~~2010~~Poughkeepsie Division (the "Bankruptcy Court"). Since ~~However,~~filing ifthe ~~such~~DH ~~proxy~~Chapter ~~statement~~11 isCases, we have not filed ~~within~~our ~~such~~quarterly ~~120~~reports on Form 10-~~day~~Q ~~period,~~or ~~Items~~our annual report on Form 10-K with the SEC. On the filing date hereof,11 we are simultaneously filing our quarterly report for the third quarter of 2011,12 our annual report for the year ended December 31,13 2011, and 14our ~~will~~quarterly bereports ~~filed~~for asthe ~~part~~first and second quarters of an2012. ~~amendment~~In each of these reports, in a note to ~~this~~the ~~Form~~financial ~~10-K~~statements, nowe ~~later~~have ~~than~~disclosed recent material developments with respect to our business, including with respect to the ~~end~~DH Chapter 11 Cases and other legal proceedings, in each case, as of the ~~120~~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-~~day~~Q ~~period~~for the second quarter of 2012.

REDUCED DISCLOSURE FORMAT-Dynegy Holdings Inc. Dynegy Holdings Inc. meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and therefore is filing this Form 10-K with the reduced disclosure format.i

~~DYNEGY~~Table ~~INC.~~of ~~and DYNEGY HOLDINGS INC.~~Contents

DYNEGY HOLDINGS, LLC

FORM 10-K

TABLE OF CONTENTS

		~~Page~~	Page
PART I
Definitions		2	1
Item 1.	~~Business—Dynegy Inc. and Dynegy Holdings Inc.~~	4Business	4
Item 1A.	~~Risk Factors—Dynegy Inc. and Dynegy Holdings Inc.~~	25Risk Factors	24
Item 1B.	~~Unresolved Staff Comments—Dynegy Inc. and Dynegy Holdings Inc.~~	36Unresolved Staff Comments	33
Item 2.	~~Properties—Dynegy Inc. and Dynegy Holdings Inc.~~	36Properties	33
Item 3.	~~Legal Proceedings—Dynegy Inc. and Dynegy Holdings Inc.~~	36Legal Proceedings	33
PART II
Item 4.		Mine Safety Disclosures	33
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities—Dynegy Inc.	37
PART II
Item 6.	Selected Financial Data—Dynegy Inc. and Dynegy Holdings Inc.	41
Item 5.		Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations—Dynegy Inc. and Dynegy Holdings Inc.	44
Item 6.		Selected Financial Data	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk—Dynegy Inc. and Dynegy Holdings Inc.	95
Item 7.		Management's Discussion and Analysis of Financial Condition and Results of Operations	36
Item 8.	Financial Statements and Supplementary Data—Dynegy Inc. and Dynegy Holdings Inc.	98
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk	69
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure—Dynegy Inc. and Dynegy Holdings Inc.	98
Item 8.		Financial Statements and Supplementary Data	72
Item 9A.	Controls and Procedures—Dynegy Inc. and Dynegy Holdings Inc.	98
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	72
	Report of Independent Registered Public Accounting Firm–Dynegy Inc.	100
Item 9A.		Controls and Procedures	73
Item 9B.	Other Information—Dynegy Inc. and Dynegy Holdings Inc.	101
		Report of Independent Registered Public Accounting Firm
PART III
Item 9B.		Other Information	73
Item 10.	Directors, Executive Officers and Corporate Governance—Dynegy Inc.	102
PART III
Item 11.	Executive Compensation—Dynegy Inc.	102
Item 10.		Directors, Executive Officers and Corporate Governance	74
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Dynegy Inc.	102
Item 11.		Executive Compensation	74
Item 13.	Certain Relationships and Related Transactions, and Director Independence—Dynegy Inc.	103
Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	74
Item 14.	Principal Accountant Fees and Services—Dynegy Inc.	103
Item 13.		Certain Relationships and Related Transactions, and Director Independence	74
PART IV
Item 14.		Principal Accountant Fees and Services	74
Item 15.	Exhibits and Financial Statement Schedules—Dynegy Inc. and Dynegy Holdings Inc.	104
PART IV
Signatures		112
Item 15.		Exhibits and Financial Statement Schedules	74
Signatures			88

~~EXPLANATORY NOTE~~ii

This report includes the combined filing of Dynegy Inc. (“Dynegy”) and Dynegy Holdings Inc. (“DHI”). DHI is the principal subsidiary of Dynegy, providing approximately 100 percent of Dynegy’s total consolidated revenue for the year ended December 31, 2010 and constituting approximately 100 percent of Dynegy’s total consolidated asset base as of December 31, 2010.

Unless the context indicates otherwise, throughout this report, the terms “the Company”, “we”, “us”, “our” and “ours” are used to refer to both Dynegy and DHI and their direct and indirect subsidiaries. Discussions or areas of this report that apply only to Dynegy or DHI are clearly noted in such discussions or areas.

TABLE OF CONTENTS

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
APIC	Additional Paid-in-Capital
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
COSO	Committee of Sponsoring Organizations of the Treadway Commission
CPUC	California Public Utility Commission
CRM	Our former customer risk management business segment
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
CUSA	Chevron U.S.A. Inc.
DCIH	Dynegy Coal Intermediate Holdings, LLC
DHI	Dynegy Holdings Inc., Dynegy’s primary financing subsidiary
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
DNE	Dynegy Northeast Generation
DPC	Dynegy Power, LLC
DPM	Dynegy Power Marketing Inc.
DYPM	Dynegy Power Marketing Inc.
EBITDA	Earnings before interest, taxes, depreciation and amortization
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
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	Our power generation business

GEN-MW Our power generation business—Midwest segment GEN-NE Our power generation business—Northeast segment GEN-WE Our power generation business—West segment GHG Greenhouse gas HAPs Hazardous air pollutants, as defined by the Clean Air Act ICAP Installed capacity ICC Illinois Commerce Commission 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 LTIP Long-Term Incentive Plan MISO Midwest Independent Transmission System Operator MGGA Midwest Greenhouse Gas Accord MGGRP Midwestern Greenhouse Reduction Program1

Table of Contents



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

~~TABLE~~Table OFof ~~CONTENTS~~Contents

MMBtu	Millions of British thermal units
RFO	Request for offer
MW	Megawatts
MWh	Megawatt hour
NERC	North American Electric Reliability Corporation
NGL	Our natural gas liquids business segment
NOL	Net operating loss
NOx	Nitrogen oxide
NPDES	National Pollutant Discharge Elimination System
NSPS	New Source Performance Standard
NYISO	New York Independent System Operator
NYSDEC	New York State Department of Environmental Conservation
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 coal
PSD	Prevention of Significant Deterioration
PURPA	The Public Utility Regulatory Policies Act of 1978
QF	Qualifying Facility
RACT	Reasonably Available Control Technology
RCRA	The Resource Conservation and Recovery Act of 1976, as amended
RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must Run
RPM	Reliability Pricing Model
RTO	Regional Transmission Organization
SCEA	Sandy Creek Energy Associates, LP
SCH	Sandy Creek Holdings, LLC
SEC	U.S. Securities and Exchange Commission
SFAS	Statement of Financial Accounting Standards
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

~~TABLE~~Table OFof ~~CONTENTS~~Contents

Item 1. Business

THE COMPANY

We are a holding ~~companies~~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 ~~seventeen~~ten operating power plants in six states totaling approximately 118,~~800~~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.

~~Dynegy~~We ~~began~~are ~~operations in 1985. DHI is~~ a wholly -owned subsidiary of Dynegy~~. Dynegy~~, which began operations in 1984 and became incorporated in the State of Delaware in 2007. Our principal executive office is located at ~~1000~~601 ~~Louisiana~~Travis Street, Suite ~~5800~~ 1400, Houston, Texas 77002, and our telephone number at that office is (713) 507-6400.

We file annual, quarterly and current reports, ~~proxy statements (for Dynegy)~~ 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 ~~our~~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 ~~our~~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 ~~contractual~~ agreements orand ~~tariffs~~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, ~~and~~ 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.

Going Concern. Our accompanying consolidated financial statements have been prepared assuming that we will continue as a going concern, which contemplates realization of assets and the satisfaction of liabilities in the normal course of business for the twelve month period following the date of these consolidated financial statements. However, continued low power prices over the past two years have had a significant adverse impact on our business. Further, as our credit rating has declined, counterparty requirements for posting collateral in support of our risk management positions have become more stringent. Over the next twelve months, we expect that we will continue to need to utilize our Fifth Amended and Restated Credit Agreement, as amended (the “Credit Facility”), through the issuance of letters of credit and/or through the drawing of cash, or secure additional sources of capital to continue to meet our operating needs. The agreements governing our existing Credit Facility require us to meet specific financial covenants both as a matter of course and as a precondition to the incurrence of additional debt and to the making of restricted payments or asset sales, among other things. These specific financial covenants are required to be calculated on a quarterly basis and become more restrictive over the course of 2011. Using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant, as currently set forth in our Credit Facility, particularly in the third and fourth quarters of 2011. Furthermore, we expect that our available liquidity will continue to be reduced as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA, as defined in our Credit Facility. To continue as a going concern over the next twelve months, we must either (i) meet the financial covenants so that we can access our Credit Facility, or (ii) amend or replace our Credit Facility or otherwise secure additional capital.

TABLE OF CONTENTS

At December 31, 2010, we have the following obligations outstanding under the Credit Facility:

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

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

● $375 million in issued letters of credit.

A failure by us to comply with our financial covenants or to comply with the other restrictions in our financing agreements could result in reduced borrowing capacity or even a default, causing our debt obligations under such financing agreements (and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. If we are unable to cure any such default, or obtain a waiver or replacement financing, and those lenders accelerate the payment of such indebtedness, in the case that we are unable to repay those amounts, the holders of the indebtedness under our secured debt obligations would be entitled to foreclose on, and acquire control of substantially all of our assets, which would have a material adverse impact on our financial condition, results of operations and cash flows.

In light of our likely covenant non-compliance, we are attempting to amend or replace our existing Credit Facility. We expect the capacity of any amended or new credit facility to be less than the current capacity of $1.8 billion and to be at a higher cost. We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans.

Our ability to continue as a going concern is dependent on many factors, including, among other things, our ability to achieve the operating results necessary to comply with the covenants in our existing Credit Facility, amend or replace our existing Credit Facility, or achieve the operating results necessary to comply with the covenants in any amended or new credit facility. Such compliance will be dependent on our ability to successfully execute our commercial strategies, manage our collateral requirements, and continue to execute the company-wide cost reduction initiatives that are ongoing. Please read Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for further discussion. Also, for additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so please see Item 1A—Risk Factors.

TABLE OF CONTENTS

Our Power Generation Portfolio

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

Facility

Total Net Generating Capacity (MW)(1)

Primary Fuel Type

Dispatch Type

Location

Region

Baldwin

1,800

Coal

Baseload

Baldwin, IL

MISO

Kendall

1,200

Gas

Intermediate

Minooka, IL

PJM

Ontelaunee

580

Gas

Intermediate

Ontelaunee Township, PA

PJM

Havana (2)

441

Coal

Baseload

Havana, IL

MISO

Hennepin

293

Coal

Baseload

Hennepin, IL

MISO

Oglesby

Gas

Peaking

Oglesby, IL

MISO

Stallings

Gas

Peaking

Stallings, IL

MISO

Vermilion Units 1-2 (3)

164

Coal/Gas

Baseload

Oakwood, IL

MISO

Unit 3 (3)

Oil

Peaking

Oakwood, IL

MISO

Wood River (4)

446

Coal

Baseload

Alton, IL

MISO

Total Midwest

5,088

Moss Landing Units 1-2

1,020

Gas

Intermediate

Monterey County, CA

CAISO

Units 6-7

1,509

Gas

Peaking

Monterey County, CA

CAISO

Morro Bay (5)

650

Gas

Peaking

Morro Bay, CA

CAISO

South Bay (6)

—

Gas

Peaking

Chula Vista, CA

CAISO

Oakland

165

Oil

Peaking

Oakland, CA

CAISO

Black Mountain (7)

Gas

Baseload

Las Vegas, NV

WECC

Total West

3,387

Independence

1,064

Gas

Intermediate

Scriba, NY

NYISO

Roseton (8)

1,200

Gas/Oil

Peaking

Newburgh, NY

NYISO

Casco Bay

540

Gas

Intermediate

Veazie, ME

ISO-NE

Danskammer Units1-2

123

Gas/Oil

Peaking

Newburgh, NY

NYISO

Units 3-4 (8)

370

Coal/Gas

Baseload

Newburgh, NY

NYISO

Total Northeast

3,297

Total Fleet Capacity

11,772

Table of Contents



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 ~~Unit~~Units 63 and 4 generating capacity. Units 1-5 and 2, with a combined net generating capacity of ~~228~~352 MW, are currently in mothball status and out of operation.

(3) We Onindirectly ~~December~~own ~~28,~~a ~~2010,~~50 percent weinterest ~~announced~~in ~~plans~~this ~~to mothball the Vermilion power generation~~ facility. atTotal ~~approximately~~output ~~the~~capacity ~~end~~ of ~~the~~this ~~first~~facility ~~quarter~~is ~~2011~~85 MW.

(4) The ~~Represents~~Roseton ~~Units~~facility 4 and ~~5 generating capacity.~~ Units 1-3, ~~with~~and a4 ~~combined~~of ~~net~~the ~~generating~~Danskammer ~~capacity~~facility ofwere ~~119~~leased ~~MW,~~by ~~are~~the ~~currently~~Company. inPlease ~~mothball~~read ~~status~~Note ~~and~~3—Chapter ~~out~~11 ofCases ~~operation~~for further discussion.

~~(5)~~On ~~Represents~~June ~~Units~~5, 32012, ~~and~~the 4effective ~~generating~~date ~~capacity.~~of ~~Units~~the 1Settlement ~~and 2~~Agreement, ~~with~~we areacquired ~~combined~~the ~~net~~Coal ~~generating~~segment ~~capacity~~constituting of3,132 ~~352~~ MW,. Please ~~are~~read ~~currently~~Note in3—Chapter ~~mothball~~11 ~~status~~Cases ~~and~~for ~~out~~further ~~of operation~~discussion.

~~(6)~~Business ~~The South Bay facility was retired on December 31, 2010 and is in the process of being decommissioned.~~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 (7as 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 ~~own~~manage aour 50generation ~~percent~~assets ~~interest~~by infuel ~~this~~type ~~facility~~with three primary reportable segments: (i) the Coal segment ("Coal"), (ii) the Gas segment ("Gas") and (iii) the Dynegy Northeast Segment ("DNE"). ~~Total~~As ~~output~~further ~~capacity~~described ofbelow, ~~this~~we ~~facility~~transferred isthe 85Coal MWsegment 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.

~~(8)~~There Weare ~~lease~~four ~~the~~primary ~~Roseton~~elements ~~facility and Units 3 and 4 of the Danskammer facility pursuant~~ to aour leveraged lease arrangement that is further described in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Disclosure of Contractual Obligations and Contingent Financial Commitments—Off-Balance Sheet Arrangements—DNE Leveraged Lease.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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~~Our~~located ~~Business~~in ~~Focus~~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 ~~business~~remaining ~~focus~~assets ~~seeks~~(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 ~~create~~Dynegy. Please ~~value~~read ~~through:~~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 ~~diverse~~higher ~~portfolio~~level of ~~power~~formalities, ~~generation~~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 aTransfer. On ~~diverse~~September 1, 2011, Dynegy and ~~flexible~~Dynegy ~~commercial~~Gas ~~strategy~~Investments, LLC ~~that~~("DGIN"), ~~includes~~a ~~buying~~wholly-owned ~~and~~subsidiary, entered ~~selling~~into ~~electric~~a ~~energy~~Membership Interest Purchase Agreement whereby DGIN transferred 100 percent of its outstanding membership interests of Dynegy Coal Holdco, LLC ~~capacity~~("Coal Holdco") which, through DMG, owns the majority of our and ~~ancillary~~our ~~services~~affiliates' ~~either~~portfolio ~~short~~of primarily coal-fired generation facilities, ~~medium-~~to orDynegy ~~long-term;~~(the ~~sales~~"DMG ~~and~~Transfer"). ~~purchases~~In ofexchange ~~emissions~~for ~~credits~~Coal Holdco, ~~fuel~~Dynegy ~~supplies~~agreed to make certain specified payments (aggregating approximately $2.1 billion through October 15, 2026) to DGIN over time which coincide in timing and ~~transportation~~amount ~~services~~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 ~~capture~~"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 ~~extrinsic~~$1.25 billion ~~value~~that ~~inherent~~matures in ~~our~~2027 ~~portfolio~~(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 ~~extent~~reduction ~~permitted~~of ~~given~~Dynegy's ~~liquidity~~obligations ~~constraints~~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 ~~safe, low cost plant operations, with a focus on having our plants available and “in the market” when it is economical to do so; and~~Cases

●On ~~maintaining~~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 ~~capital~~voluntary ~~structure~~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 ~~support~~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 ~~commercial~~continue ~~operations~~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”).

Maintain a Diverse Portfolio to Capitalize on Market Opportunities and Mitigate Risk. We operate a portfolio of generation assets that is diversified in terms of dispatch profile, fuel type and geography. Baseload generation is generally low-cost and economically attractive to dispatch around the clock throughout the year. A baseload facility is usually expected to run in excess of 70 percent of the hours in a given year. Intermediate generation may not be as efficient and/or economical as baseload generation, but is typically intended to be dispatched during higher load times such as during daylight hours and sometimes on weekends. Peaking generation is the least efficient and highest cost generation, and is generally dispatched to serve load during the highest load times such as hot summer and cold winter days.

Power prices have significantly declined since the summer of 2008. This decline reflects a similar decline in natural gas prices, which is exacerbated by shale gas proliferation, and the impact of general economic conditions, including a recessionary environment that has negatively impacted the demand for electricity. Despite these effects, we continue to believe that, over the longer term, power demand and power pricing should increase, as more stringent environmental regulations force the retirement of older, less efficient power generation units that have not invested in environmental upgrades. As a result, we believe our coal-fired, baseload fleet that have received environmental upgrades, should benefit from the impact of higher power prices in the Midwest, allowing us to capture higher margins over time. We anticipate that our combined cycle units also should benefit from increased run-times as heat rates expand, with improved margins and cash flows as demand increases in our key markets.

In addition, we believe that our portfolio of assets helps to mitigate certain risks inherent in our business. For example, weather patterns, regulatory regimes and commodity prices often differ by region and state. Geographic diversity lessens the impact of an individual risk in any one region, and we are better positioned to improve the level and consistency of our earnings and cash flows.

Employ a Flexible Commercial Strategy to Maintain Long-Term Market Upside Potential While Protecting Against Downside Risks. We expect to see tightening reserve margins through time in the regions in which our assets are located. As these reserve margins tighten, in the longer term we expect to see our generating assets increase in value through improved cash flows and earnings as capacity utilization and power prices improve. Given current market pricing and conditions, we see limited long-term attractive commercial arrangements.

We plan to continue to volumetrically hedge the expected output from our facilities over a rolling 1-3 year time frame with the goal of achieving an efficient balance of risk and reward; however, liquidity constraints may limit our ability to post the collateral necessary to support this hedging strategy. Keeping the portfolio completely open and selling in the day-ahead market, for instance, would force us to take weather and general economic-related risks, as well as price risk of correlated commodities. These risks can cause significant swings in financial performance in any one year and are not consistent with our efforts to improve predictability of short- and medium-term earnings and cash flows.

Our commercial strategy seeks to balance the goal of protecting cash flow in the short- and medium-term with maintaining the ability to capture value longer term as markets tighten. In order to maximize the value of our assets, we seek to capture intrinsic and extrinsic value. Opportunities to capture extrinsic value – that is, value beyond that ascribed to our generating capacity based solely on a current price strip – arise from time to time in the form of price volatility, differences in counterparties’ views of forward prices and other market conditions. In order to execute our strategy, we utilize a wide range of products and contracts such as power purchase agreements, fuel supply contracts, capacity auctions, bilateral capacity contracts, power and natural gas swap agreements, power and natural gas options and other financial instruments.

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WeCoal ~~also,~~Holdco toand ~~the~~Dynegy ~~extent~~GasCo ~~we have sufficient liquidity~~Holdings, ~~seek~~ toLLC ~~balance predictability of earnings~~ and ~~cash~~their ~~flow~~indirect, ~~with~~wholly-owned ~~achieving~~subsidiaries ~~the~~(including ~~highest~~DMG ~~level of earnings~~ and ~~cash~~DPC) ~~flow. Short-term~~are ~~market~~not ~~volatility~~included ~~can~~in ~~negatively~~the ~~impact~~Chapter ~~our~~11 ~~profitability;~~Cases. weThe ~~will~~normal ~~seek~~ day-to-day ~~reduce~~operations ~~those~~of ~~negative impacts through~~ the ~~disciplined use of short~~coal-fired ~~and~~power ~~medium-term~~generation ~~forward~~facilities ~~economic~~held ~~hedging~~by ~~instruments. Through~~DMG ~~the use of forward economic hedging instruments, including various products~~ and ~~contracts such as options and swaps, we seek to capture~~ the ~~extrinsic value inherent in our portfolio. Due to a number of variables – including changes in correlations between~~ gas-fired ~~and~~ power, ~~time~~generation ~~decay,~~facilities ~~changes~~held inby ~~commodity~~DPC ~~prices,~~continue ~~volatility~~without ~~and~~interruption. ~~liquidity~~The –commencement weof ~~intend~~the toChapter 11 ~~actively~~Cases ~~and~~did ~~continuously~~not ~~balance~~constitute ~~our~~an ~~asset~~event ~~and~~of ~~hedge~~default ~~portfolios. However,~~under ~~our~~either ~~ability~~the toDMG ~~execute~~Credit ~~our~~Agreement ~~strategy~~or ~~may~~the beDPC ~~limited~~Credit ~~as a result of liquidity constraints~~Agreement.

InOn ~~carrying~~August ~~out~~27, ~~this~~2012, ~~commercial~~the ~~strategy,~~results weof ~~either~~the ~~prepay~~vote ~~obligations~~on orthe ~~post~~Plan ~~significant~~were ~~amounts~~filed ofwith ~~collateral. Various~~the ~~commodity~~Bankruptcy ~~trading~~Court, ~~counterparties~~with ~~make~~creditors ~~collateral~~holding ~~demands~~over ~~that~~$3.5 ~~reflect~~billion ~~our~~of ~~non-investment~~claims, ~~grade~~or ~~credit~~more ~~ratings~~than ~~and~~99% of the ~~counterparties’~~value ~~views~~ of ~~our~~the ~~creditworthiness~~claims that voted, asapproving ~~well~~the asPlan ~~changes~~(this inreflects ~~commodity~~approximately ~~prices. We~~87% ~~use~~of athe ~~portion~~number of ~~our~~creditors ~~capital~~who ~~resources~~voted). Further, inDynegy ~~the~~announced ~~form~~that ofthe ~~cash,~~Consenting ~~short-term~~Senior ~~investments~~Noteholders, ~~lien~~the ~~capacity,~~Lease Trustee and ~~letters~~the ofCreditors' ~~credit,~~Committee selected the initial directors to ~~satisfy~~be ~~these~~appointed ~~counterparty~~to ~~collateral~~Dynegy's ~~demands~~Board. ~~Our~~ At ~~commodity~~a ~~agreements~~hearing ~~are~~on ~~tied~~September to5, ~~market~~2012, ~~pricing~~the Bankruptcy Court found that DH and ~~may~~Dynegy ~~require~~had usmet toall ~~post~~the ~~additional~~Plan ~~collateral~~confirmation requirements under ~~certain~~the ~~circumstances~~Bankruptcy Code. If Accordingly, ~~conditions~~on ~~change~~September ~~such~~10, ~~that~~2012, ~~counterparties~~the ~~demand~~Bankruptcy ~~additional~~Court ~~collateral, additional~~entered ~~strains~~its order confirming the Plan (the "Confirmation Order"). For detailed information on ~~our~~the ~~liquidity~~Chapter ~~could~~11 ~~result~~Cases including the plan of reorganization, Settlement Agreement and Plan Support Agreement and the related accounting impacts please read Note 3—Chapter 11 Cases.

AsMARKET further discussed at Note 1—Organization and Operations—Going Concern, using the latest available forward commodity price curves and considering our current hedging contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant, as set forth in our Credit Facility, particularly in the third and fourth quarters of 2011. In light of our probable covenant non-compliance, we are attempting to amend or replace our existing Credit Facility. We expect the capacity of any amended or new credit facility to be less than the current capacity of $1.8 billion. Depending on the ultimate capacity available, our ability to use forward economic hedging instruments could be limited due to the collateral requirements the use of such instruments entails. Reduced hedging activity would expose us to future increases and decreases in commodity prices and limit our ability to capture the extrinsic value associated with our portfolio of assets.DISCUSSION

WeOur ~~set~~business ~~specific~~operations ~~limits~~are ~~for~~focused ~~“gross~~primarily ~~margin~~on atthe ~~risk”~~wholesale ~~for~~power ~~our~~generation ~~assets~~sector ~~and~~of ~~economic~~the ~~hedges~~energy industry. ~~These~~ ~~limits~~During ~~require~~2011, ~~power~~we ~~hedging~~reorganized ~~above~~and manage ~~minimum~~and ~~levels,~~report ~~while~~the ~~requiring~~results ~~that~~of ~~corresponding~~our ~~fuel~~power ~~supplies~~generation ~~are~~business ~~appropriately~~based ~~hedged~~on asfuel wetype ~~progress~~with ~~through~~three ~~time. We~~segments ~~also~~on ~~specifically~~a ~~attempt~~consolidated ~~to manage~~ basis: ~~risk~~(i) Coal, to(ii) Gas ~~more~~and ~~liquid~~(iii) DNE. As ~~market~~further ~~hubs~~described ~~that~~below, ~~are~~we ~~not~~transferred the ~~natural~~Coal ~~sales~~segment ~~hub~~to ~~for~~our aparent, ~~facility. Any~~Dynegy, ~~reduction~~effective inSeptember ~~our~~1, ~~hedging~~2011 ~~activity~~and tosubsequently ~~reduce~~reacquired ~~liquidity~~the ~~needs~~Coal ~~will~~segment ~~result~~from inDynegy, aeffective ~~corresponding~~June ~~inability~~5, to2012. Please ~~limit~~read ~~our~~Note ~~gross~~3—Chapter ~~margin~~11 atCases ~~risk~~for further discussion.

Operate Our Assets Safely and Cost-Efficiently to Maximize Revenue Opportunities and Operating Margins. We have a history of strong plant operations and are committed to operating our facilities in a safe, reliable, low-cost and environmentally compliant manner. By maintaining and operating our assets in an effort to ensure plant availability, high dispatch and capacity factors and an increased focus on operating and capital costs, we believe we are positioned to capture opportunities in the marketplace to benefit our operating margins.

Our power generation facilities are managed to require a relatively predictable level of maintenance capital expenditures without compromising operational integrity. Our capital expenditures are applied to the maintenance of our facilities to ensure their continued reliability and to investment in new equipment for either environmental compliance or increasing profitability. We seek to operate and maintain our generation fleet efficiently and safely, with an eye toward increased reliability and environmental stewardship. This increased reliability impacts our results to the extent that our generation units are available during times that it is economically sound to run. For units that are subject to contracts for capacity, our ability to secure availability payments from customers is dependent on plant availability.

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Maintain a Capital Structure that is Integrated with our Operating Strategy. We believe that the power industry is a commodity cyclical business with significant commodity price volatility and considerable capital investment requirements. Thus, operating in this market environment requires a capital structure that can withstand fuel and power price volatility as well as a commercial strategy that seeks to capture the value associated with both medium- and long-term price trends. We seek to employ a suitable capital structure, including debt amounts and maturities, debt covenants and overall liquidity, that is appropriate for our commercial strategy and the commodity cyclical market in which we operate. As discussed in Note 1—Organization and Operations—Going Concern, we are attempting to amend or replace our existing Credit Facility in order to continue to meet our operating needs over the next twelve months and/or seek additional sources of liquidity, which could impact our capital structure.

SEGMENT DISCUSSION

Our business operations are focused primarily on the wholesale power generation sector of the energy industry. We report the results of our power generation business, based on geographical location and how we have allocated our resources, as three separate segments in our consolidated financial statements: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Our consolidated financial results also reflect corporate-level expenses such as general and administrative and interest. Please read Note 25—Segment Information for further information regarding the financial results of our business segments.

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 ~~pricing~~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.

9Market-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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~~Market-Based~~Table ~~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.Contents

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 next triennial market power review for our MISO facilities will be filed with FERC in June 2012. The next triennial market power review for our GEN-NE and PJM facilities will be filed at FERC in June 2011. The triennial market power reviews for our GEN-WE facilities was filed in June 2010 and accepted by FERC in December 2010 with a finding that the GEN-WE facilities satisfied FERC’s requirement that such facilities do not have horizontal or vertical market power.

~~Power~~The ~~Generation—Midwest~~Dodd-Frank ~~Segment~~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.

~~GEN-MW~~Coal is comprised of eight facilities in Illinois and one in Pennsylvania with a total generating capacity of 5,088 MW. As of December 31, 2010, GEN-MW operated entirely within either the MISO or the PJM.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 ~~Michigan and~~ portions of ~~Ohio~~Michigan, Kentucky, Indiana, Illinois, Nebraska, Kansas, Missouri, Iowa, Minnesota, North Dakota, Montana and Manitoba, Canada. As of December 31, 2010, we owned seven power generating facilities that sell into the MISO market and are located in Illinois, with an aggregate net generating capacity of 3,308 MW within MISO. On December 28, 2010, we announced plans to mothball the 176 MW Vermilion power generation facility at the end of the first quarter 2011.

The MISO energy market is designed to ensure that ~~every~~all ~~electric~~market ~~industry~~participants ~~participant~~have ~~has~~ open-access to the ~~grid~~transmission ~~and~~system ~~that~~on noa ~~entity~~non-discriminatory ~~has~~basis. ~~the~~MISO, ~~ability~~as toan ~~deny~~independent ~~access~~RTO, tomaintains afunctional ~~competitor. MISO~~control ~~also~~over ~~manages~~ the use of the transmission ~~lines~~system to ~~make~~ensure ~~sure~~transmission ~~that~~circuits ~~they~~ do not exceed their secure operating limits and become overloaded. MISO operates ~~physical~~day-ahead and ~~financial~~real-time energy markets using a ~~system known as~~ LMP, system which calculates a price for every generator and load point within MISO. This ~~system~~market is ~~“price-~~transparent”, allowing generators and load serving entities to see real-time price effects of transmission constraints and the impacts of ~~generation~~congestion ~~and load changes to prices~~ at each pricing point. MISO ~~operates~~administers ~~day-ahead~~a ~~and~~centralized ~~real-time~~capacity ~~markets~~market ~~into~~that ~~which~~relies ~~generators~~on ~~can~~bilateral ~~offer~~transactions tofor ~~provide~~all ~~energy. MISO~~sales ~~does~~and ~~not~~purchases ~~administer~~beyond one month forward and includes a ~~centralized~~monthly voluntary clearing auction that allows buyers to clear residual capacity ~~market~~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.

~~PJM. The~~MISO ~~PJM~~implemented ~~market~~the ~~includes~~Ancillary ~~all~~Services orMarket ~~parts~~(Regulation ofand ~~Delaware,~~Operating ~~Illinois,~~Reserves) ~~Indiana,~~on ~~Kentucky~~January 6, ~~Maryland,~~2009 ~~Michigan,~~and ~~New~~implemented ~~Jersey,~~an ~~North~~enforceable ~~Carolina,~~Planning ~~Ohio,~~Reserve ~~Pennsylvania,~~Margin ~~Tennessee,~~for ~~Virginia,~~each ~~West~~planning ~~Virginia~~year ~~and~~effective ~~the~~June 1, ~~District~~2009. ofA ~~Columbia. As~~feature of ~~December~~the ~~31,~~Ancillary ~~2010,~~Services weMarket ~~owned~~is ~~two~~the ~~generating~~addition ~~facilities~~of scarcity pricing that, ~~sell~~during ~~into~~supply ~~the~~shortages, ~~PJM~~can ~~market~~raise ~~and~~the ~~are~~combined ~~located~~price inof ~~Illinois~~energy and ~~Pennsylvania~~ancillary ~~with~~services ansignificantly ~~aggregate~~higher ~~net~~than ~~generating~~the ~~capacity~~previous cap of $1,~~780 MW~~000/MWh.

10An independent market monitor is responsible for ensuring that MISO markets are operating competitively and without exercise of market power.

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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 2013-2014, which ends May 31, 2014, 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) existing $1,000/MWh energy market price caps that are in place.

Contracted Capacity and Energy

~~MISO. Power~~We ~~prices~~commercialize ~~in MISO are a significant driver of~~ our ~~overall~~Coal ~~financial~~segment ~~performance~~assets ~~due~~through ~~to the fact that~~ a ~~significant~~combination ~~portion~~ of ~~our~~physical ~~total~~participation ~~power generating capacity is located~~ in the MISO ~~and~~markets is(as ~~attributable~~described toabove), ~~coal-fired baseload units. We commercialize these assets through a combination of~~ bilateral physical and financial power sales, and fuel and capacity contracts.

~~PJM. Our~~Reserve 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. In January 2010, we executed an agreement to terminate a 280 MW tolling agreement for our Kendall facility. This agreement was replaced by two smaller tolling agreements which total 135 MW into 2012 and 85 MW into 2017.Margins

~~Regulatory~~MISO's ~~Considerations~~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.

~~MISO. Actual~~Gas reserve margins are substantially above MISO’s current required reserve margin of 15 percent. The reserve margin based on available capacity was 29 percent during the 2010 summer season as compared to 44 percent during the 2009 summer season.Segment

~~PJM. Actual~~Our ~~reserve~~Gas ~~margins~~segment ~~are~~is ~~somewhat~~comprised ~~above~~of ~~PJM’s~~seven ~~current~~operating ~~required~~natural ~~installed~~gas-fired ~~reserve~~power ~~margin~~generation offacilities 15located ~~percent. The~~in ~~reserve~~California ~~margin~~(2), ~~based~~Nevada on(1), ~~deliverable~~Illinois ~~capacity~~(1), ~~was~~Pennsylvania 26(1), ~~percent~~New ~~for~~York ~~Planning~~(1), ~~Year~~and ~~2010/11~~Maine as(1), ~~compared~~and toone 20fuel-oil ~~percent~~fired ~~for~~power ~~Planning~~generation ~~Year~~facility ~~2009/10~~located in California, totaling 6,771 MW of electric generating capacity. ~~PJM’s~~ ~~required~~Our ~~installed~~309 ~~reserve~~MW ~~margin~~South isBay 16facility ~~percent~~was ~~for~~permanently ~~Planning~~retired ~~Year~~in ~~2010/11.~~

~~Power Generation—West Segment~~9

~~GEN-WE~~Table ~~is comprised~~ of three operating natural gas-fired power generation facilities located in California (2) and Nevada (1) and one fuel oil-fired power generation facility located in California, totaling 3,387 MW of electric generating capacity. Our 309 MW South Bay facility is currently out of operation and is in the process of being decommissioned.Contents

112010 and is currently in the process of being decommissioned.

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RTO/ISO Discussion

~~CAISO~~PJM. ~~CAISO~~ The ~~covers~~PJM ~~approximately~~market 90includes ~~percent~~all or parts of ~~the~~Delaware, ~~State~~Illinois, ofIndiana, ~~California. At~~Kentucky, ~~December~~Maryland, 31Michigan, ~~2010~~New Jersey, weNorth ~~owned~~Carolina, ~~three~~Ohio, ~~operating~~Pennsylvania, ~~generation~~Tennessee, Virginia, West Virginia and the District of Columbia. Our Kendall and Ontelaunee facilities, located in ~~California~~Illinois ~~within~~and ~~CAISO. The~~Pennsylvania, ~~Oakland~~respectively, ~~facility~~operate isin ~~designated~~PJM aswith an ~~RMR~~aggregate ~~unit~~net bygenerating ~~the~~capacity ~~CAISO~~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

~~CAISO~~PJM. In Our ~~CAISO,~~generation ~~where our~~ assets ~~include~~in ~~intermediate~~PJM ~~dispatch~~are ~~and~~natural ~~peaking~~gas-fired, ~~facilities~~combined-cycle, weintermediate-dispatch ~~seek~~facilities. toWe ~~mitigate~~commercialize ~~spark~~these ~~spread~~assets ~~variability~~ through ~~RMR,~~a ~~tolling~~combination ~~arrangements~~of ~~and physical and financial~~ bilateral power, fuel and ~~fuel~~capacity contracts. ~~All~~ ofWe ~~the~~commercialize ~~capacity of~~ our ~~Moss~~capacity ~~Landing~~through ~~Units~~either 6the ~~and~~RPM 7auction ~~and~~or ~~Morro~~on ~~Bay~~a ~~facility~~bilateral ~~are contracted under tolling arrangements through 2013~~basis. Our ~~Oakland~~Kendall facility ~~operates~~has ~~under~~two ~~RMR~~tolling ~~contracts. The~~agreements, ~~RMR~~one ~~contract~~for at135 ~~our~~MW ~~South~~that ~~Bay~~expires ~~facility~~in ~~expired~~March on2012 ~~December 31, 2010,~~ and weone ~~expect~~for ~~the~~85 ~~facility~~MW tothat beexpires ~~demolished~~in 2017.

~~Regulatory~~NYISO. At ~~Considerations~~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. ~~The~~ ~~actual~~As of the latest Summer Assessment for 2011, reserve margin ~~generally~~was ~~moves~~approximately ~~within,~~20.8 percent. orUnlike ~~close~~other ~~to,~~centrally ~~this~~cleared ~~range~~capacity markets, ~~but~~the ~~seasonal~~CAISO ~~and~~Resource ~~regional~~Adequacy ~~fluctuations~~market ~~exist~~is a bi-laterally traded market.

~~Equity~~DNE ~~Investment~~Segment

~~Black~~Our ~~Mountain. We~~DNE ~~have~~segment ais 50comprised ~~percent~~of ~~indirect~~the ~~ownership~~Roseton ~~interest~~and inDanskammer ~~the~~facilities ~~Black~~located ~~Mountain~~in ~~facility~~Newburgh, ~~which~~New isYork, with a ~~PURPA~~total QFcapacity ~~located~~of ~~near~~1,693 ~~Las~~MW. ~~Vegas,~~A ~~Nevada~~total of 1,570 inMW of generation capacity relates to leased units at the ~~WECC~~two facilities. ~~Capacity~~ ~~and~~In ~~energy~~connection ~~from~~with ~~this~~the ~~facility~~DH ~~are~~Chapter 11 ~~sold~~Cases, tothe ~~Nevada~~DH ~~Power~~Debtor ~~Company~~Entities ~~under~~rejected athese long-term ~~PURPA~~leases. QFThe ~~contract~~applicable ~~that~~DH ~~runs~~Debtor Entities have operated and plan to ~~2023~~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.

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

GEN-NE is comprised of four facilities located in New York (3) and Maine (1), with a total capacity of 3,297 MW. We own and operate the Independence, Casco Bay and Danskammer Units 1 and 2 power generating facilities, and we operate the Roseton and Danskammer Units 3 and 4 facilities under long-term lease arrangements. Our Roseton and Danskammer facility sites are adjacent and share common resources such as fuel handling, a docking terminal, personnel and systems.

RTO/ISO Discussion

~~The~~NYISO. For ~~market~~a infull ~~which~~discussion ~~GEN-NE~~of ~~resides~~the isNYISO ~~characterized~~market, bysee ~~two interconnected and actively traded competitive markets:~~ the "NYISO" ~~(an~~section ~~ISO)~~under ~~and the~~ "Gas—RTO/ISO~~-NE~~ ~~(an~~Discussion" ~~RTO)~~above. In ~~the~~Our ~~GEN-NE~~DNE ~~markets,~~facilities ~~load-serving~~operate ~~entities~~in ~~generally~~the ~~lack~~Rest ~~their~~of ~~own~~State ~~generation~~market. ~~capacity~~Due ~~and~~to ~~procure~~transmission ~~their~~constraints, energy ~~supplies~~prices ~~from~~vary ~~merchant~~across ~~generation~~New ~~owners~~York ~~through~~and ~~the ISO/RTO markets. Commodity prices~~ are ~~typically~~generally ~~more~~higher ~~volatile~~ in the ~~Northeast~~Southeastern ~~(on~~part anof ~~as-delivered~~New ~~basis)~~York, ~~than~~where inour ~~other~~Roseton ~~regions~~and ~~due~~Danskammer tofacilities ~~the~~are ~~distance~~located, and ~~occasional~~in ~~physical~~New ~~constraints~~York ~~that~~City ~~impact~~and ~~the~~Long ~~delivery of fuel into the region~~Island.

Although both RTOs/ISOs and their respective energy markets are functionally, administratively and operationally independent, they follow, to a certain extent, similar market designs. Both the NYISO and the ISO-NE dispatch power plants to meet system energy and reliability needs and settle physical power deliveries at LMPs as discussed above. The energy markets in both the NYISO and ISO-NE also have defined, but different, mitigation protocols for bidding.

In addition to energy delivery, the NYISO and ISO-NE administer markets for installed capacity, ancillary services and FTRs.

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NYISO. The NYISO market includes virtually the entire state of New York. At December 31, 2010, we operated three facilities within NYISO with an aggregate net generating capacity of 2,757 MW.

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 in the general sector in which it is needed most when that new capacity is needed. 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 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. Our Independence facility is located in the Northwest 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. The ISO-NE implemented an FCM in June 2010 where capacity prices are determined through auctions. As of December 31, 2010, we owned and operated one power generating facility (Casco Bay) within the ISO-NE, with an aggregate net generating capacity of 540 MW.

Contracted Capacity and Energy

~~NYISO.~~ 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

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 the LMP at Pleasant Valley. Additionally, we supply steam and up to 44 MW of electric energy from our Independence facility to a third party at a fixed price.11

~~For~~Table ~~the uncommitted portion~~ of our NYISO fleet, 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 our remaining capacity into the market.Contents

~~ISO-NE. Four~~products, ~~forward~~we ~~capacity~~are ~~auctions~~able ~~have been held~~ to ~~date~~sell ~~with~~substantially ~~capacity~~all ~~clearing~~of ~~prices ranging from $4.50 kW/month for~~ the ~~2010/2011~~assets' ~~market period to $2.95 kW/month for the 2012/2013 market period. These~~ capacity ~~clearing~~into ~~prices represent~~ the ~~floor price and the actual rate paid to~~ market ~~participants that were affected by pro-rationing due to oversupply conditions~~.

Regulatory Considerations

NYISO. A reserve margin of 15.5 percent has been proposed for the New York Control Area for the period beginning May 1, 2011 and ending April 30, 2012, down from the current requirement of 18 percent. The actual amount of installed capacity is somewhat above NYISO’s current required margin.

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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 ~~included~~allocated into ~~Other~~each inreportable ~~our~~ segment ~~reporting. Corporate general and administrative expenses~~, ~~income~~in ~~taxes~~accordance ~~and~~with ~~interest~~the ~~expenses~~relevant ~~are~~Service ~~also~~Agreements. ~~included,~~Please asread ~~are~~Note ~~corporate-related~~21—Related ~~other~~Party ~~income~~Transactions—Service ~~and~~Agreements ~~expense items. Results~~ for ~~our~~further ~~legacy~~discussion. ~~CRM~~Corporate ~~operations,~~interest ~~which~~expense ~~primarily~~and ~~consist~~income oftaxes aare ~~minimal~~included ~~number~~in ofOther, ~~natural~~as ~~gas~~are ~~trading~~corporate-related ~~positions,~~other ~~are~~income ~~also~~and ~~included~~expense ~~in Other~~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, ~~changed~~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 $~~225~~ 180 million in ~~2010~~2011 compared to approximately $~~320~~ 225 million in ~~2009~~2010 and approximately $~~245~~ 320 million in ~~2008~~2009. The ~~2010~~2011 expenditures ~~include~~included approximately $~~200~~ 150 million for projects related to our ~~Midwest~~ Consent Decree (which is defined and discussed below) compared to ~~$260~~approximately $200 million for ~~Midwest~~ Consent Decree projects in ~~2009~~2010. We estimate that total ~~environmental~~ expenditures in ~~2011~~2012 related to our Coal segment will be approximately $~~180~~100 million, including approximately $~~150~~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 $30 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 2223—Commitments and Contingencies for further discussion of this matter.

~~Climate~~The ~~Change~~Clean Air Act

~~For~~The ~~the~~CAA ~~last~~and ~~several~~comparable ~~years,~~state ~~there~~laws ~~has~~and ~~been~~regulations arelating ~~robust~~to ~~public~~air ~~debate~~emissions ~~about~~impose ~~climate~~responsibilities ~~change~~on owners and ~~the~~operators ~~potential~~of ~~for~~sources ~~regulations~~of ~~requiring~~air ~~lower~~ emissions, ofincluding ~~GHG,~~requirements ~~primarily~~to ~~CO2~~obtain construction and ~~methane~~operating permits as well as compliance certifications and reporting obligations. We ~~believe~~The CAA requires that ~~the~~fossil-fueled ~~focus~~electric ofgenerating ~~any~~plants ~~federal~~have ~~program~~sufficient ~~attempting~~emission allowances to ~~address~~cover ~~climate~~actual ~~change~~SO2 ~~should~~emissions ~~include~~and ~~three~~in ~~critical~~some regions NOX emissions, ~~interrelated~~and ~~elements:~~that ~~(i)~~they ~~the~~meet ~~environment~~certain pollutant emission standards as well. Our power generation facilities, ~~(ii)~~some ~~the~~of ~~economy~~which ~~and~~have ~~(iii)~~changed ~~energy~~their ~~security~~operations to accommodate new control equipment or changes in fuel mix, are currently in compliance with these requirements.

WeIn ~~cannot~~order ~~confidently~~to ~~predict~~ensure ~~the~~continued ~~final~~compliance ~~outcome~~with of the ~~current~~CAA ~~debate~~and onrelated ~~climate~~rules ~~change~~and ~~nor~~regulations, ~~can~~including ozone-related requirements, we ~~predict~~have ~~with~~installed, ~~confidence~~are in the ~~ultimate~~process ~~requirements~~ of ~~proposed~~installing, or ~~anticipated~~have ~~federal~~plans ~~and~~to ~~state~~install ~~legislation~~additional ~~and~~emission ~~regulations~~reduction ~~intended~~technology toat ~~address~~our ~~climate~~Coal ~~change~~segment facilities. ~~These~~ ~~activities,~~Two ~~and~~coal-fired ~~the~~units ~~highly~~at ~~politicized~~our ~~nature~~Baldwin ~~of climate~~facility ~~change,~~and ~~suggest~~the acoal-fired ~~trend~~unit ~~toward~~at ~~increased~~our ~~regulation~~Havana offacility ~~GHG~~have ~~that~~installed ~~could~~and ~~result~~are inoperating adry ~~material~~flue ~~adverse~~gas ~~effect~~desulphurization onsystems ~~our~~for ~~financial~~the ~~condition,~~control ~~results~~ of ~~operations~~SO2 emissions, and ~~cash~~electrostatic ~~flows. Existing~~precipitators and ~~anticipated~~baghouses ~~federal~~for ~~and~~the ~~state~~control ~~regulations~~of ~~intended~~particulate toemissions. ~~address~~A ~~climate~~third ~~change~~unit ~~may~~at ~~significantly~~Baldwin ~~increase~~(Unit ~~the~~2) currently ~~cost~~utilizes ofan ~~providing~~electrostatic ~~electric~~precipitator ~~power,~~and ~~resulting~~is inscheduled ~~far-reaching~~to ~~and~~complete ~~significant~~installation ~~impacts~~of ona usdry flue gas desulphurization system and ~~others~~baghouse inby the ~~power~~end ~~generation~~of ~~industry~~2012. ~~over~~Our ~~time. It~~coal-fired isunits ~~possible~~at ~~that~~the ~~federal~~Hennepin ~~and~~facility ~~state~~have ~~actions~~electrostatic ~~intended~~precipitators toand ~~address~~baghouses ~~climate~~for ~~change~~the ~~could~~control ~~result~~of inparticulate ~~costs~~matter. ~~assigned~~The tobaghouses ~~GHG~~at ~~emissions~~our ~~that~~Coal wesegment ~~would~~facilities ~~not~~also becontrol ~~able to~~hazardous ~~fully~~air ~~recover~~pollutants ~~through~~in ~~market~~particulate ~~pricing~~form, orsuch ~~otherwise~~as most metals. If ~~capital~~Activated ~~and/or~~carbon ~~operating~~injection ~~costs~~or ~~related~~mercury tooxidation ~~compliance~~systems ~~with~~for ~~regulations~~the ~~intended~~control toof ~~address~~mercury ~~climate~~emissions ~~change~~have ~~become~~been ~~great~~installed ~~enough~~and toare ~~render~~operating ~~the~~on ~~operations~~approximately 97 percent of ~~certain~~our ~~plants~~Coal ~~uneconomical~~segment's coal-fired capacity, and we ~~could,~~will atinstall controls on our ~~option~~final ~~and~~unit ~~subject~~(Wood River Unit 4) by 2013. SCR technology to ~~any~~control ~~applicable~~NOX ~~financing~~emissions ~~agreements~~has orbeen ~~other~~installed ~~obligations,~~and ~~reduce~~has ~~operations~~been oroperating ~~cease~~at toHavana ~~operate~~for ~~such~~several ~~plants~~years; ~~and~~the ~~forego~~remaining ~~such~~Coal ~~capital~~segment units use low-NOX burners and~~/or~~ ~~operating~~overfire ~~costs~~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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~~Power~~sources ~~generating~~in ~~facilities~~the ~~are~~larger aarea. The ~~major~~NYSDEC ~~source~~recommended ofthat ~~GHG~~all ~~emissions~~areas – in ~~2010,~~New ~~our~~York ~~facilities~~State inbe ~~GEN~~designated attainment or unclassifiable with the new 1-MWhour SO2 NAAQS; however, ~~GEN-WE~~in November 2011, the Sierra Club recommended to the NYSDEC and ~~GEN-NE~~the ~~emitted~~EPA ~~approximately~~that, ~~23.5~~based ~~million~~on emissions modeling it had performed, ~~1.5~~certain ~~million~~areas ~~and~~in 4New York State be designated nonattainment due to SO2 emissions from the Danskammer generating station.8 ~~million~~While ~~tons~~the nature and scope of ~~CO2e~~potential future requirements concerning the 1-hour SO2 NAAQS cannot be predicted with confidence at this time, ~~respectively. The~~a ~~amounts~~requirement offor ~~CO2e~~additional ~~emitted~~SO2 ~~from~~emission reductions at our ~~facilities~~Danskammer ~~during~~facility, or any ~~time~~of ~~period~~our ~~will~~other ~~depend~~facilities, ~~upon~~for ~~their~~purposes ~~dispatch~~of ~~rates~~the ~~during~~1-hour ~~the~~SO2 ~~period~~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.

~~Though~~On weJune ~~consider~~15, ~~our largest risk related to climate change to be legislative and regulatory changes intended to slow or prevent it~~2012, wethe ~~are~~EPA ~~subject~~proposed to ~~physical~~lower ~~risks~~the ~~inherent~~NAAQS infor ~~industrial operations including severe weather events such as hurricanes and tornadoes~~PM2. To5. The ~~the~~EPA ~~extent~~is ~~that~~required ~~changes~~to intake ~~climate~~final ~~effect~~action ~~changes~~by inDecember ~~weather patterns (such as more severe weather events) or changes in sea level where we have generating facilities~~14, ~~we could be adversely affected~~2012. To The ~~the~~EPA ~~extent~~intends ~~that~~to ~~climate~~make ~~change~~initial ~~results~~nonattainment indesignations ~~changes~~by inDecember ~~sea level~~2014, webased ~~would~~on ~~expect~~air ~~such~~quality ~~effects~~data tofor be2011 ~~gradual and amenable~~ to ~~structural mitigation during the useful life of the facilities~~2013. ~~However,~~ The ifearliest ~~this~~attainment isdeadlines ~~not the case it is possible that we~~ would be ~~impacted~~ in anapproximately ~~adverse~~2020. The ~~way,~~nature ~~potentially~~and ~~materially~~scope ~~so. We~~of ~~could~~potential ~~experience~~future ~~both~~requirements ~~risks~~resulting ~~and~~from ~~opportunities as~~ a ~~result~~more ofstringent ~~related~~PM2.5 ~~physical~~NAAQS ~~impacts. For~~cannot ~~example,~~be ~~more~~predicted ~~extreme~~with ~~weather~~confidence ~~patterns~~at –this ~~namely~~time, but a ~~warmer~~requirement ~~summer~~for oradditional aemission ~~cooler~~reductions ~~winter~~at –any ~~could~~of ~~increase~~our ~~demand~~facilities for ~~our~~purposes ~~products. However,~~of wea ~~also~~more ~~could~~stringent ~~experience~~PM2.5 ~~more~~NAAQS ~~difficult~~may ~~operating~~result ~~conditions~~ in ~~that~~significantly ~~type~~increased ofcompliance ~~environment. We~~costs ~~maintain~~and ~~various~~could ~~types~~have ofa ~~insurance~~material inadverse ~~amounts~~effect weon ~~consider~~our ~~appropriate~~financial ~~for~~condition, ~~risks~~results ~~associated~~of ~~with~~operations ~~weather~~and ~~events~~cash flows.

~~Federal~~New ~~Legislation~~York ~~Regarding~~NOx ~~Greenhouse~~RACT ~~Gases~~Rule. ~~Several~~ In ~~bills~~June ~~have~~2010, ~~been~~New ~~introduced~~York inState ~~Congress~~issued ~~since~~a ~~2003~~final ~~that~~rule ifestablishing ~~passed~~revised ~~would~~RACT ~~compel~~limits ~~reductions~~for inemissions ~~CO2~~of ~~emissions~~NOx from ~~power~~stationary ~~plants~~combustion sources. In ~~June~~Compliance ~~2009,~~with the ~~House~~revised ofNOx ~~Representatives~~RACT ~~passed~~limits ~~the~~is ~~American~~required ~~Clean~~by ~~Energy~~July 1, 2014, and ~~Security~~compliance ~~Act~~plans ofwere ~~2009~~due ~~(“H.R.~~to ~~2454”). Title~~NYSDEC ~~III~~by ofJanuary 1, H2012.R. ~~2454~~Compliance ~~would~~options ~~add~~include ameeting ~~new~~presumptive ~~Title~~RACT ~~VII~~limits, tocase-by-case RACT determinations, fuel switching during the ~~CAA~~ozone ~~creating~~season a(May 1 ~~Global~~through ~~Warming~~September 30), ~~Pollution~~and ~~Reduction~~participation ~~Program~~in a system averaging plan. ~~H.R.~~ ~~2454~~In ~~would~~December ~~also~~2011, ~~create~~we asubmitted ~~national~~RACT ~~cap-and-trade~~proposals ~~program~~for ~~aimed~~our atGas ~~reducing~~segment's ~~CO2~~Independence ~~emissions~~facility toand ~~three~~DNE ~~percent~~segment's ~~below~~Danskammer ~~2005~~and ~~levels~~Roseton byfacilities. ~~2012~~For our Independence facility, 17we ~~percent~~proposed ~~below~~to ~~2005~~meet ~~levels~~the bypresumptive ~~2020,~~RACT 42limits ~~percent~~using ~~below~~the ~~2005~~facility's ~~levels~~existing bySCR ~~2030~~technology and 83currently ~~percent~~applicable ~~below~~NOx ~~2005~~BACT ~~levels~~emission ~~by 2050~~limits. ~~The~~ ~~companion~~For ~~bill~~each ~~introduced~~of inour ~~the~~DNE ~~Senate,~~segment ~~S. 1733~~facilities, ~~was~~we ~~passed~~proposed byto meet the ~~Senate~~presumptive ~~Environment~~RACT ~~and~~limits ~~Public~~with ~~Works~~compliance ~~Committee~~to inbe ~~November~~achieved ~~2009~~by ~~but~~a ~~did~~system ~~not~~averaging ~~gain~~plan. ~~enough~~We ~~support~~are continuing to bereview ~~brought~~our toNOx aRACT ~~vote~~compliance ofoptions at Roseton and Danskammer. In connection with the ~~full~~DH ~~Senate~~Chapter 11 Cases, the DH Debtor Entities rejected the leases at the Danskammer and Roseton facilities. ~~While~~ ~~several~~The ~~other~~applicable ~~bills~~DH Debtor Entities have ~~been~~operated ~~introduced~~and inplan to continue operating the ~~Senate,~~leased ~~none~~facilities ~~have~~until ~~been~~such ~~passed~~facilities ~~out~~can ofbe ~~committee~~sold ~~and~~in accordance with the ~~passage~~terms of ~~comprehensive~~the ~~GHG~~Settlement ~~legislation~~Agreement and Plan Support Agreement and in ~~the~~compliance ~~next~~with ~~two~~applicable ~~years~~federal isand ~~considered~~state ~~unlikely~~regulatory requirements. Please read Note 3—Chapter 11 Cases for further discussion.

~~Federal~~Consent ~~Regulation~~Decree. In of2005, ~~Greenhouse~~we ~~Gases. In~~settled ~~April~~a ~~2007,~~lawsuit filed by the EPA and the United States Department of Justice in the U.S. ~~Supreme~~District Court ~~issued~~for ~~its~~the ~~decision~~Southern inDistrict ~~Massachusetts~~of v.Illinois ~~EPA,~~that aalleged ~~case~~violations ~~involving~~of the ~~regulation~~Clean ofAir ~~GHG~~Act ~~emissions~~and ~~from~~related ~~new~~federal ~~motor~~and ~~vehicles. The~~Illinois ~~Court~~regulations ~~held~~concerning ~~that~~certain ~~GHGs~~maintenance, ~~meet~~repair and replacement activities at our Baldwin generating station. A consent decree (the ~~definition~~“Consent ofDecree”) awas ~~pollutant~~finalized ~~under~~in July 2005. Among other provisions of the ~~CAA~~Consent ~~and~~Decree, ~~that~~we ~~regulation~~are required to not operate certain of ~~GHG~~our ~~emissions~~power isgenerating ~~authorized~~facilities byafter ~~the~~specified ~~CAA. The~~dates ~~Court~~unless ~~ruled~~certain ~~that~~emission ~~the~~control ~~EPA~~equipment ~~had~~is ainstalled. As ~~duty~~of toJune ~~determine~~30, ~~whether~~2012, oronly ~~not~~Baldwin ~~GHG~~Unit ~~emissions~~2 ~~from~~has ~~motor~~material ~~vehicles~~Consent ~~might~~Decree ~~reasonably~~work yet to be ~~anticipated~~performed, towhich ~~endanger~~is ~~public~~scheduled ~~health~~to orbe ~~welfare~~completed ~~within~~by the ~~meaning~~end of ~~the~~2012. We ~~CAA~~have spent approximately $902 million through June 30, 2012 related to these Consent Decree projects.

InPlease ~~response~~read to the ruling in Massachusetts v. EPA, the Administrator of the EPA issued a proposed finding in April 2009 that GHG emissions from motor vehicles cause or contribute to air pollution that endangers the public health and welfare. After a comment period, the Administrator issued a final endangerment finding under Section 202(a) of the CAA in December 2009. The decision found that six GHGs in the atmosphere may reasonably be anticipated to endanger public health and welfare. Subsequently, Requests for Reconsideration of EPA’Item 7—Management's ~~endangerment~~Discussion ~~finding were filed,~~ and ~~sixteen petitions~~Analysis ~~for review~~ of ~~the~~Financial ~~final~~Condition ~~EPA action have been filed in the U.S. Court of Appeals for the District of Columbia by organizations representing industry, an organization representing nine members of Congress,~~ and byResults ~~the states~~ of ~~Alabama,~~Operations—Liquidity ~~Texas~~ and ~~Virginia. The~~Capital ~~EPA~~Resources ~~denied the Requests~~ for ~~Reconsideration~~further ~~on July 29, 2010 and the denial has been challenged in the U~~discussion.~~S. Court of Appeals for the District of Columbia.~~

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 ~~finalized~~targeting ~~several~~coal-fired ~~proposed~~power ~~rules~~plants. ~~concerning~~We ~~GHGs~~submitted responses to the information request in ~~2010:~~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 ~~EPA~~Clean ~~and~~Water the U.S. Department of Transportation adopted a joint rule to regulate GHG emissions from passenger cars and light trucks under Section 202(a) of the CAA. The final motor vehicle rule was published in the Federal Register on May 7, 2010. While this rule will not directly affect us, it renders GHGs, including CO2, “subject to regulation” under the CAA.Act

●Our ~~The~~water ~~EPA~~withdrawals ~~final~~and ~~rule~~wastewater ~~requiring~~discharges ~~mandatory~~are ~~reporting~~permitted ofunder ~~GHG~~the ~~emissions~~CWA ~~from~~and ~~all~~analogous ~~sectors~~state oflaws. ~~the~~The ~~economy~~cooling ~~went~~water ~~into~~intake ~~effect~~structures inat ~~January~~several ~~2010~~of ~~and~~our ~~requires~~facilities ~~that~~are ~~reports~~regulated ofunder ~~GHG~~Section 316(b) ~~emissions~~of bethe ~~filed~~CWA. ~~annually~~This ~~thereafter.~~provision Wegenerally ~~have~~directs ~~implemented~~that ~~new~~standards ~~processes~~set ~~and~~for ~~procedures~~facilities torequire ~~report~~that ~~these~~the ~~emissions~~location, asdesign, ~~required~~construction and ~~anticipate~~capacity ~~filing~~of ~~our~~cooling ~~first~~water ~~report~~intake ~~in March 2011, with annual filings thereafter.~~

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●structures ~~The~~reflect ~~EPA~~BTA ~~Tailoring Rule proposed to “phase in” new GHG emissions applicability thresholds~~ for ~~the~~minimizing ~~PSD~~adverse ~~permit~~environmental ~~program and for the operating permit program under Title V of the CAA~~impact. ~~The~~These ~~final~~standards ~~Tailoring~~are ~~Rule~~developed ~~was~~and ~~published~~implemented in the Federal Register on June 3, 2010. For sources already subject to the PSD program, the rule establishes a GHG emissions PSD applicability threshold at a net increase of 75,000 tons per year of CO2e for ~~new~~power ~~and~~generating ~~modified~~facilities ~~sources~~through ~~from~~NPDES ~~January~~permits 2,or ~~2011~~SPDES ~~through June 30, 2011~~permits. ~~From July 1~~Historically, ~~2011~~standards ~~through June 30, 2013 the GHG emissions PSD applicability threshold will be 100,000 tons per year~~ for ~~new~~minimizing ~~sources~~adverse ~~even~~environmental ifimpacts ~~these sources are not otherwise subject to the PSD program for other pollutants. The applicability threshold for modifications to existing sources will continue to be a net increase~~ of ~~75,000~~cooling ~~tons~~water ~~per~~intakes ~~year. Several parties~~ have ~~filed Requests for Reconsideration of the Tailoring Rule with the EPA. The Rule has also~~ been ~~challenged~~made inby ~~the~~permitting ~~U.S.~~agencies ~~Court~~on ofa ~~Appeals~~case-by-case ~~for~~basis ~~the~~considering ~~District of Columbia. We cannot predict with confidence~~ the ~~outcome~~best ofprofessional ~~the~~judgment ~~litigation. Application~~ of the ~~PSD~~permitting ~~program to GHG emissions will require implementation of BACT for new and modified sources of GHG~~agency. On November 10, 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.

OnIn ~~December 30~~2004, ~~2010,~~ the EPA ~~published~~issued athe ~~Notice~~Cooling ~~of Proposed~~Water ~~Settlement~~Intake ~~Agreement~~Structures ofPhase II aRules ~~CAA~~(the ~~citizen~~"Phase II ~~suit in New York~~Rules"), etwhich ~~al.~~set v.forth ~~EPA,~~standards ~~a challenge~~ to ~~its~~implement ~~final~~the ~~NSPS~~BTA requirements for ~~electric~~cooling ~~utility~~water ~~steam~~intakes ~~generating~~at ~~units~~existing ~~(“EGUs”),~~facilities. ~~issued~~The onrules ~~February~~were ~~27,~~challenged ~~2006. Several~~by ~~states~~several ~~and~~ environmental ~~organizations~~groups ~~challenged~~and ~~the~~in ~~rule~~2007 ~~because~~were itstruck ~~did~~down ~~not~~by ~~establish~~the ~~standards~~U.S. Court of ~~performance~~Appeals for ~~GHG emissions. Following~~ the ~~Supreme~~Second ~~Court’s~~Circuit ~~decision~~ in ~~Massachusetts~~Riverkeeper, Inc. v. EPA~~, the U~~.S. ~~Court~~The ofcourt's ~~Appeals~~decision ~~for~~remanded ~~the~~several ~~District~~provisions of ~~Columbia Circuit remanded~~ the ~~rule~~rules to the EPA for further ~~consideration~~rulemaking. ofSeveral ~~the~~parties ~~GHG~~sought ~~issues. The~~review ~~proposed~~of ~~settlement~~the ~~would~~decision ~~require~~before the ~~EPA~~U.S. toSupreme ~~issue~~Court. aIn ~~proposed~~April ~~NSPS~~2009, ~~under~~ the ~~CAA~~U.S. ~~for~~Supreme ~~control~~Court ofruled ~~GHG~~that ~~emissions~~the ~~from~~EPA ~~new~~permissibly ~~and~~relied ~~modified~~on ~~EGUs,~~cost-benefit asanalysis ~~well~~in assetting ~~proposed~~the ~~emission~~national ~~guidelines~~BTA ~~for~~performance ~~control~~standard ~~of GHG emissions from existing EGUs, by July 26, 2011~~ and toin ~~finalize~~providing ~~the~~for ~~standard~~cost-benefit byvariances ~~May~~from ~~26,~~those ~~2012. Any such~~ standards ~~would~~as ~~directly~~part ~~affect several~~ of ~~our~~the ~~power~~Phase II ~~generating facilities~~Rules.

~~State~~In ~~Regulation~~July 2007, following remand of ~~Greenhouse~~the ~~Gases~~rules by the U. ~~Many~~S. ~~states~~Court ~~where~~of weAppeals, ~~operate~~the ~~generation~~EPA ~~facilities~~suspended ~~have,~~its ~~are~~Phase II ~~considering,~~Rules orand ~~are~~advised inthat ~~some~~permit ~~stage~~requirements offor ~~implementing,~~cooling ~~state~~water intake structures at existing facilities should once more be established on a case-~~only~~by-case ~~regulatory~~best ~~programs~~professional ~~intended~~judgment tobasis ~~reduce~~until ~~emissions~~replacement ofrules ~~GHGs~~are ~~from~~issued. ~~stationary~~On ~~sources~~March 28, as2011, the EPA released a ~~means~~proposed ofrule ~~addressing~~for ~~climate~~cooling ~~change~~water intake structures at existing facilities. ~~Beginning~~ inThe ~~2009,~~proposed ~~our~~rule ~~generating~~would (i) establish impingement mortality standards that would give affected facilities inthe ~~New~~option ~~York~~of either achieving impingement mortality of no more than 12 percent (annual average) and ~~Maine~~31 percent ~~were~~(monthly ~~required~~average) toor ~~purchase~~maintaining ~~CO2~~intake ~~allowances~~velocity ~~from~~at ~~the~~no ~~states~~more ~~where~~than ~~they~~0.5 ~~operate~~feet inper ~~sufficient~~second ~~quantities~~under all conditions; and (ii) require the permitting authority to ~~cover~~establish ~~CO2~~case-by-case ~~emissions. Please~~entrainment ~~see~~mortality ~~“Northeast”~~standards ~~below~~based ~~for~~on ~~further~~a ~~information. Beginning~~site-specific inassessment ~~2012~~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 ~~generating~~affected power generation facilities. inThe ~~California~~scope ~~are~~of ~~also~~requirements, ~~expected~~timing tofor compliance and the compliance methodologies that will ultimately be ~~required~~allowed tounder ~~purchase~~the ~~CO2~~final ~~allowances~~rule potentially may result in ~~sufficient~~significantly ~~quantities~~increased tocompliance ~~cover~~costs ~~CO2~~and ~~emissions. Please~~could ~~see~~have ~~“West”~~a ~~below~~material ~~for~~adverse ~~further~~effect ~~information~~on our financial condition, results of operations and cash flows.

~~Midwest. Our~~On ~~assets~~June in11, ~~Illinois~~2012, ~~may~~the ~~become~~EPA ~~subject~~released to a ~~regional~~NODA ~~GHG~~concerning ~~cap-and-trade program being developed under~~ the ~~MGGA. The~~impingement ~~MGGA~~mortality isstandards anin ~~agreement~~its ~~among~~June ~~six~~2011 ~~states~~proposed ~~and~~rule ~~one~~for ~~Canadian~~cooling ~~province~~water tointake ~~create~~structures. The ~~the~~EPA's ~~MGGRP~~NODA torequests ~~establish~~comment ~~GHG~~on ~~reduction~~new ~~targets~~impingement ~~and~~data ~~timeframes~~in ~~consistent~~the ~~with~~rulemaking ~~member~~record ~~states’ targets~~ and topossible ~~develop~~alternative aapproaches ~~market-based~~for ~~and~~impingement ~~multi-sector~~standards, ~~cap~~which ~~and~~generally ~~trade~~would ~~mechanism~~provide tomore ~~achieve~~compliance ~~the~~flexibility ~~GHG reduction targets. Illinois has set a goal of reducing GHG emissions~~ to ~~1990~~affected ~~levels by the year 2020, and to 60 percent below 1990 levels by 2050~~facilities. The ~~MGGRP~~EPA ~~is,~~has ~~however,~~reached ~~still in~~ an ~~early~~agreement ~~stage~~to ofextend ~~development~~the ~~and~~deadline ~~specific targets~~ for ~~GHG~~issuing ~~emission~~its ~~reductions~~final ~~and~~rule ~~regulations~~on tocooling ~~achieve~~water ~~such~~intake ~~targets~~structures ~~have~~until ~~not~~June ~~yet~~27, ~~been agreed to by the members~~2013.

~~West. Our~~The ~~assets~~environmental ingroups ~~California~~that ~~are~~participate ~~subject~~in toour ~~the~~NPDES ~~California~~and ~~Global~~SPDES ~~Warming~~permit ~~Solutions~~proceedings ~~Act~~generally ~~(“AB 32”),~~argue ~~which~~that ~~became~~only ~~effective~~closed incycle ~~January~~cooling ~~2007. AB~~meets ~~32 requires~~ the ~~CARB~~BTA torequirement. ~~develop~~The aissuance ~~GHG~~and ~~emission~~renewal ~~control~~of ~~program~~NPDES ~~that~~or ~~will~~SPDES ~~reduce~~permits ~~emissions~~for three of ~~GHG~~our inpower ~~the~~generation ~~state~~facilities to(Danskammer, ~~their~~Roseton ~~1990~~and ~~levels~~Moss byLanding) ~~2020~~have ~~with~~been achallenged ~~fully~~on ~~effective~~this ~~regulatory~~basis. ~~program~~The toDanskammer beSPDES inpermit, ~~place~~which bywas ~~January~~renewed ~~2012. The formal cap-~~and~~-trade~~ ~~rulemaking~~issued ~~began~~in ~~with~~June ~~the~~2006, ~~release~~does ofnot ~~the~~require ~~Staff~~installation ~~Report:~~of ~~Initial~~a ~~Statement~~closed ofcycle ~~Reasons~~cooling onsystem; ~~October 28~~however, ~~2010. The~~it ~~CARB~~does ~~considered~~require ~~the~~aquatic ~~Proposed~~organism ~~Regulation~~mortality toreductions ~~Implement~~resulting ~~the~~from ~~California~~NYSDEC's ~~Cap-and-Trade~~determination ~~Program~~of atBTA ~~its~~requirements ~~public~~under ~~hearing~~its ~~on December 16, 2010~~regulations. At ~~that~~All ~~hearing,~~appeals ~~the~~of ~~Board~~this ~~adopted~~permit ahave ~~resolution~~been toexhausted. ~~approve~~The ~~the~~Moss ~~rule~~Landing ~~with~~NPDES ~~specified~~permit, ~~modifications~~which ~~that~~was ~~will~~issued ~~be made through additional rulemakings~~ in ~~2011~~2000, ~~including~~does anot ~~rulemaking~~require toclosed ~~address~~cycle ~~allowance~~cooling ~~allocations. Initially,~~and ~~the~~was ~~program~~challenged ~~will~~by ~~apply~~a tolocal ~~large~~environmental ~~stationary~~group. ~~sources~~In ~~including~~August ~~power~~2011, ~~generation~~the ~~facilities~~Supreme ~~beginning~~Court inof ~~2012. GHG~~California ~~emission~~affirmed ~~allowances~~the ~~are~~appellate ~~expected~~court's todecision beupholding ~~sold~~the atpermit. ~~auctions~~One ~~beginning~~permit inchallenge ~~February~~is ~~2012~~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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~~The~~existing ~~State~~power ofplants: ~~California~~(i) reduce istheir awater ~~party~~intake flow rate to a ~~regional~~level ~~GHG~~commensurate ~~cap-and-trade~~with ~~program~~that ~~being~~which ~~developed~~can ~~under~~be achieved by a closed cycle cooling system; or (ii) if it is not feasible to reduce the ~~WCI~~water intake flow rate to this level, reduce ~~GHG~~impingement ~~emissions~~mortality inand ~~the~~entrainment ~~participating~~to ~~states. The~~a ~~WCI~~level iscomparable to that achieved by such a ~~collaborative~~reduced ~~effort~~water ~~among~~intake ~~seven~~flow ~~states~~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 ~~four~~at ~~Canadian~~our ~~provinces~~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’s ~~implementation~~power ofplant ABowners 32in isfiling ~~expected~~a tolawsuit ~~constitute~~in the ~~state’s~~Sacramento ~~contribution~~County toSuperior Court challenging the ~~WCI~~Policy. ~~and~~We tocannot ~~form~~predict with confidence the ~~model~~outcome ~~for~~of ~~other~~the ~~participating~~litigation ~~jurisdictions~~at this time.

~~Northeast. On~~In ~~January~~September 12010, ~~2009,~~the ~~our~~State ~~assets~~Water inBoard ~~New~~proposed ~~York~~to ~~and~~amend ~~Maine~~the ~~became~~Policy ~~subject~~ to allow an owner or operator of a ~~state~~power plant with previously installed combined-~~driven~~cycle ~~GHG~~power ~~emission~~generating ~~control~~units ~~program~~to ~~known~~continue asto ~~RGGI. RGGI~~use ~~was~~once-through ~~developed~~cooling ~~and~~at ~~implemented~~combined-cycle byunits ~~ten~~until ~~New~~the ~~England~~unit ~~and~~reaches ~~Mid-Atlantic~~the ~~states~~end toof ~~reduce~~its ~~CO2~~useful ~~emissions~~life ~~from~~under ~~power~~certain ~~plants~~circumstances. ~~The~~ ~~participating~~At ~~RGGI~~its ~~states~~December 14, ~~implemented~~2010, ~~rules~~hearing ~~regulating~~on ~~GHG~~the ~~emissions~~proposed ~~using~~amendment, athe ~~cap-and-trade~~State ~~program~~Water toBoard ~~reduce~~declined ~~CO2~~to ~~emissions~~approve bythe atamendment ~~least~~and 10instead ~~percent~~tabled ofit ~~2009~~for ~~emission~~consideration ~~levels~~until byafter the ~~year~~Statewide ~~2018~~Advisory Committee on Cooling Water Intake Structures ("SACCWIS") has reviewed facility compliance plans and made recommendations to the Board. ~~Compliance~~ ~~with~~In March 2012, SACCWIS reported its recommendations to the ~~allowance~~Board ~~requirement~~on ~~under~~the Policy's compliance deadlines, recommending that the ~~RGGI~~Board ~~cap-and-trade~~recognize ~~program~~it ~~can~~may be ~~achieved~~necessary byto ~~reducing~~modify ~~emissions,~~final ~~purchasing~~compliance ordates ~~trading~~for ~~allowances,~~generating orunits ~~securing~~due ~~offset~~to ~~allowances~~projected ~~from~~capacity anneeds ~~approved~~in ~~offset~~the ~~project. While~~ISO ~~allowances~~balancing ~~are~~authority ~~sold~~area. SACCWIS byconcluded ~~year~~that, ~~actual~~based ~~compliance~~on the state's electric system needs, it is ~~measured~~possible ~~across~~that aadditional ~~three~~reliability ~~year~~studies ~~control~~may ~~period. The~~justify ~~first~~revisions ~~control~~to ~~period~~the isfinal compliance date for some or all of Moss Landing's capacity, but that it did not believe an extension of the ~~2009-2011~~final ~~timeframe~~compliance date for Morro Bay is necessary at this time.

In ~~December~~accordance ~~2010,~~with ~~RGGI~~the ~~held~~Policy, ~~its~~on ~~tenth~~April 1, ~~auction~~2011, inwe ~~which~~submitted ~~approximately~~proposed 25compliance ~~million~~plans ~~allowances~~ for ~~the~~our ~~current~~Morro ~~control~~Bay ~~period,~~ and ~~1.2~~Moss ~~million~~Landing ~~allowances~~facilities. ~~for~~For ~~future~~Morro ~~control~~Bay ~~periods,~~and ~~were~~Moss ~~sold~~Landing atUnits ~~clearing~~6 ~~prices~~and of7, ~~$1.86~~we ~~per~~proposed ~~allowance. We~~to ~~have~~continue ~~participated~~our inongoing ~~each~~review of ~~the~~potential ~~quarterly~~compliance ~~RGGI~~options ~~auctions~~taking ~~(or~~into inaccount ~~secondary~~the ~~markets,~~facility's asapplicable ~~appropriate)~~final tocompliance ~~secure~~deadline. ~~some~~For ~~allowances~~Moss ~~for~~Landing ~~our~~Units ~~affected~~1 ~~assets. We~~and ~~expect~~2, ~~that~~we ~~the~~proposed ~~increased~~to ~~operating~~continue ~~costs~~current ~~resulting~~once-through ~~from~~cooling ~~purchase~~operations ofthrough ~~CO2~~the ~~allowances~~end ~~will~~of be2032, at ~~least~~which ~~partially~~time ~~reflected~~we inwould ~~market~~evaluate ~~prices. The~~repowering ~~RGGI~~or ~~states~~installation ~~plan~~of tofeasible ~~continue~~control ~~to conduct quarterly auctions in 2011~~measures.

~~Our~~It ~~generating~~may ~~facilities~~not inbe ~~New~~possible ~~York~~to ~~and~~meet ~~Maine~~the ~~emitted~~requirements ~~approximately~~of ~~4.8~~the ~~million~~Policy ~~tons~~without ofinstalling ~~CO2~~closed ~~during~~cycle ~~2010~~cooling systems. ~~Based~~ onGiven the ~~average~~numerous ~~clearing~~variables ~~price~~and offactors ~~$2.51~~involved ~~for~~in ~~current~~calculating ~~allowances~~the ~~sold~~potential incosts ~~all~~of ~~auctions~~closed ~~held~~cycle tocooling ~~date~~systems, weany ~~estimate~~decision ~~our~~to ~~cost~~install ofsuch ~~allowances~~a ~~required~~system towould ~~operate~~be ~~these~~made ~~facilities~~on ~~during~~a ~~2010~~case-by-case ~~would~~basis beconsidering ~~approximately~~all ~~$12~~relevant ~~million~~factors at the time. ~~The~~ ~~RGGI~~In ~~compliance~~addition, ~~period~~while the Policy is ~~three~~generally ~~years~~at least as stringent as the EPA's proposed rule for cooling water intake structures, socompliance with the ~~actual~~Policy ~~cost~~may not meet all requirements of ~~allowances~~the ~~required~~forthcoming ~~for~~EPA ~~our~~final ~~2010~~rule. ~~operations~~If ~~may~~capital ~~vary~~expenditure ~~from~~requirements ~~this~~related ~~estimate~~to ascooling awater ~~result~~systems are great enough to render the continued operation of ~~purchases~~a particular plant uneconomical, we could at our option, and~~/or~~ ~~sales~~subject ofto ~~allowances~~any ~~between~~applicable ~~now~~financing agreements and ~~2012~~other obligations, ~~which~~reduce ~~may~~operations ~~result~~or incease ato ~~lower~~operate orthe ~~higher~~plant ~~average~~and ~~allowance~~forego ~~cost~~such capital expenditures.

~~Climate~~New ~~Change~~York ~~Litigation~~Water Intake Policy. ~~There~~ On isJuly 10, a2011, ~~risk~~the ofNYSDEC ~~litigation~~issued ~~from~~its ~~those~~final ~~seeking~~policy ~~injunctive~~on ~~relief~~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 togreater ~~impose~~of ~~liability~~that onwhich ~~sources~~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 ~~GHG~~capacity ~~emissions~~over a current five-year averaging period from the entrainment performance goal, ~~including~~provided ~~power~~that ~~generators~~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 ~~claims~~entrainment ofon ~~adverse~~a ~~effects~~best ~~due~~professional judgment basis. For facilities for which a BTA determination was issued prior to ~~climate~~adoption ~~change~~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. ~~Recent~~ ~~court~~At ~~decisions~~this ~~disagree~~time onwe ~~whether~~do not believe that the ~~claims~~NYSDEC ~~are~~Policy will have a material impact on operations of the subject toDNE ~~resolution~~segment byfacilities given the ~~courts~~prior BTA determination for Danskammer and ~~whether~~the entrainment exemption for low-capacity facilities. In connection with the ~~plaintiffs~~DH Chapter 11 Cases, the DH Debtor Entities rejected the lease at the Danskammer and Roseton facilities. The applicable DH Debtor Entities have ~~standing~~operated and plan to ~~sue~~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.

InOther ~~September~~CWA ~~2009,~~Initiatives. The ~~the~~requirements ~~U.S.~~applicable ~~Court~~to ofwater ~~Appeals~~quality ~~for~~are ~~the~~expected ~~2nd~~to ~~Circuit~~increase ~~considered~~in the ~~appeal~~future. ofA ~~Connecticut~~number v.of ~~AEP~~efforts ~~and~~are ~~held~~under ~~that~~way within the ~~U.S.~~EPA ~~District~~to ~~Court~~evaluate iswater anquality ~~appropriate~~criteria ~~forum~~ for ~~resolving~~parameters ~~claims~~associated bywith ~~eight~~the ~~states~~by-products ~~and~~of ~~New~~fossil ~~York~~fuel ~~City~~combustion. ~~against~~These ~~six~~parameters ~~electric~~relate ~~power~~primarily ~~generators related~~ to ~~climate change. Similarly~~arsenic, inmercury ~~October~~and ~~2009, the U~~selenium.S. ~~Court~~Under ofa ~~Appeals~~consent ~~for~~decree, ~~the~~as ~~5th~~modified, ~~Circuit considered~~ the ~~appeal~~EPA ofis ~~Comer~~required v.to ~~Murphy~~propose ~~Oil~~revisions ~~and~~to ~~held~~the ~~that~~Effluent ~~claims~~Guidelines ~~related~~for tosteam ~~climate~~electric ~~change~~units by ~~property~~November ~~owners~~20, ~~along~~2012 ~~the~~and ~~Mississippi~~to ~~Gulf~~take ~~Coast~~final ~~against~~action ~~energy~~on ~~companies~~the ~~could~~proposal ~~be resolved~~ by ~~the~~April ~~courts. However~~28, ~~the Comer v~~2014. Significant ~~Murphy~~changes ~~decision~~in ~~was~~these ~~subsequently~~requirements ~~vacated. In~~could ~~September~~require ~~2009,~~installation ~~the U.S. District Court for the Northern District~~ of ~~California~~additional ~~dismissed~~water ~~claims~~treatment ~~related~~equipment toat ~~climate~~our ~~change~~facilities byor anrequire ~~Alaskan~~dry ~~community~~handling ~~against~~of 24coal ~~companies~~ash. inThe ~~the~~nature ~~energy industry, including us, in Native Village of Kivalina~~ and ~~City~~scope of ~~Kivalina~~potential v.future ~~ExxonMobil~~water ~~Corporation,~~quality etrequirements ~~al. The~~concerning ~~Kivalina case is pending before~~ the ~~U.S.~~by-products ~~Court~~ of ~~Appeals~~fossil ~~for~~fuel ~~the~~combustion ~~9th~~cannot ~~Circuit. Please~~be ~~read~~predicted ~~Note~~with ~~22—Commitments~~confidence ~~and~~at ~~Contingencies~~this ~~for~~time, ~~further~~but ~~discussion of this case.~~

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. On December 6, 2010, the U.S. Supreme Court agreed to review Connecticut v. AEP.

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~~Carbon~~could ~~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 2 million bottomland hardwood seedlings. In California, we are evaluating the use of bio-fuels as a ~~means~~material ofadverse ~~reducing~~effect ~~reliance~~ on ~~traditional~~our ~~fuels. In~~financial ~~Illinois~~condition, weresults ~~are~~of ~~funding~~operations ~~prairie, bottomland hardwood~~ and ~~savannah~~cash ~~restoration projects in partnership with the Illinois Conservation Foundation~~flows. 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.

~~Our~~Coal ~~Moss~~Combustion Landing facility in California is involved in a pilot project with Calera Corporation that treats flue gas emissions from the facility in a process that produces materials similar to Portland cement and aggregate. The Calera carbonate mineralization process binds CO2 with minerals in brines or seawater in a manner that has the potential to permanently sequester the CO2 in the solid materials it produces. If this process can be developed on a commercial scale, it would provide a means of capturing CO2 and creating beneficial, marketable products for the building materials industry.Residuals

~~Other~~The ~~Environmental~~combustion ~~Matters~~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 ~~Clean~~draft ~~Air~~reports ~~Act~~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.

~~The~~In ~~CAA~~addition, ~~and~~on ~~comparable~~June 21, ~~state~~2010, ~~laws~~the ~~and~~EPA ~~regulations~~proposed ~~relating~~two toalternative ~~air~~rules ~~emissions~~under ~~impose~~RCRA ~~responsibilities~~for onfederal ~~owners~~regulation of the management and ~~operators~~disposal of ~~sources~~CCR offrom ~~air~~electric ~~emissions,~~utilities ~~including~~and ~~requirements~~independent topower ~~obtain~~producers. ~~construction~~One ~~and~~proposal ~~operating~~would ~~permits~~regulate CCR as ~~well~~a asspecial ~~compliance~~waste ~~certifications~~under ~~and~~RCRA ~~reporting~~subtitle ~~obligations~~C rules when those wastes are destined for disposal in a landfill or surface impoundment. The ~~CAA~~subtitle ~~requires~~C ~~that~~proposal ~~fossil-fueled~~would ~~electric~~subject ~~generating~~persons ~~plants~~who ~~have~~generate, ~~sufficient~~transport, ~~emission~~treat, ~~allowances~~store toor ~~cover~~dispose ~~actual~~of ~~SO2~~such ~~emissions~~CCR ~~and~~to inmany ~~some~~of ~~regions~~the ~~NOX~~existing ~~emissions,~~RCRA ~~and~~regulations ~~that~~applicable ~~they~~to ~~meet~~hazardous waste. While certain ~~pollutant~~types ~~emission~~of ~~standards~~beneficial asuse ~~well. Our~~of ~~power~~CCR ~~generation~~would ~~facilities~~be exempt from regulation under the subtitle C proposal, ~~some~~the impact of ~~which~~subtitle ~~have~~C ~~changed~~regulation ~~their~~on ~~operations~~the tocontinued ~~accommodate~~viability ~~new~~of ~~control~~beneficial ~~equipment~~use oris ~~changes~~debated. inRegulation ~~fuel~~under ~~mix,~~subtitle ~~are~~C ~~currently~~would ineffectively ~~compliance~~phase ~~with~~out ~~these~~the ~~requirements~~use of ash ponds for disposal of CCR.

InThe ~~order~~alternative toproposal ~~ensure~~would ~~continued~~regulate ~~compliance~~CCR ~~with~~disposed ~~the~~in ~~CAA~~landfills ~~and~~or ~~related~~surface ~~rules~~impoundments ~~and~~as ~~regulations,~~a ~~including~~solid ~~ozone-related~~waste ~~requirements,~~under wesubtitle ~~have~~D ~~plans~~of ~~to install additional emission reduction technology at our GEN-MW coal-fired facilities~~RCRA. ~~When~~ ~~our~~The ~~plans~~subtitle ~~are~~D ~~complete,~~proposal ~~our~~would ~~four~~establish ~~coal-fired~~national ~~units~~criteria ~~at our Baldwin and Havana facilities will have dry flue gas desulphurization systems~~ for ~~the~~disposal ~~control~~ of ~~SO2~~CCR ~~emissions,~~in ~~and~~landfills ~~electrostatic precipitators~~ and ~~baghouses~~surface ~~for~~impoundments, ~~the~~requiring ~~control~~new ~~of particulate emissions. Selective catalytic reduction technology for the control of NOX emissions has been installed and operated on three of these~~ units ~~for several years; GEN-MW’s remaining units use low-NOX burners and overfire air~~ to ~~lower~~install ~~NOX~~composite ~~emissions~~liners. ~~Our~~ ~~coal-fired~~The ~~units~~subtitle atD ~~our~~proposal ~~Vermilion~~might ~~and~~also ~~Hennepin~~require ~~facilities~~existing ~~have~~surface ~~electrostatic~~impoundments ~~precipitators~~without ~~and~~liners ~~baghouses~~to ~~for~~close ~~the~~or ~~control~~be ofretrofitted ~~particulate~~with ~~matter. We~~composite ~~now~~liners ~~have~~within ~~activated~~five carbon injection technology for the control of mercury emissions installed and operating on approximately 95 percent of GEN-MW’s coal-fired capacity, and we will install this technology on our final unit by 2013years.

~~Multi~~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-~~Pollutant~~hazardous ~~Air~~waste ~~Emission~~also ~~Initiatives~~has been introduced in Congress.

InWe ~~recent~~have ~~years,~~implemented hydrogeologic ~~various~~investigations ~~federal~~for ~~and~~the ~~state~~CCR ~~legislative~~surface ~~and~~impoundment ~~regulatory~~at ~~multi-pollutant~~our ~~initiatives~~Baldwin ~~have~~facility ~~been~~and ~~introduced. In~~for ~~early~~two ~~2005,~~CCR ~~the~~surface ~~EPA~~impoundments ~~finalized~~at ~~several~~our ~~rules~~Vermilion ~~(i.e.~~facility ~~CAIR~~in ~~and~~response ~~CAMR)~~to ~~that~~requests ~~would~~by ~~collectively~~the ~~require~~Illinois ~~reductions~~EPA. Groundwater ofmonitoring ~~approximately~~results 70indicate ~~percent~~that ~~each~~the inCCR ~~emissions~~surface ofimpoundments ~~SO2~~at ~~and~~each ~~NOx~~site byimpact ~~2015~~onsite ~~and mercury by 2018 from coal-fired power generation units~~groundwater.

~~CAIR~~ isAt ~~intended~~the torequest ~~reduce~~of ~~SO2~~the ~~and~~Illinois ~~NOx~~EPA, ~~emissions~~in ~~from~~late ~~power~~2011 ~~generation~~we ~~sources~~initiated ~~across~~an ~~the~~investigation ~~eastern~~at ~~United~~the ~~States~~Baldwin ~~(29~~facility ~~states~~to ~~and~~determine if the ~~District~~facility's CCR surface impoundment impacts offsite groundwater. Results of ~~Columbia)~~the ~~and~~offsite togroundwater ~~address~~quality ~~fine~~investigation ~~particulate~~at ~~matter~~Baldwin, ~~and~~as ~~ground-level~~submitted ~~ozone~~to ~~National~~the ~~Ambient~~Illinois ~~Air~~EPA ~~Quality~~on ~~Standards. CAIR~~April ~~was~~24, ~~challenged~~2012, ~~and~~indicate two ~~the~~localized ~~U.S.~~areas ~~Court~~where ofClass ~~Appeals~~I ~~for~~groundwater ~~the~~standards ~~District~~were ofexceeded. If ~~Columbia~~these ~~Circuit~~offsite ~~remanded~~groundwater ~~the~~results ~~rule~~are ultimately attributed to the ~~EPA~~Baldwin toCCR ~~correct~~surface ~~several~~impoundment ~~aspects~~and ofremediation ~~the~~measures ~~rule~~are ~~determined~~necessary byin the ~~Court~~future, towe bemay ~~unacceptable. The~~incur ~~rule~~significant ~~remains~~costs ~~effective~~that ~~until~~could ~~the~~have ~~EPA~~a ~~completes~~material ~~its~~adverse ~~proposed~~effect ~~Transport~~on ~~Rule~~our tofinancial ~~replace~~condition, ~~CAIR. Our~~results ~~facilities~~of inoperations ~~Illinois~~ and ~~New~~cash ~~York~~flows. At ~~are~~this ~~subject~~time towe ~~state~~cannot ~~SO2~~reasonably ~~and~~estimate ~~NOx~~the ~~limitations~~costs ~~more~~of ~~stringent~~corrective ~~than~~action ~~those~~that ~~imposed~~ultimately bymay ~~the~~be ~~currently~~required ~~effective~~at ~~CAIR~~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

~~TABLE~~Table OFof ~~CONTENTS~~Contents

~~Transport~~that ~~Rule. On~~such ~~August~~groundwater 2,migrates ~~2010,~~offsite to the ~~EPA~~north ~~proposed~~of ~~its~~the ~~Federal~~property ~~Implementation~~and ~~Plans~~ to ~~Reduce~~the ~~Interstate~~adjacent ~~Transport~~Middle Fork of ~~Fine~~the ~~Particulate~~Vermilion ~~Matter~~River. The ~~and~~proposed ~~Ozone~~corrective ~~(the~~action ~~“proposed~~plans ~~Transport~~include ~~Rule”). The~~groundwater ~~proposed~~monitoring ~~Transport~~and ~~Rule~~recommend ~~would~~closure beof ~~implemented~~both ~~through~~CCR ~~federal~~impoundments, ~~implementation~~including ~~plans~~installation ~~that~~of ~~would~~a begeosynthetic ~~effective~~cover. In inaddition, ~~each~~we ~~affected~~submitted ~~state~~an asapplication ~~soon~~to as the ~~final~~Illinois ~~rule~~EPA isto ~~issued. The~~establish ~~proposed~~a ~~rules~~groundwater ~~are~~management ~~intended~~zone towhile ~~reduce~~impacts ~~emissions~~from ofthe ~~SO2~~facility ~~and~~are ~~NOx~~mitigated. The ~~from~~preliminary ~~large~~estimated ~~electric~~cost ~~generating~~of ~~units~~the inrecommended 31closure ~~eastern~~alternative ~~states~~for ~~and~~both ~~the~~impoundments, ~~District~~including ofpost-closure ~~Columbia~~care, is approximately $14 million. The ~~rules~~Vermilion ~~would~~facility ~~impose~~also ~~cap~~has ~~and~~a ~~trade~~third ~~programs~~CCR ~~within~~surface ~~each~~impoundment, ~~state~~the ~~that~~new ~~would~~east ~~cap~~impoundment ~~emissions~~that ofis ~~SO2~~lined and ~~NOx~~is atnot ~~levels~~known ~~predicted~~ to ~~eliminate~~impact ~~that~~groundwater. Although ~~state’s~~not ~~contribution~~part toof ~~nonattainment~~the inproposed corrective action plans, orif ~~interference~~we ~~with~~decide ~~maintenance~~to ofclose ~~attainment~~the ~~status~~new east impoundment by, ~~down-wind~~removing ~~areas~~its CCR contents concurrent with ~~respect~~the torecommended closure alternative for the ~~National~~old ~~Ambient~~east ~~Air~~and ~~Quality~~north ~~Standards~~impoundments, the preliminary total estimated closure cost for ~~particulate~~all ~~matter~~three ~~smaller~~impoundments ~~than~~would ~~2.5~~be ~~micrometers~~approximately ~~(PM2~~$16 million.5) If the proposed corrective action plans submitted for the old east and ~~ozone. Our~~north ~~generating~~CCR ~~facilities~~impoundments inare timely approved by the Illinois EPA, ~~New~~detailed ~~York~~proposed ~~and~~closure ~~Pennsylvania~~plans would be ~~subject~~submitted to the ~~rules~~Illinois EPA by year end 2012 for approval.

~~The~~In ~~rules~~July ~~applicable to annual and ozone season NOx emissions would require compliance by January 1~~2012, ~~2012. The~~the ~~rules applicable to SO2 emissions from electric generating units in~~ Illinois, ~~New~~EPA ~~York~~issued ~~and~~violation ~~Pennsylvania~~notices ~~would~~alleging beviolations ~~implemented~~of ingroundwater ~~two~~standards ~~stages~~onsite ~~with~~at ~~compliance~~the ~~dates~~Baldwin ~~of January 1, 2012~~ and ~~January~~Vermilion ~~1, 2014~~facilities. ~~The~~ In ~~EPA~~response, ~~would~~we ~~initially~~have ~~allocate~~submitted ~~NOx and SO2 emission allowances~~ to ~~existing~~the ~~electric~~Illinois ~~generating~~EPA ~~units~~a ~~based~~proposed oncompliance ~~the~~agreement ~~lower~~for ofeach ~~2009~~facility. For ~~annual~~Vermilion, ~~emissions~~we orproposed ~~projected 2012 emissions necessary~~ to ~~meet~~implement the ~~EPA’s~~previously ~~emission~~submitted ~~budget~~corrective ~~for~~action ~~the~~plans ~~state. The~~and, ~~SO2~~for ~~emission budgets in Illinois~~Baldwin, ~~New~~we ~~York~~proposed ~~and~~to ~~Pennsylvania~~perform ~~would~~additional bestudies ~~reduced~~of inhydrogeologic ~~2014,~~conditions and ~~existing~~apply ~~electric~~for ~~generating~~a ~~units~~groundwater inmanagement ~~these~~zone ~~states would be allocated fewer SO2 emission allowances beginning~~ in ~~2014. Electric~~preparation ~~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 technologiessubmittal, ~~(ii)~~as ~~operating existing controls more often~~necessary, ~~(iii)~~of ~~switching~~a ~~fuels,~~corrective oraction ~~(iv) curtailing or ceasing operation~~plan.

~~Allowance~~Climate trading would be allowed under the proposed Transport Rule among sources within the same state with limited interstate allowance trading. Illinois, New York and Pennsylvania would be subject to three new cap and trade programs under the proposed Transport Rule capping emissions of NOx from May 1st through September 30th and capping emissions of SO2 and NOx respectively, on an annual basis.Change

InFor the ~~preamble~~last toseveral ~~the proposed Transport Rule~~years, ~~the~~there ~~EPA~~has ~~solicited~~been ~~comments on alternatives and variations to~~ a ~~number~~robust ofpublic ~~provisions~~debate ofabout ~~the~~climate ~~proposal~~change ~~including~~and the ~~state~~potential ~~emissions~~for ~~budgets,~~regulations ~~the~~requiring ~~emission~~lower ~~allowance~~emissions ~~allocation~~of ~~approach~~GHG, ~~auction~~primarily ofCO2 ~~allowances rather than allocation by the EPA,~~ and ~~direct control of emissions through emission rate limits~~methane. We ~~submitted~~believe ~~comments~~that on the ~~proposed~~focus ~~rule on October 1, 2010. On January 7, 2011, the EPA issued a Notice~~ of ~~Data~~any ~~Availability~~federal ~~and~~program ~~requested~~attempting ~~comment~~to onaddress ~~alternative~~climate ~~allocation~~change ~~methodologies~~should ~~based~~include onthree ~~historic~~critical, ~~heat~~interrelated ~~input. We~~elements: ~~will continue to monitor~~ (i) the ~~rulemaking~~environment, ~~process surrounding~~ (ii) the ~~proposed~~economy ~~Transport Rule~~ and to(iii) energy ~~evaluate any potential impacts it might have on our operations~~security.

~~Mercury/HAPs. In~~We ~~March~~cannot ~~2005,~~confidently predict the ~~EPA~~final ~~issued~~outcome of the ~~CAMR~~current ~~for~~debate ~~control~~on ofclimate ~~mercury~~change ~~emissions~~nor ~~from~~can ~~coal-fired~~we ~~power~~predict ~~plants~~with ~~and~~confidence ~~established~~the aultimate ~~cap~~requirements ~~and~~of ~~trade~~proposed ~~program~~or ~~requiring~~anticipated ~~states~~federal toand ~~promulgate~~state ~~rules~~legislation atand ~~least~~regulations asintended ~~stringent~~to asaddress ~~CAMR~~climate change. In ~~December~~These ~~2006~~activities, and the ~~Illinois~~highly ~~Pollution~~politicized ~~Control~~nature ~~Board~~of ~~approved~~climate achange, ~~state~~suggest ~~rule~~a ~~for~~trend ~~the~~toward ~~control~~increased regulation of ~~mercury~~GHG ~~emissions~~that ~~from~~could ~~coal-fired~~result ~~power~~in ~~plants~~a ~~that~~material ~~required~~adverse ~~additional~~effect ~~capital~~on our financial condition, results of operations and ~~O&M~~cash ~~expenditures~~flows. atExisting ~~each~~and anticipated federal and state regulations intended to address climate change may significantly increase the cost of ~~our~~providing ~~Illinois~~electric ~~coal~~power, resulting in far-~~fired~~reaching ~~plants~~and ~~beginning~~significant impacts on us and others in ~~2007~~the power generation industry over time. ~~The~~ ~~State~~It ofis ~~New~~possible ~~York~~that ~~has~~federal ~~also~~and ~~approved~~state aactions ~~mercury~~intended ~~rule~~to address climate change could result in costs assigned to GHG emissions that ~~will~~we ~~likely~~would ~~require~~not usbe able to ~~incur~~fully ~~additional~~recover through market pricing or otherwise. If capital and/or operating costs ~~for~~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 ~~Danskammer~~option ~~power~~and ~~generating~~subject ~~facility~~to byany ~~January~~applicable 1financing agreements or other obligations, ~~2015~~reduce operations or cease to operate such plants and forego such capital and/or operating costs.

InPower ~~February~~generating ~~2008,~~facilities ~~the~~are ~~U.S.~~a ~~Court~~major ofsource ~~Appeals for the District~~ of ~~Columbia~~GHG ~~Circuit~~emissions—in ~~vacated the CAMR; however~~2011, ~~the~~our ~~Illinois~~Gas and ~~New~~DNE ~~York~~segment ~~mercury~~facilities ~~regulations~~emitted ~~remain~~approximately ~~in effect~~5. In3 million ~~December 2009, the EPA issued information requests under Section 114 of the CAA to many coal-~~ and ~~oil- fired steam electric generating companies, including certain of our operating companies~~1. ~~These~~3 million ~~requests~~tons ~~required stack tests to develop information on emissions~~ of ~~mercury and other HAPs~~CO2e, ~~including~~respectively. ~~organics,~~The ~~acid~~amounts ~~gases and non-mercury metals, and will be used by the EPA to develop emission standards for HAPs under Section 112~~ of ~~the~~CO2e ~~CAA. Under~~emitted ~~a consent decree, the EPA is required to propose MACT emission standards for HAPs~~ from ~~coal-~~our ~~and~~facilities ~~oil-fired~~during ~~electric~~any ~~utility~~time ~~steam~~period ~~generating units, pursuant to CAA Section 112, by March 16, 2011 and to issue final standards by November 16, 2011. We~~ will ~~continue~~depend toupon ~~monitor~~their ~~the~~dispatch ~~HAP~~rates ~~rulemaking~~during ~~process and evaluate any potential impacts~~ the ~~rulemaking might have on our operations~~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.

~~TABLE~~Table OFof ~~CONTENTS~~Contents

~~Visibility. CAVR~~In ~~requires~~response ~~states~~ to ~~analyze~~that ~~and~~decision, ~~include~~the ~~BART~~EPA ~~requirements~~issued ~~for~~a ~~individual~~finding ~~facilities~~ in ~~their~~December ~~SIPs~~2009 that GHG emissions from motor vehicles cause or contribute to ~~address~~air ~~regional~~pollution ~~haze~~that endangers the public health and welfare. The ~~requirements~~EPA ~~apply~~has since also finalized several rules concerning GHGs as directly relevant to our facilities. ~~built~~In ~~between~~January ~~1962~~2010, ~~and~~the ~~1977~~EPA ~~that~~rule ~~emit~~on ~~more~~mandatory ~~than~~reporting ~~250~~of ~~tons~~GHG ~~per~~emissions ~~year~~from all sectors of ~~certain~~the ~~regulated~~economy ~~pollutants~~went ininto ~~specific~~effect ~~industrial~~and ~~categories,~~requires ~~including~~the ~~utility~~annual ~~boilers~~reporting of GHG emissions. In ~~July~~We ~~1999~~have implemented processes and procedures to report these emissions and, ~~the~~as ~~EPA~~required, ~~published~~reported ~~its~~our ~~final~~2010 ~~Regional~~GHG ~~Haze~~emissions by September 30, 2011 The EPA Tailoring Rule, which ~~requires~~became ~~states~~effective toin ~~submit~~January ~~regional~~2011, ~~haze~~phases ~~implementation~~in ~~plans~~new toGHG emissions applicability thresholds for the ~~EPA~~PSD ~~detailing~~permit ~~their~~program ~~plans~~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 ~~reduce~~GHG emissions will require implementation of ~~visibility-impairing~~BACT ~~pollutants~~for ~~(NOx~~new and modified major sources of GHG. In November 2010, ~~SO2~~the ~~and~~EPA ~~particulates)~~issued ~~that~~its ~~affect~~PSD ~~visibility~~and inTitle ~~downwind~~V ~~Federal~~Permitting ~~Class~~Guidance Ifor ~~Areas~~Greenhouse (iGases.e. ~~parks~~For coal-fired electric generating units, the guidance focuses on steam turbine and ~~wilderness)~~boiler ~~with~~efficiency improvements as a ~~goal~~reasonable toBACT ~~restore~~requirement. The ~~natural~~endangerment ~~visibility~~finding, ~~conditions~~including the EPA's denial of subsequent requests for reconsideration, and the Tailoring Rule were challenged in ~~these~~the ~~areas~~U.S. byCourt ~~2064~~of Appeals for the District of Columbia Circuit.

~~The~~On ~~State~~June of26, ~~New~~2012, ~~York~~the ~~has~~court ~~been~~issued ~~identified~~an asopinion ~~having certain BART eligible facilities that contribute to regional haze~~ in ~~Class~~Coalition IFor ~~Areas~~Responsible ~~in other states~~Regulation, ~~including our Roseton power generating facility and Unit 4 at our Danskammer power generating facility~~Inc. ~~On May 1~~, ~~2010,~~et ~~the~~al. ~~New York State BART Rule became effective~~v. In ~~compliance~~EPA, ~~with~~upholding the ~~rule,~~endangerment ~~our~~finding ~~Danskammer~~ and ~~Roseton~~several ~~power~~EPA ~~generating~~GHG-related ~~facilities~~rules. The ~~performed~~court aheld ~~comprehensive,~~that ~~unit~~the ~~specific~~EPA's ~~modeling~~endangerment ~~analysis~~finding ~~for~~was ~~their~~not ~~BART~~arbitrary ~~eligible~~and ~~units~~capricious tonotwithstanding ~~determine~~scientific ~~their~~uncertainty ~~impact~~and onthat ~~visibility. In~~ the ~~fall~~Agency ofhad ~~2010,~~adequate weevidence ~~submitted~~on ~~this~~which ~~analysis~~ to ~~NYSDEC~~base ~~along~~its ~~with a proposal to reduce NOx and SO2 emission limits to address impacts on visibility~~finding. ~~Compliance~~ The atcourt ~~our~~also ~~Roseton~~held ~~facility~~that ~~would be achieved, effective January 1, 2014, by reducing~~ the ~~sulfur~~Tailpipe ~~content~~Rule ofwas ~~our~~adequately ~~fuel~~justified ~~oil~~ and ~~optimization~~that, ofupon ~~existing~~making ~~NOx~~the ~~emission~~Endangerment ~~controls. Compliance at Danskammer Unit 4 would be achieved~~Finding, ~~effective~~the ~~July~~Agency 1,was ~~2014,~~required ~~through~~by ~~optimization~~Clean ofAir ~~existing~~Act ~~NOx~~Section ~~emission~~202 ~~controls,~~to ~~co-firing~~regulate ~~with~~tailpipe ~~natural~~GHG ~~gas,~~emissions. The ~~use~~court ofdid ~~alternative~~not ~~coal,~~reach ~~and/or~~the ~~installation~~merits of ~~additional~~the ~~emission~~arguments ~~controls. Our~~challenging ~~BART proposals are under review by NYSDEC and~~ the EPA~~. We~~'s ~~are~~Timing ~~continuing~~Rule toand ~~review~~Tailoring ~~our compliance options at Danskammer~~Rule, ~~options~~instead ~~which~~deciding ~~could~~that ~~result~~the inpetitioners ~~significant~~lacked ~~expenditures~~standing ~~for~~to ~~emission~~challenge ~~control~~those ~~equipment~~rules.

~~Other~~In ~~Air~~March ~~Emission~~2011, ~~Initiatives~~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.

~~New York NOx RACT Rule.~~ In ~~June 2010~~February 2012, ~~New~~the ~~York~~EPA ~~State~~proposed ~~issued~~not ato ~~final~~change ~~rule~~its ~~establishing~~Tailoring ~~revised~~Rule GHG ~~RACT~~permitting ~~limits~~thresholds for ~~emissions~~the ofPSD ~~NOx~~and ~~from~~Title ~~stationary~~V ~~combustion~~operating ~~sources~~permit programs. ~~Compliance~~ Under ~~with~~ the ~~revised~~approach ~~NOx~~that ~~RACT~~would ~~limits~~be ismaintained ~~required~~ by ~~July~~the 1proposal, ~~2014~~existing sources that emit 100,000 ~~and~~tons ~~compliance~~per ~~plans~~year ~~must~~(tpy) beof ~~submitted~~CO2e toand ~~NYSDEC~~make changes increasing GHG emissions by ~~January~~at 1least 75,000 ~~2012. Compliance~~tpy ~~options~~of ~~include~~CO2e ~~meeting~~continue ~~presumptive~~to ~~RACT~~require ~~limits,~~PSD ~~case-by-case~~permits. Facilities ~~RACT~~that ~~determinations,~~must ~~fuel~~obtain ~~switching~~a ~~during~~PSD ~~the~~permit ~~ozone~~for ~~season~~other ~~(May~~pollutants 1must ~~through~~also ~~September~~address ~~30),~~GHG ~~and~~emission ~~participation~~increases inof a75,000 ~~system~~tpy ~~averaging~~or ~~plan~~more of CO2e. We The ~~are~~EPA's ~~continuing~~proposal tonotes ~~review~~that the ~~potential~~agency ~~impact~~will ofcomplete ~~the~~a ~~revised~~subsequent ~~NOx~~rulemaking ~~RACT~~by ~~rule~~April 30, on2016, ~~our~~to ~~subject~~determine ~~power~~whether ~~generation~~it ~~facilities~~would be appropriate to lower the thresholds at that time.

~~Midwest~~State ~~Consent~~Regulation ~~Decree. In 2005, we settled a lawsuit filed by the EPA and the U.S. Department~~ of ~~Justice~~Greenhouse ~~that alleged violations of the CAA and related federal and Illinois regulations concerning certain maintenance, repair and replacement activities at our Baldwin generating facility~~Gases. A Many ~~consent~~states ~~decree~~where ~~was~~we ~~finalized~~operate ingeneration ~~July 2005 that would prohibit operation of certain of our power generating~~ facilities ~~after certain dates unless specified emission control equipment is installed (the “Midwest Consent Decree”). We~~ have, ~~achieved~~are ~~all~~considering, ~~emission~~or ~~reductions to date under the Midwest Consent Decree and~~ are in ~~the~~some ~~process~~stage of ~~installing~~implementing, ~~additional~~state-only ~~emission~~regulatory ~~control~~programs ~~equipment~~intended to ~~meet~~reduce ~~future~~emissions ~~Midwest~~of ~~Consent~~GHGs ~~Decree~~from ~~emission~~stationary ~~limits. We~~sources ~~anticipate~~as our costs associated with the Midwest Consent Decree projects, which we expect to incur through 2013, will be approximately $960 million, which includes approximately $730 million spent to date. This estimate required a ~~number~~means of ~~assumptions~~addressing ~~about~~climate ~~uncertainties that are beyond our control, including an assumption that labor and material costs will increase at four percent per year over the remaining project term~~change. ~~The following are the future estimated capital expenditures required to comply with the Midwest Consent Decree:~~

2011		2012		2013
		(in millions)
$	140	$	80	$	10

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.

IfOur ~~the~~assets ~~costs~~in ofCalifornia ~~these~~are ~~capital~~subject ~~expenditures~~to ~~become~~the ~~great~~California ~~enough~~Global toWarming ~~render~~Solutions ~~operation~~Act of("AB ~~the~~32"), ~~affected~~which ~~facility~~became oreffective ~~facilities~~in ~~uneconomical,~~January we2007. ~~could,~~AB at32 ~~our~~requires ~~option,~~the ~~cease~~CARB to ~~operate~~develop ~~the~~a ~~facility~~GHG oremission ~~facilities~~control ~~and~~program ~~forego~~that ~~these~~will ~~expenditures~~reduce ~~without~~emissions ~~any~~of ~~further~~GHG ~~obligations~~in ~~under~~ the ~~Midwest~~state ~~Consent~~to ~~Decree. Further,~~their ~~our~~1990 ~~production~~levels ~~may~~by be2020. ~~affected~~In ifOctober we2011, ~~fail~~the toCARB ~~meet~~adopted ~~certain~~its ~~performance~~final ~~standards~~GHG ~~under~~cap-and-trade ~~the~~regulation, ~~Midwest~~which became ~~Consent Decree.~~

~~TABLE~~Table OFof ~~CONTENTS~~Contents

~~Please~~effective ~~see~~on ~~Item~~January 1, ~~7—Management’s~~2012, ~~Discussion~~but cap-and-trade ~~Analysis~~compliance ofobligations ~~Financial~~do ~~Condition~~not ~~and~~begin ~~Results~~until ofJanuary 1, ~~Operations—Liquidity~~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 ~~Capital~~by ~~Resources~~about three percent annually from 2015 to 2020. The CARB's first allowance auction is scheduled for ~~further~~November ~~discussion~~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.

~~Information~~ ~~Request under Section 114 of the Clean Air Act.~~ In ~~March~~late ~~2009~~March 2012, weseveral ~~received~~environmental angroups ~~information~~filed ~~request~~a ~~from~~lawsuit ~~the~~in ~~EPA~~California ~~regarding~~state ~~maintenance,~~court ~~repair~~challenging ~~and~~the ~~replacement projects undertaken between January 2000~~ cap-and-trade ~~the~~rule's ~~present~~offset atprovisions, ~~the~~which ~~Danskammer~~allow ~~power~~covered ~~generation~~sources ~~facility. We submitted responses~~ to ~~the~~comply ~~information~~by ~~request~~purchasing inemissions ~~April~~reductions ~~and~~made ~~July~~by ~~2009~~entities ~~and~~not ~~are~~otherwise ~~continuing~~participating toin ~~cooperate with~~ the ~~EPA~~cap-and totrade ~~provide additional information as requested~~program. ~~The~~ CARB ~~information~~also ~~request~~released isother ~~related~~GHG toprogram aproposals ~~nationwide~~in ~~enforcement~~June ~~initiative~~2012 bythat ~~the~~address ~~EPA~~issues ~~targeting~~such ~~electric~~as ~~utilities. The~~auction ~~EPA’s~~administration ~~inquiry~~and ~~may~~revisions ~~lead~~ to ~~claims of CAA violations that could result in an enforcement action,~~ the ~~scope~~mandatory ofreporting ~~which cannot be predicted with confidence at this time, but which could have a material adverse effect on our financial condition, results of operations and cash flows~~rule.

The ~~Clean~~State ~~Water~~of ~~Act~~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.

~~Our~~On ~~water~~January 1, ~~withdrawals~~2009, ~~and~~our ~~wastewater~~assets ~~discharges~~in ~~are~~New ~~permitted~~York ~~under~~and ~~the~~Maine ~~CWA~~became ~~and~~subject ~~analogous~~to a state-driven ~~laws~~GHG emission control program known as RGGI. ~~The~~ ~~cooling~~RGGI ~~water~~was ~~intake~~developed ~~structures~~and atinitially ~~several~~implemented ofby ~~our~~ten ~~facilities~~New ~~are~~England ~~regulated~~and ~~under~~Mid-Atlantic ~~Section~~states ~~316(b)~~to ofreduce ~~the~~CO2 ~~CWA. This~~emissions ~~provision~~from ~~generally~~power ~~directs~~plants. ~~that~~The ~~standards~~participating ~~set~~RGGI ~~for~~states ~~facilities~~implemented ~~require~~rules ~~that~~regulating ~~the~~GHG ~~location,~~emissions ~~design,~~using ~~construction~~a cap-and-trade ~~capacity~~program ofto ~~cooling~~reduce ~~water~~CO2 ~~intake~~emissions ~~structures~~by ~~reflect~~at ~~BTA~~least ~~for~~10 percent ~~minimizing~~of ~~adverse~~2009 ~~environmental~~emission ~~impact~~levels by the year 2018. ~~These~~ ~~standards~~Compliance ~~are~~with ~~developed~~the allowance requirement under the RGGI cap-and-trade ~~implemented~~program ~~for~~can ~~power~~be ~~generating~~achieved ~~facilities~~by ~~through~~reducing ~~NPDES~~emissions, ~~permits~~purchasing or ~~SPDES~~trading ~~permits. Historically~~allowances, ~~standards~~or ~~for~~securing ~~minimizing~~offset ~~adverse~~allowances ~~environmental~~from ~~impacts~~an ofapproved ~~cooling~~offset ~~water~~project. ~~intakes~~While ~~have~~allowances ~~been~~are ~~made~~sold by ~~permitting~~year, ~~agencies~~actual oncompliance is measured across a ~~case~~three-~~by-case~~year ~~basis~~control ~~considering~~period. ~~the~~The ~~best~~first ~~professional~~control ~~judgment~~period ofcovered ~~the~~2009-2011. ~~permitting~~The ~~agency~~second control period covers 2012-2014.

In ~~2004~~December 2011, ~~the~~RGGI ~~EPA~~held ~~issued~~its ~~the~~fourteenth ~~Cooling Water Intake Structures Phase II Rules (the “Phase II Rules”)~~auction, ~~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~~which ~~were~~approximately ~~struck down by the U~~27.S.29 million ~~Court~~allowances ~~of Appeals~~ for the ~~2nd~~first ~~Circuit~~control inperiod ~~Riverkeeper,~~were ~~Inc.~~sold v.at ~~EPA. The~~a ~~Court’s~~clearing ~~decision~~price ~~remanded several provisions~~ of ~~the rules to the EPA for further rulemaking~~$1. ~~Several~~89 ~~parties~~per ~~sought review of the decision before the U~~allowance.S. ~~Supreme~~No ~~Court. In~~bids ~~April~~were ~~2009,~~submitted ~~the~~for ~~U.S.~~allowances ~~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~~a ~~variances~~future ~~from~~control ~~those standards as part of the Phase II Rules~~period.

InRGGI ~~July~~quarterly ~~2007,~~auctions ~~following~~continue ~~remand~~in of2012 ~~the~~but ~~rules~~will byRGGI ~~the~~offer ~~U.S.~~only ~~Court~~2012 ofallocation ~~Appeals~~year allowances in those auctions. On March 14, ~~the~~2012, ~~EPA~~RGGI ~~suspended~~held its ~~Phase~~fifteenth IIauction, ~~Rules~~in ~~and~~which ~~advised~~approximately ~~that~~21.5 ~~permit~~million ~~requirements~~allowances for ~~cooling~~the ~~water~~second ~~intake~~control ~~structures~~period atwere ~~existing~~sold ~~facilities~~at ~~should~~a ~~once~~clearing ~~more~~price beof ~~established~~$1.93 onper aallowance. On ~~case-by-case~~June 6, ~~best~~2012, ~~professional~~RGGI ~~judgment~~held ~~basis~~its ~~until~~sixteenth ~~replacement~~auction, ~~rules~~in ~~are~~which ~~issued~~approximately 20. ~~Under~~9 amillion ~~settlement~~allowances ~~agreement,~~for the ~~EPA~~second ~~will~~control ~~issue~~period ~~proposed~~were ~~cooling~~sold ~~water~~at ~~intake~~a ~~structure~~clearing ~~rules~~price ~~for~~of ~~existing~~$1.93 ~~facilities~~per inallowance. RGGI's ~~March~~next ~~2011~~quarterly ~~and~~auction ~~finalize~~is ~~the~~scheduled ~~rules~~for ~~in July~~ September 2012. ~~The~~ ~~scope~~We ofhave ~~requirements,~~participated ~~timing~~in ~~for~~each ~~compliance~~of ~~and~~ the ~~compliance~~quarterly ~~methodologies~~RGGI ~~that~~auctions ~~will~~(or ~~ultimately~~in besecondary ~~allowed~~markets, byas ~~future~~appropriate) ~~rulemaking~~to ~~may~~secure ~~become~~some ~~more~~allowances ~~restrictive,~~for ~~potentially~~our ~~resulting~~affected ~~in significantly increased costs~~assets.

~~The~~Our ~~environmental~~generating ~~groups~~facilities ~~that participate~~ in ~~our~~New ~~NPDES~~York and ~~SPDES~~Maine ~~permit~~emitted ~~proceedings~~approximately ~~generally~~3.5 million ~~argue~~tons ~~that~~of ~~only~~CO2 ~~closed~~during ~~cycle~~2011. ~~cooling~~For ~~meets~~ the ~~BTA~~first ~~requirement. The~~RGGI ~~issuance~~compliance ~~and~~period ~~renewal~~(2009-2011), ofthe ~~NPDES~~actual orcost ~~SPDES~~of ~~permits~~allowances required for ~~three~~our ofoperations ~~our~~was ~~power~~$35 million. ~~generation~~The ~~facilities~~average ~~(Danskammer,~~clearing ~~Roseton~~price ~~and~~for ~~Moss~~future ~~Landing)~~period ~~have~~allowances ~~been~~sold ~~challenged~~in onall ~~this~~auctions ~~basis~~held to date is $2. ~~The~~33. ~~Danskammer~~We ~~SPDES~~believe ~~permit,~~that ~~which~~the ~~was~~current ~~renewed~~market ~~and~~price ~~issued~~of in$1.96 ~~June 2006,~~is ~~does~~indicative ~~not~~of ~~require~~future ~~installation~~pricing and estimate our cost of aallowances ~~closed~~required ~~cycle~~to ~~cooling~~operate ~~system;~~these ~~however,~~facilities itduring ~~does~~2012 ~~require~~would ~~aquatic~~be ~~organism~~approximately ~~mortality~~$7 million. RGGI ~~reductions~~will ~~resulting~~perform ~~from~~a ~~NYSDEC’s~~comprehensive ~~determination~~program review in 2012, including an evaluation of ~~BTA~~a ~~requirements~~possible ~~under~~additional ~~its~~reduction ~~regulations~~in the CO2 emissions cap. ~~All~~ ~~appeals~~The outcome of ~~this~~that ~~permit~~program ~~have~~review ~~been~~and ~~exhausted. Two~~its ~~permit~~potential ~~challenges~~impact on our affected assets are ~~still~~currently ~~pending~~unknown.

~~● Roseton SPDES Permit —~~ In ~~April~~August ~~2005~~2011, the ~~NYSDEC~~State ~~issued~~of aNew ~~Draft~~York ~~SPDES~~enacted ~~Permit renewal for~~ the ~~Roseton~~"Power ~~plant.~~NY ~~The~~Act ~~permit~~of is2011," ~~opposed~~which byrequires ~~environmental groups challenging~~ the ~~BTA~~NYSDEC ~~determination.~~to Inpromulgate, ~~October~~within ~~2006~~12 months, ~~various~~regulations ~~holdings~~targeting inCO2 ~~the~~emission ~~administrative~~reductions ~~law~~from ~~judge’s~~major ~~ruling~~electric ~~admitting~~generating ~~the~~facilities ~~environmental~~that ~~group~~commenced ~~petitioners~~construction toafter ~~party status and setting forth~~ the ~~issues~~effective todate beof ~~adjudicated in~~ the ~~permit~~regulations. ~~renewal~~In ~~hearing~~June ~~were~~2012, ~~appealed~~NYSDEC toadopted ~~the~~CO2 ~~Commissioner~~emission ofstandards ~~NYSDEC~~for bynew ~~the~~major ~~petitioners,~~electric ~~NYSDEC~~generating ~~staff~~facilities and ~~us.~~for ~~The~~increases ~~permit~~in ~~renewal~~capacity ~~hearing~~of ~~will~~at beleast ~~scheduled~~25 ~~after~~MW ~~the~~at ~~Commissioner~~existing ~~rules~~major onelectric ~~those~~generating ~~appeals~~facilities. The Werule ~~believe~~does ~~that~~not ~~the~~affect ~~petitioners’~~existing ~~claims~~electric ~~lack~~generating ~~merit~~facilities ~~and~~that wedo ~~plan~~not toexpand ~~oppose~~electrical ~~those~~output ~~claims vigorously~~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

~~TABLE~~Table OFof ~~CONTENTS~~Contents

●electric ~~Moss~~power ~~Landing~~generators ~~NPDES~~related ~~Permit~~to —climate change. The ~~California~~Supreme ~~Regional~~Court ~~Water~~was ~~Quality~~equally ~~Control~~divided ~~Board~~by ~~(“Water~~a ~~Board”)~~vote ~~issued~~of an4-4 ~~NPDES~~on ~~permit for~~ the ~~Moss~~question ~~Landing~~of ~~power~~whether ~~generating~~the ~~facility~~plaintiffs inhad ~~2000~~standing ~~that~~to ~~did~~bring ~~not~~the ~~require~~suit ~~closed~~and, ~~cycle~~therefore, ~~cooling.~~affirmed ~~A local environmental group challenged~~ the ~~BTA~~court's ~~determination~~exercise of ~~the permit~~jurisdiction. ~~The~~On ~~Water~~the ~~Board’s~~merits ~~decision was affirmed by~~ the ~~Superior~~ Court inruled ~~2004 and~~ by ~~the~~a ~~Court~~vote of ~~Appeals~~8-0 inthat ~~2007.~~the ~~The~~CAA ~~Supreme Court of California granted review in March 2008. The petitioner’s brief was filed in December 2009. We filed a motion to dismiss~~ and ~~our~~EPA ~~responsive~~action ~~brief~~authorized inby ~~March 2010. The petitioner’s reply brief was filed in May 2010. Our motion to dismiss was denied in June 2010. In July 2010,~~ the ~~California~~CAA ~~Energy~~displace ~~Commission~~any ~~filed~~federal ancommon ~~application~~law ~~for~~right ~~leave~~ to ~~file~~seek aabatement ~~brief in support~~ of ~~our~~CO2 ~~argument~~emissions ~~challenging~~from ~~the~~fossil ~~jurisdiction~~fuel-fired ofpower ~~the~~plants. ~~Superior~~The Court. Indid ~~September~~not ~~2010,~~reach ~~four~~the ~~air~~issue ~~quality control districts filed an application for leave to file a brief in support~~ of ~~jurisdiction~~whether of the ~~Superior~~CAA ~~Court.~~preempts Wesimilar ~~believe that petitioner’s~~ claims ~~lack~~under ~~merit~~state ~~and~~nuisance ~~we plan to continue to oppose those claims vigorously~~law.

~~Due~~In toFebruary ~~the nature of these claims~~2008, anthe ~~adverse~~Native ~~result~~Village ~~in either~~ of ~~these~~Kivalina ~~proceedings~~and ~~could~~the ~~have~~City ~~a material effect on our financial condition, results~~ of ~~operations and cash flows; however~~Kivalina, ~~given~~Alaska ~~the~~initiated ~~numerous~~an ~~variables~~action ~~and~~in ~~factors~~federal ~~involved~~court in ~~calculating~~ the ~~potential~~Northern ~~costs~~District ~~associated~~of ~~with~~California ~~installing~~against aDH ~~closed~~and ~~cycle~~23 ~~cooling~~other ~~system,~~companies ~~any~~in ~~decision~~the toenergy ~~install~~industry. In ~~such~~September a2009, ~~system~~the atcourt ~~any~~dismissed all of ~~our~~the ~~facilities~~plaintiffs' ~~would~~claims bebased ~~made~~ on alack ~~case-by-case~~of ~~basis~~subject ~~considering~~matter ~~all~~jurisdiction ~~relevant~~and ~~factors~~because atplaintiffs ~~such~~lacked ~~time. If~~standing ~~capital expenditures related~~ to ~~cooling~~bring ~~water~~the ~~systems~~suit. The ~~become~~plaintiffs ~~great~~appealed ~~enough~~ to ~~render~~ the ~~operation~~Ninth ofCircuit, ~~the~~which ~~plant~~held ~~uneconomical,~~oral weargument ~~could,~~on atNovember ~~our option~~28, ~~and~~2011. Following ~~subject~~the tofiling ~~any~~of ~~applicable~~the ~~financing~~DH ~~agreements~~Chapter or11 ~~other obligations to make payments as required under applicable leases~~Cases, ~~reduce~~the ~~operations~~Plaintiffs orvoluntarily ~~cease~~dismissed toDH ~~operate~~with ~~that~~prejudice ~~facility~~on ~~and~~February ~~forego~~2, ~~the capital expenditures~~2012.

~~California~~In ~~Water~~October ~~Intake~~2009, ~~Policy. The California State Water Board adopted its Statewide Water Quality Control Policy on~~ the ~~Use~~U.S. Court of ~~Coastal~~Appeals ~~and Estuarine Waters~~ for ~~Power Plant Cooling (~~the ~~“Policy”)~~Fifth atCircuit ~~its~~considered ~~meeting on May 4, 2010, introducing and adopting several amendments making it more stringent than~~ the ~~proposed~~appeal ~~draft~~of ~~Policy~~Comer v. ~~The~~ ~~approved~~Murphy ~~Policy~~Oil ~~requires~~and held that ~~existing~~claims ~~power~~related ~~plants:~~to ~~(i)~~climate ~~reduce~~change ~~their~~by ~~water~~property ~~intake~~owners ~~flow~~along ~~rate~~the toMississippi aGulf ~~level~~Coast ~~commensurate~~against ~~with~~energy ~~that~~companies ~~which~~could ~~can~~ be ~~achieved~~resolved by athe ~~closed~~courts. ~~cycle~~However, ~~cooling~~the ~~system;~~Comer v. orMurphy ~~(ii)~~decision ifwas itsubsequently isvacated. ~~not~~In ~~feasible~~May 2011, ~~to reduce~~ the ~~water~~plaintiffs ~~intake~~re-filed ~~flow~~a ~~rate~~substantially tosimilar ~~this~~complaint ~~level,~~in ~~reduce~~the ~~impingement~~United ~~mortality~~States ~~and~~District ~~entrainment~~Court tofor athe ~~level~~Southern ~~comparable~~District toof ~~that~~Mississippi. In ~~achieved~~March 2012, bythe ~~such~~court adismissed ~~reduced~~the ~~water~~complaint ~~intake~~on ~~flow~~multiple ~~rate~~alternative ~~using~~grounds, ~~operational or structural controls~~concluding, oramong ~~both. The~~other ~~Policy became effective October 1~~things, ~~2010. Compliance~~that ~~with~~ the ~~Policy~~plaintiffs' ~~would~~claims bewere ~~required~~barred ~~at our Morro Bay power generation facility~~ by ~~December~~collateral ~~31,~~estoppel ~~2015~~ and atres ~~our~~judicata, ~~Moss~~the ~~Landing~~plaintiffs ~~power~~lacked ~~generation facility by December 31~~standing, ~~2017. On~~the ~~October~~claims ~~27,~~were ~~2010,~~non-justiciable ~~Dynegy~~political ~~Morro Bay~~questions, ~~LLC~~ and ~~Dynegy~~that ~~Moss~~the ~~Landing,~~federal ~~LLC~~Clean ~~joined~~Air ~~with~~Act ~~other~~displaced ~~California power plant owners in filing a lawsuit in~~ the ~~Sacramento~~federal ~~County~~common ~~Superior~~law ~~Court~~nuisance ~~challenging the Policy~~claims.

OnThe ~~September~~conflict ~~29,~~in ~~2010,~~recent ~~the~~court ~~State~~decisions ~~Water~~illustrates ~~Board proposed to amend~~ the ~~Policy~~unsettled tolaw ~~allow~~related ~~an owner or operator of a power plant with previously installed combined-cycle power generating units~~ to ~~continue~~claims tobased ~~use~~on ~~once-through cooling at combined-cycle units until~~ the ~~unit~~effects ~~reaches the end~~ of ~~its~~climate ~~useful life under certain circumstances~~change. A ~~hearing~~The todecisions ~~receive~~affirming ~~comment~~the ~~and~~jurisdiction toof ~~take action on~~ the ~~proposed~~courts ~~amendment~~and ~~was held on December 14, 2010; however,~~ the ~~State~~standing ~~Water~~of ~~Board declined to approve~~ the ~~amendment. We~~plaintiffs ~~are continuing~~ to ~~review~~bring ~~the~~these ~~potential~~claims ~~impact~~could ofresult ~~the~~in ~~Policy~~an onincrease ~~our~~in ~~affected~~similar ~~power~~lawsuits ~~generation~~and ~~facilities~~associated ~~and~~expenditures ~~our~~by ~~compliance~~companies ~~options~~like ours.

ItCarbon ~~may~~Initiatives. We ~~not~~participate bein ~~possible~~several toprograms ~~meet~~that ~~the~~partially ~~requirements~~offset ofor ~~the~~mitigate ~~Policy~~our inGHG ~~its~~emissions. ~~final~~In ~~form~~the ~~without~~lower ~~installing~~Mississippi ~~closed~~River ~~cycle~~Valley, ~~cooling~~we ~~systems. Given~~have partnered with the ~~numerous~~U.S. ~~variables~~Fish & ~~and~~Wildlife ~~factors~~Service ~~involved~~to inrestore ~~calculating~~more ~~the~~than ~~potential~~45,000 ~~costs~~acres of ~~closed-~~hardwood ~~cycle~~forests ~~cooling~~by ~~systems,~~planting ~~any~~more ~~decision~~than to8 million ~~install~~bottomland ~~such~~hardwood aseedlings. ~~system~~In ~~would~~Illinois, bewe ~~made~~are onfunding aprairie, ~~case-by-case~~bottomland ~~basis~~hardwood ~~considering~~and ~~all~~savannah ~~relevant~~restoration ~~factors~~projects atin partnership with the ~~time~~Illinois Conservation Foundation. If ~~capital~~We ~~expenditure~~also ~~requirements~~have ~~related~~programs to ~~cooling~~reuse ~~water~~CCR ~~systems~~produced ~~become~~at ~~great~~our ~~enough~~coal-fired togeneration ~~render~~units ~~the~~through ~~continued~~agreements ~~operation~~with ofcement amanufacturers ~~particular~~that ~~plant~~incorporate ~~uneconomical,~~the wematerial ~~could~~into atcement ~~our option~~products, ~~and~~helping ~~subject~~ to ~~any applicable financing agreements and other obligations,~~ reduce ~~operations~~CO2 oremissions ~~cease~~from ~~to operate~~ the ~~plant~~cement ~~and~~manufacturing ~~forego such capital expenditures~~process.

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New York Water Intake Policy. On March 4, 2010, the NYSDEC issued a draft policy (the “NYSDEC Policy”) on “BTA for Cooling Water Intake Structures.” The NYSDEC Policy, which was subject to comment until July 8, 2010, would establish closed cycle cooling or its equivalent as the minimum performance goal for existing power plants. If NYSDEC determines that closed cycle cooling is not available for a facility, the NYSDEC Policy would establish a performance goal of 90 percent or greater reduction in impingement mortality and entrainment from that which could be achieved by closed cycle cooling. The NYSDEC Policy would exempt certain power generation facilities that operate at very low capacity. We are continuing to review the potential impact of the NYSDEC Policy, if adopted, on our subject power generation facilities.

Given the numerous variables and factors involved in calculating the potential costs associated with closed cycle cooling, any decision to install such a system at any of our facilities, should they be required, would be made on a case-by-case basis considering all relevant factors at such time. If capital expenditures related to cooling water systems become great enough to render the operation of the plant uneconomical, we could, at our option, and subject to any applicable financing agreements or other obligations, reduce operations or cease to operate such facility and forego these capital expenditures.

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. In addition, under a proposed consent decree, the EPA would be required to propose revisions to the Effluent Guidelines for steam electric units by July 23, 2012 and to take final action on the proposal by January 31, 2014. Significant changes in these requirements could impact discharge limits and could require us to spend significant environmental capital to install additional water treatment equipment at our facilities.

Coal Combustion Residuals

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

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

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

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

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

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 ~~power~~Coal, ~~generation~~Gas ~~businesses~~and inDNE ~~the~~power ~~Midwest,~~generation ~~West~~businesses ~~and Northeast~~ 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 ~~these~~the ~~businesses~~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 ~~and to support the construction and operation of renewable-fueled power generation facilities~~. For example, regulatory requirements for load-serving entities to acquire a percentage of their energy from renewable-fueled facilities will potentially ~~reduce the demand for energy from coal-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.~~

2422

~~TABLE~~Table OFof ~~CONTENTS~~Contents

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, ~~2010~~2011, approximately 3036 percent, 17 percent, 1522 percent and 13 11 percent of our consolidated revenues were derived from transactions with MISO, NYISO, PJM and ~~PJM~~NGX, respectively. For the year ended December 31, ~~2009~~2010, approximately 19 30 percent, 12 15 percent and 11 13 percent of our consolidated revenues were derived from transactions with MISO, NYISO and PJM, respectively. For the year ended December 31, ~~2008~~2009, approximately 2519 percent, 12 percent and 11 percent of our consolidated revenues were derived from transactions with MISO, NYISO and ~~NYISO~~PJM, respectively. No other customer accounted for more than 10 percent of our consolidated revenues during ~~2010~~2011, ~~2009~~2010 or ~~2008~~2009.

EMPLOYEES

At December 31, ~~2010~~2011, we and Dynegy had approximately ~~419~~274 employees at our corporate headquarters and approximately ~~1,235~~ 988 employees at our facilities, including field-based administrative employees. In ~~February~~Approximately ~~2011,~~639 weemployees ~~reduced~~at our ~~workforce~~operating byfacilities ~~approximately~~are ~~135~~subject ~~positions~~to ascollective ~~part~~bargaining ofagreements ~~our~~with ~~cost~~various ~~savings programs~~unions. As Approximately 770 of ~~March~~our 3employees, ~~2011,~~including wethose ~~had~~located ~~approximately~~in ~~334 employees at~~ our corporate headquarters, ~~and~~our ~~approximately~~natural 1gas facilities,~~185 employees~~ atand ~~our~~Dynegy's coal facilities~~. Approximately~~ ~~748~~that ~~employees~~we atacquired ~~Dynegy-operated~~on ~~facilities~~June 5, 2012, are ~~subject~~employed toby ~~collective~~our ~~bargaining~~subsidiary, ~~agreements~~and ~~with~~approximately ~~various~~147 ~~unions~~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:

●• ~~beliefs~~our ~~and~~ability ~~assumptions~~to ~~regarding~~consummate ~~our~~one ~~ability~~or more plans of reorganization with respect to ~~continue~~the asChapter a11 ~~going~~Cases, ~~concern~~and to consummate all the transactions contemplated by the Settlement Agreement and Plan Support Agreement;

●• ~~the impact of the turnover in~~ our ~~executive team and Dynegy’s Board of Directors on our~~ ability to ~~execute~~consummate ~~our~~the ~~business plan~~Merger;

●• ~~beliefs~~our ~~and~~ability ~~assumptions relating~~ to ~~our~~sell ~~liquidity,~~the ~~available~~Roseton ~~borrowing capacity~~ and ~~capital~~Danskammer ~~resources~~power ~~generally,~~generation ~~including~~facilities ~~the extent~~ to ~~which~~one ~~such liquidity could be affected by poor economic and financial market conditions~~ or ~~new~~more ~~regulations~~third ~~and~~parties ~~any~~as ~~resulting~~set ~~impacts~~forth onin ~~financial~~the ~~institutions~~Settlement ~~and other current and potential counterparties~~Agreement;

●• ~~the~~beliefs ~~outcome~~and ofassumptions ~~any~~relating ~~legal~~to ~~proceedings~~our ~~that~~liquidity, ~~may~~available borrowing capacity and capital resources generally, including the extent to which such liquidity could be ~~instituted~~affected ~~against~~by ~~Dynegy~~poor economic and/ financial market conditions or ~~others~~new ~~relating~~regulations toand ~~the~~any ~~Blackstone~~resulting ~~Merger~~impacts ~~Agreement~~on financial institutions and ~~Icahn~~other ~~Merger~~current ~~Agreement~~and potential counterparties;

●• ~~diversion~~the anticipated effectiveness of ~~management’s~~the ~~attention~~overall ~~from~~restructuring ~~ongoing~~activities ~~business~~and ~~concerns~~any additional strategies to address our liquidity and our capital resources including accessing the capital markets;

●• ~~limitations~~beliefs onand assumptions regarding our ability to ~~utilize~~continue ~~Dynegy’s~~as ~~previously~~a ~~incurred~~going ~~federal net operating losses or alternative minimum tax credits~~concern;

●• ~~the~~limitations ~~amount~~on ofour ~~the~~ability ~~costs,~~to ~~fees,~~utilize ~~expenses,~~previously ~~and~~incurred ~~other~~federal ~~charges~~net ~~related~~operating tolosses ~~the~~or ~~Blackstone~~alternative ~~Merger~~minimum ~~Agreement~~tax ~~and the Icahn Merger Agreement~~credits;

●• expectations regarding our compliance with the ~~timing~~DMG and ~~anticipated~~DPC ~~benefits~~Credit toAgreements, beincluding ~~achieved~~collateral ~~through~~demands, ~~our~~interest ~~company-wide~~expense ~~cost~~and ~~savings~~other ~~programs~~payments;

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

~~TABLE~~• OFexpectations ~~CONTENTS~~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;

●• ~~expectations regarding environmental matters~~beliefs, ~~including~~assumptions ~~costs of compliance, availability~~ and ~~adequacy~~projections ofregarding ~~emission credits, and~~ the ~~impact~~demand offor ~~ongoing~~power, ~~proceedings~~generation volumes and ~~potential~~commodity ~~regulations or changes to current regulations~~pricing, including ~~those~~natural ~~relating~~gas toprices ~~climate~~and ~~change,~~the ~~air~~impact ~~emissions,~~on ~~cooling~~such ~~water~~prices ~~intake~~from ~~structures,~~shale ~~coal~~gas ~~combustion~~proliferation ~~byproducts,~~ and ~~other~~the ~~laws~~timing ~~and~~of ~~regulations~~a torecovery ~~which~~in wenatural ~~are,~~gas ~~or could become~~prices, ~~subject~~if any;

●• ~~beliefs~~sufficiency of, ~~assumptions~~access to and ~~projections~~costs ~~regarding~~associated ~~the~~with ~~overall economy~~coal, ~~demand~~fuel ~~for~~oil ~~power, generation volumes~~ and ~~commodity pricing , including~~ natural gas ~~prices~~inventories and ~~the~~transportation ~~impact on such prices from shale gas proliferation and the timing of a recovery in natural gas prices, if any~~thereof;

●• ~~sufficiency~~beliefs ofand assumptions about market competition, ~~access~~generation tocapacity and ~~costs~~regional ~~associated~~supply ~~with~~and ~~coal~~demand characteristics of the wholesale power generation market, ~~fuel~~including ~~oil~~the ~~and~~anticipation ~~natural~~of ~~gas~~higher ~~inventories~~market ~~and~~pricing ~~transportation~~over ~~thereof~~the longer term;

●• ~~beliefs~~the ~~and~~effectiveness ~~assumptions~~of ~~about~~our ~~market~~strategies ~~competition,~~to ~~generation~~capture ~~capacity~~opportunities ~~and~~presented ~~regional~~by ~~supply~~changes ~~and~~in ~~demand~~commodity ~~characteristics~~prices ofand ~~the~~to ~~wholesale~~manage ~~power~~our ~~generation~~exposure ~~market,~~to ~~including~~energy ~~the~~price ~~anticipation of higher market pricing over the longer term~~volatility;

●• ~~the~~beliefs ~~possibility~~and ofassumptions ~~further~~about ~~consolidation~~weather ~~in the power generation industry~~ and ~~the~~general ~~impact~~economic ~~of any such activity on Dynegy~~conditions;

~~● beliefs and assumptions regarding our ability to enhance or protect long-term value for stockholders;~~24

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

●• ~~beliefs~~projected ~~and~~operating ~~assumptions~~or ~~about~~financial ~~weather~~results, ~~and~~including ~~general~~anticipated ~~economic~~cash ~~conditions~~flows from operations, revenues and profitability;

●• ~~projected~~our ~~operating~~focus oron ~~financial~~safety ~~results,~~and ~~including~~our ~~anticipated~~ability ~~cash~~to ~~flows~~efficiently ~~from~~operate ~~operations,~~our ~~revenues~~assets so as to capture revenue generating opportunities and ~~profitability~~operating margins;

●• ~~expectations~~beliefs ~~regarding~~about ~~our~~the ~~revolver~~outcome ~~capacity~~of legal, ~~credit~~administrative, ~~facility~~legislative ~~compliance,~~and ~~financial~~regulatory ~~covenants~~matters, ~~collateral~~including ~~demands,~~the ~~capital~~impact ~~expenditures,~~of ~~interest~~final ~~expense~~rules ~~and~~regarding ~~other~~derivatives ~~payments~~to be issued by the CFTC under the Dodd-Frank Act; and

●• ~~beliefs or~~ expectations regarding ~~the~~performance ~~potential~~standards ~~amendment~~and orestimates ~~refinancing~~regarding ofcapital ~~our~~and ~~Credit~~maintenance ~~Facility~~expenditures, orincluding the ~~timing~~Consent ~~thereof;~~Decree and its associated costs and performance standards

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

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

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

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth below.

FACTORS THAT MAY AFFECT FUTURE RESULTS

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

WeThe ~~have~~Debtor ~~received~~Entities ~~audit~~filed ~~reports~~voluntary onpetitions ~~our~~for ~~consolidated~~relief ~~financial~~under ~~statements~~Chapter 11 ~~that~~of ~~express~~the ~~uncertainty~~U.S. ~~about~~Bankruptcy ~~our~~Code ~~ability~~and are subject to ~~continue~~the asrisks aand ~~going~~uncertainties ~~concern~~associated with bankruptcy cases.

~~Our~~The ~~independent~~Debtor ~~registered~~Entities ~~public~~filed ~~accounting~~voluntary ~~firm~~petitions ~~has~~for ~~included~~relief anunder ~~explanatory~~Chapter 11 ~~paragraph~~of inthe ~~their~~Bankruptcy ~~reports on our December 31, 2010, 2009 and 2008 consolidated financial statements regarding doubt as to our ability to continue as a going concern~~Code. ~~This~~For ~~may~~the ~~have~~duration aof ~~negative impact on~~ the ~~trading~~Debtor ~~price~~Entities' ofChapter 11 ~~Dynegy's~~Cases, ~~common~~our ~~stock~~business and ~~may~~operations ~~make~~will itbe ~~more~~subject ~~difficult~~ to ~~amend~~various orrisks, ~~replace~~including ~~our~~but ~~current~~not ~~Credit~~limited ~~Facility~~to, orthe ~~to seek additional sources of liquidity.~~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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Wepercent ~~have~~shareholders ~~significant~~at ~~debt~~any ~~that~~time ~~could~~during ~~negatively~~the ~~impact~~applicable ~~our~~testing ~~business~~period (an “Ownership Change”).

WeNotwithstanding ~~have~~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 ~~have~~exist after such Ownership Change and, as a ~~significant~~result ~~amount~~of COD Income resulting on the Effective Date, such tax attributes held at DH will be reduced or eliminated prior to the reduction of ~~debt~~tax ~~outstanding~~attributes held by entities other than DH or produced after the Ownership Change. As Because the use of ~~December~~these ~~31,~~tax ~~2010~~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, wethe ~~had~~impact ~~total~~of ~~consolidated~~a ~~debt~~further Ownership Change on the Effective Date should not have a significant impact on Dynegy's (and our) use of ~~approximately~~these $4tax attributes.8 ~~billion~~Dynegy (~~including~~and ~~debt~~we) ~~outstanding~~produced ~~under~~additional ~~our~~NOLs ~~Credit~~after ~~Facility)~~the Ownership Change in the second quarter of 2012 and prior to the Effective Date. ~~Our~~ ~~significant~~The ~~level~~use of ~~debt~~these ~~could:~~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 ~~make~~and itDMG ~~difficult~~receive tosignificant ~~satisfy~~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 ~~obligations~~condition, ~~including~~and ~~debt~~results ~~service~~of ~~requirements;~~operations.

●The ~~limit~~Gas and Coal segments receive significant services from certain of our ~~ability~~subsidiaries, toincluding, ~~obtain~~among ~~additional~~others, ~~financing~~cash management and energy management services. If the provision of these services were to ~~operate~~be delayed, interrupted or otherwise halted for any reason, including if any of our ~~business;~~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 ~~limit~~Related ~~our~~to ~~financial~~Our ~~flexibility~~Financial inStructure, ~~planning~~Level ~~for~~of Indebtedness and ~~reacting~~Access to ~~business~~Capital ~~and~~Markets ~~industry changes;~~

●We ~~impact~~have ~~the~~significant ~~evaluation~~indebtedness ofthat ~~our~~could ~~creditworthiness~~adversely byaffect ~~counterparties~~our tofinancial ~~commercial~~health ~~agreements~~ and ~~affect~~prevent ~~their willingness to transact with~~ us ~~and/or~~from ~~the~~fulfilling ~~level~~certain of ~~collateral~~our wefinancial ~~are required to post under such agreements;~~obligations.

●We ~~place~~have usand atwill continue to have a ~~competitive~~significant ~~disadvantage~~amount ~~compared~~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 ~~less~~compromise ~~leveraged~~in ~~companies;~~the bankruptcy process and $1.1 billion outstanding under the DPC Credit Agreement). Such amount of indebtedness could:

●• ~~increase~~make ~~our~~it ~~vulnerability~~difficult to ~~general~~satisfy ~~adverse~~our ~~economic~~financial ~~and industry conditions~~obligations, including ~~changes~~debt inservice ~~interest rates and volatility in commodity prices~~requirements; ~~and~~

●• ~~require~~limit ~~us to dedicate a substantial portion of~~ our ~~cash~~ability ~~flows~~ to ~~principal~~obtain ~~and~~additional ~~interest~~financing ~~payments~~in onthe ~~our~~future ~~debt,~~for ~~thereby~~working ~~reducing~~capital, ~~the~~capital ~~availability~~expenditures, ofacquisitions ~~our~~or ~~cash flow for~~ other purposes ~~including~~on ~~our~~acceptable ~~operations~~terms, ~~capital~~on ~~expenditures~~a ~~and~~timely ~~future~~basis ~~business~~or ~~opportunities.~~at all;

~~Furthermore,~~• welimit ~~may~~our ~~incur~~financial orflexibility ~~assume additional debt~~ in ~~the~~planning ~~future. If~~for, ~~new~~or ~~debt~~reacting isto, ~~added~~changes toin our ~~current~~business ~~debt levels~~ and ~~those of our subsidiaries,~~ the ~~related~~industry ~~risks~~in ~~that~~which we ~~and they face could increase significantly.~~operate;

~~Our~~• ~~financing~~impact ~~agreements~~the ~~governing~~evaluation of our ~~debt~~creditworthiness ~~obligations~~by ~~require~~counterparties us to ~~satisfy~~commercial ~~specific~~agreements, ~~financial~~both ~~covenants. Using~~for ~~the~~hedging ~~latest~~as ~~available~~well ~~forward~~as ~~commodity~~operating ~~price curves and considering our current derivative~~ contracts, wesuch ~~project~~as ~~that~~for itfuel isand ~~likely~~transportation, ~~that~~and weaffect ~~will~~their ~~not~~willingness ~~be able~~ to ~~comply~~transact with ~~our~~us ~~EBITDA to Consolidated Interest Expense covenant, particularly in the third~~ and/or ~~fourth quarters of 2011. Our failure to comply with~~ the ~~financial~~level ~~covenants would have a material adverse impact on our business, financial condition, results~~ of ~~operations~~collateral ~~and cash flows. If~~ we are ~~unable~~required to ~~successfully~~post ~~execute our plan to amend or replace our Credit Facility or otherwise obtain additional sources of liquidity, it may be necessary for us to seek protection from creditors~~ under ~~Chapter~~such ~~11 of the U.S. Bankruptcy Code, or an involuntary petition for bankruptcy may be filed against us.~~agreements;

~~Our~~• ~~financing~~place ~~agreements, including the Credit Facility, require~~ us toat ~~meet specific financial covenants both as~~ a ~~matter~~competitive ofdisadvantage ~~course~~compared ~~and as a precondition~~ to ~~the~~our ~~incurrence~~competitors ofthat ~~additional~~have ~~debt~~less and to the making of restricted payments or asset sales, among other things. Our obligations relating to ongoing financial covenants include the maintenance of specified financial ratios regarding Secured Debt to EBITDA and EBITDA to Consolidated Interest Expense (as each such term is defined in the Credit Facility) (together, the “Maintenance Covenants”). The financial covenants set forth as a condition to the events described above include the demonstration, on a pro forma basis, of a specified ratio of Total Indebtedness to EBITDA (as each such term is defined in the Credit Facility). Each of these three ratios becomes more restrictive over the course of 2011 and into 2012.debt;

As• ofincrease ~~December 31, 2010, we were in compliance with the Maintenance Covenants. Using the latest available forward commodity price curves and considering~~ our ~~current~~vulnerability ~~derivative contracts, we project that it is likely that we will not be able~~ to ~~comply~~general ~~with~~adverse ~~our~~economic ~~EBITDA to Consolidated Interest Expense covenant, as currently set forth in our Credit Facility, particularly in the third~~ and ~~fourth~~industry ~~quarters of 2011~~conditions, ~~which could result in an event of default causing our indebtedness thereunder (~~and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. If we are unable to cure or obtain a waiver for any such default, or are unable to obtain replacement financing or otherwise pay off such amounts, and our lenders accelerate the payment of such indebtedness, our lenders would be entitled to foreclose on, and acquire control of substantially all of our assets, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.


•	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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In• ~~light of our likely non-compliance, we are attempting to amend or replace our existing Credit Facility. If we are able to amend our Credit Facility or~~ enter into arelated ~~new~~party facility, we expect that capacity of any such facility to be less than the current capacity of $1.8 billion and to be at a higher cost, which reduced capacity and increased costs could have a material adverse effect on our ability to successfully run our business. We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans. If we are unable to successfully execute our plan to amend or replace our Credit Facility or otherwise obtain additional sources of liquidity, it may be necessary for us to seek protection from creditors under Chapter 11 of the U.S. Bankruptcy Code, or an involuntary petition for bankruptcy may be filed against us.transactions;

An• ~~event~~create ~~of loss and~~ certain ~~other events relating to our Dynegy Northeast Generation facilities could trigger a substantial obligation that would be difficult for us to satisfy.~~liens;

We• ~~acquired~~enter ~~the DNE power generating facilities in January 2001 for $950 million. In May 2001, we entered~~ into ~~an asset-backed~~ sale~~-leaseback~~ transaction relating to these facilities to provide us with long-term acquisition financing. In this transaction, we sold four of the six generating units comprising these facilities for approximately $920 million to Danskammer OL LLC and ~~Roseton~~leaseback OL LLC, and we concurrently agreed to lease them back from these entities. Obligations under these leases are guaranteed by DHI. We have no option to purchase the leased facilities at Roseton or Danskammer at the end of their respective lease terms, which end in 2035 and 2031, respectively. If one or more of the leases were to be terminated prior to the end of its term because of an event of loss (such as substantial damage to a facility or a condemnation or similar governmental taking or action), because it becomes illegal for us to comply with the lease, or because the facility becomes economically or technologically obsolete, we would be required to make a termination payment in an amount sufficient to compensate the lessor for termination of the lease, including redeeming the pass-through trust certificates related to the unit or facility for which the lease is terminated plus, in the case of an obsolescence termination (other than as a result of a change in law or the requirement by a governmental entity of significant capital improvements), a make whole premium for the remaining term of the pass through certificates. As of December 31, 2010, the termination payment would be approximately $816 million and the make whole premium would be approximately $109 million for all of our DNE facilities. It could be difficult for us to raise sufficient funds to make this termination payment if a termination of this type were to occur with respect to the DNE facilities, resulting in a material adverse effect on our financial condition, results of operations and cash flows.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.

~~As previously described, we will require additional capital in the near-term.~~ Because of our non-investment grade credit rating, the ~~going~~Chapter 11 ~~concern~~Cases ~~emphasis~~of ~~paragraph in our most recent audit report,~~ the ~~recent~~Debtor ~~changes in senior management and Dynegy’s Board of Directors~~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 ~~debt and~~ credit agreements;

●• ~~investor~~the ~~confidence~~outcome inof usthe ~~and~~bankruptcy ~~the~~proceedings ~~regional~~for ~~wholesale~~the ~~power~~Debtor ~~markets~~Entities;

●• ~~our~~investor ~~financial~~confidence ~~performance~~in us and the ~~financial~~regional ~~performance~~wholesale ofpower ~~our subsidiaries~~markets;

●• our ~~levels~~financial performance and the financial performance of ~~debt~~our subsidiaries;

●• our ~~requirements~~levels ~~for~~of ~~posting collateral under various commercial agreements~~debt;

●• our ~~credit~~requirements ~~ratings~~for posting collateral under various commercial agreements;

28• our credit ratings;

~~TABLE~~• OFour ~~CONTENTS~~cash flow;

●• our ~~cash~~long-term ~~flow~~business prospects; and

●• ~~our~~general ~~long-term~~economic ~~business~~and ~~prospects;~~capital market conditions, including the timing and magnitude of any market recovery.

● 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 ~~ratings~~rating ~~are~~is currently below investment grade, and onwe ~~March 1, 2011, Standard & Poor's downgraded our corporate family ratings to "CCC" from "B-". 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 our business. Various commodity trading counterparties may 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. In connection with the most recent downgrade by Standard & Poor's, certain of our counterparties have requested collateral support. Other counterparties may require further collateral support in the future.

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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.

We conduct virtually all of our operations through our subsidiaries and may be limited in our ability to access funds from these subsidiaries to service our debt.

We conduct virtually all of our operations through our subsidiaries and, therefore, depend upon dividends and other intercompany transfers of funds from our subsidiaries to meet our debt service and other obligations. In addition, the ability of our subsidiaries to pay dividends and make other payments to us may be restricted by, among other things, applicable corporate and other laws, potentially adverse tax consequences and agreements of our subsidiaries. If we are unable to access the cash flow of our subsidiaries, we may have difficulty meeting our debt obligations.

If we are unable to successfully execute our plans to amend or replace our Credit Facility or otherwise obtain alternative sources of liquidity, we may seek protection pursuant to a voluntary bankruptcy filing under Chapter 11 of the U.S. Bankruptcy Code, or an involuntary petition for bankruptcy may be filed against us.

As described in Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources, using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with the covenant regarding the EBITDA to Consolidated Interest Expense ratio contained in our Credit Facility, particularly in the third and fourth quarters 2011, which could result in an event of default causing our indebtedness thereunder (and any other indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions) to potentially become immediately due and payable. In light of our likely non-compliance, we are attempting to amend or replace our existing Credit Facility. We may also seek additional sources of liquidity in an effort to secure sufficient cash to meet our operating needs. These additional sources of liquidity could include asset sales, public or private issuances of debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. However, we cannot provide any assurances that we will be successful in accomplishing any of these plans. If we are unsuccessful, we may consider or pursue various forms of negotiated restructurings of our debt obligations and/or asset sales under court supervision pursuant to a voluntary bankruptcy filing under Chapter 11 of the U.S. Bankruptcy Code. In addition, under certain circumstances our creditors may file an involuntary petition for bankruptcy against us.

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If we file for bankruptcy protection, our business and operations will be subject to certain risks.

A bankruptcy filing by or against Dynegy, DHI and/or certain of our subsidiaries (each referred to as a “filer”) would subject our business and operations to various risks, including but not limited to, the following:

● A bankruptcy filing by or against a filer may adversely affect our business prospects, including our ability to continue to obtain and maintain the contracts necessary to operate our business on competitive terms;

● We may be unable to retain and motivate key executives and employees through the process of reorganization, and we may have difficulty attracting new employees;

● There can be no assurance as to our ability to maintain or obtain sufficient financing sources for operations or to fund any reorganization plan and meet future obligations;

● There can be no assurance that we will be able to successfully develop, prosecute, confirm and consummate one or more plans of reorganization that are acceptable to the bankruptcy court and our creditors, equity holders and other parties in interest;

● Our ability to use our federal NOLs and AMT credits, which totaled $222 million and $271 million, respectively, at December 31, 2010 could be limited or modified as a result of bankruptcy proceedings; and

● The value of Dynegy’s common stock could be reduced to zero as result of a bankruptcy filing.

Risks Related to the Operation of Our Business

The recent resignations of certain members of our executive team and the decision of Dynegy's board of directors to not stand for reelection at Dynegy's upcoming annual meeting could have a material adverse impact on our business, financial condition and results of operations.

On February 21, 2011, we announced that Bruce A. Williamson, the Chairman of Dynegy’s Board of Directors and our President and Chief Executive Officer, and Holli C. Nichols, our Executive Vice President and Chief Financial Officer, were resigning from their executive positions effective March 11, 2011. Mr. Williamson resigned as a director and Chairman effective February 21, 2011. Also, on February 21, 2011, Dynegy’s then-remaining directors each informed Dynegy that he or she does not currently intend to stand for reelection as a director of Dynegy at Dynegy’s upcoming annual meeting of stockholders. The loss of these executives and directors and their skills, experience and industry knowledge could have a material adverse impact on our business, financial condition and results of operations. Furthermore, our inability to attract, motivate and retain other key employees, including new senior executives, and to replace the directors that will not stand for reelection at the annual meeting with qualified and knowledgeable directors, could have a negative effect on our business, financial condition, results of operations and cash flows.

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

●• ~~regulatory constraints on pricing (current or future) or~~ the ~~functioning~~existence ~~of the energy trading markets~~ and ~~energy~~effectiveness ~~trading~~of ~~generally~~demand-side management;

●• ~~the~~conservation ~~proliferation~~efforts ofand ~~advanced~~the ~~shale~~extent ~~gas~~to ~~drilling~~which ~~increasing~~they ~~domestic~~impact ~~natural~~electricity ~~gas supplies~~demand;

●• ~~fuel~~regulatory ~~price~~constraints ~~volatility;~~on pricing (current or future) or the functioning of the energy trading markets and energy trading generally;

●• ~~increased~~the ~~competition~~proliferation orof ~~price~~advanced ~~pressure~~shale ~~driven~~gas bydrilling ~~generation~~increasing ~~from~~domestic ~~renewable~~natural ~~sources.~~gas supplies;

~~Many~~• offuel ~~our~~price ~~facilities~~volatility; operate as “merchant” facilities without long-term power sales agreements. Consequently, we cannot be sure 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 decreased 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 power commodity 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,~~competition ~~and~~or ~~our~~price ~~financial~~pressure ~~condition,~~driven 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 usgeneration infrom ~~the~~renewable ~~next several years~~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 ~~tenors~~types. In doing so, we attempt to balance a desire for greater predictability of earnings and cash flows in the short- and medium-~~term~~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 reliability of the people and 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-term, 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.

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Wereliability 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 ~~exposed~~unable to transact in the ~~risk~~short- and medium-terms, our financial condition, results of ~~fuel~~operations and ~~fuel~~cash ~~transportation~~flows ~~cost~~will ~~increases~~be subject to significant uncertainty and ~~interruptions~~volatility. inAlternatively, ~~fuel~~significant ~~supplies~~contract ~~because~~execution ~~some~~for ofany ~~our~~such ~~facilities~~period domay ~~not~~precede ~~have~~a ~~long~~run-~~term~~up ~~coal~~in commodity prices, ~~natural~~resulting ~~gas~~in orlost ~~fuel~~upside ~~oil~~opportunities ~~supply~~and ~~agreements~~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 ~~our ability to procure~~ coal at prices weand ~~consider~~coal ~~reasonable~~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. In ~~the~~We ~~Midwest,~~have ~~our~~entered into term contracts for PRB coal, ~~requirements~~which ~~are~~we ~~approximately~~use 96for ~~percent~~our ~~contracted~~coal facilities in ~~2011~~the ~~and~~Midwest. 99Our ~~percent~~expected coal requirements are fully contracted ~~for~~and priced in 2012. ~~All~~ Our forecast coal requirements for 2013 are 9685 percent ~~priced~~contracted ~~through 2011~~ and 6953 percent ~~are~~ priced ~~for 2012~~. ~~Forecasted~~ The ~~coal~~contracted ~~requirements~~volumes ~~that~~remaining are ~~currently~~ unpriced but are subject to a price collar structure. Our ~~Midwest~~ coal transportation requirements are 100 percent contracted and priced through 2013~~. We~~ ~~have~~when ~~entered~~our ~~into~~current ~~term~~ contracts ~~for~~expire. In ~~South~~August ~~American coal~~2012, ~~which~~ we ~~use~~executed ~~for~~new ~~our GEN-NE~~ coal ~~facility,~~transportation ~~and~~contracts ~~for PRB coal,~~ which wetake ~~use~~effect ~~for~~when our ~~GEN-MW~~current ~~coal~~contracts ~~facilities~~expire. We These ~~cannot~~new ~~assure~~long-term ~~you~~contracts ~~that~~also wecover ~~will~~100 bepercent ~~able~~of ~~to renew~~ our coal ~~procurement and~~ transportation ~~contracts~~requirements. We ~~when~~continue ~~they terminate on terms that are favorable~~ to usexplore orvarious atalternative ~~all. Further,~~contractual ~~our~~commitments and ~~our~~financial ~~suppliers’~~options, ~~ability~~as towell ~~procure~~as ~~South~~facility ~~American~~modifications, ~~coal is subject~~ to ~~local~~ensure ~~political~~stable and ~~other~~competitive ~~factors~~fuel ~~that~~supplies ~~could~~and ~~have~~to amitigate ~~negative~~further ~~impact on our coal deliveries regardless of our contract situation. Permit limitations that restrict the sulfur content of coal used at our coal facilities limit our options for coal fuel~~ supply, ~~creating~~risks ~~risk~~ for usnear- inand ~~terms~~long-term ~~of our ability to procure~~ coal ~~for periods and at prices we believe are firm and favorable~~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 ~~construct,~~ 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 ~~consent~~the ~~decrees~~Consent Decree or other governmental orders.

32With 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.

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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 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 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.

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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.

~~We have numerous competitors, and additional competitors may enter the industry.~~ 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, ~~which~~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 ~~new or~~ maturing RTOs and similar 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.

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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 ~~Midwest~~ Consent Decree may be materially adversely impacted by our future operating cash flows or unforeseen labor, ~~material and equipment~~ costs.

As a result of the ~~Midwest~~ Consent Decree, we are required to not operate certain of our ~~most~~coal-fired ~~profitable~~ 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 ~~Midwest~~ Consent Decree and anticipate ~~incurring~~the ~~additional~~remainder ~~significant~~of ~~costs over~~ the ~~course~~equipment ofinstallations ~~the~~to ~~next~~incur ~~three~~additional ~~years~~significant costs. Further, we are exposed to the risk of ~~substantial~~ price increases in the costs of ~~materials,~~ labor and ~~equipment~~to ~~used in~~ the ~~construction of emission control equipment. We are further exposed to~~ risk in 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. If the costs of these capital expenditures become great enough to render the operation of the facility uneconomical, we could, at our option, cease to operate the facility or facilities and forego these capital expenditures without incurring any further obligations under the Midwest Consent Decree. Further, our production may be affected if we fail to meet certain performance standards under the ~~Midwest~~ Consent Decree.

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We may pursue dispositions or business combinations that could fail or present unanticipated problems for our business in the future, which would adversely affect our ability to realize the anticipated benefits of those transactions.

We may seek to enter into transactions that may include disposing of assets or combining with other businesses. We may not be able to identify suitable transaction opportunities or finance and complete any particular transaction successfully. Furthermore, transactions involve a number of risks and challenges, including:

● diversion of our management’s attention;

● the ability to obtain required regulatory and other approvals;

● the need to integrate operations;

● potential loss of key employees;

● difficulty in evaluating the power assets, operating costs, infrastructure requirements, environmental and other liabilities and other factors beyond our control;

● potential lack of operating experience in new geographic/power markets or with different fuel sources;

● an increase in our expenses and working capital requirements; and

● the possibility that we may be required to issue a substantial amount of additional equity or debt securities or assume additional debt in connection with any such transactions.

Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize synergies or other anticipated benefits from a strategic transaction. Furthermore, the market for transactions is highly competitive, and our capital resources are such that we may not be well positioned in the market to execute a transaction, which may adversely affect our ability to find transactions that fit our strategic objectives. Consistent with industry practice, we routinely engage in discussions with industry participants regarding potential transactions, large and small. We intend to continue to engage in strategic discussions and will need to respond to potential opportunities quickly and decisively. As a result, strategic transactions may occur at any time and may be significant in size relative to our assets and operations.

Issuances or acquisitions of Dynegy's common stock, or sales or dispositions of Dynegy's common stock by stockholders could inhibit Dynegy’s ability to use its federal net operating losses or alternative minimum tax credits to offset its future taxable income may be limited under Sections 382 and 383 of the Internal Revenue Code.

Dynegy’s ability to utilize previously incurred federal NOLs and AMT credits to offset future taxable income would be limited if it were to undergo an “ownership change” within the meaning of Section 382 of the Internal Revenue Code (the “Code”). In general, an ownership change occurs whenever the percentage of the stock of a corporation owned by “5-percent shareholders” (within the meaning of Section 382 of the Code) increases by more than 50 percentage points over the lowest percentage of the stock of such corporation owned by such “5-percent shareholders” at any time over the preceding three years. Under certain circumstances, issuances or acquisitions of Dynegy's common stock or sales or dispositions of Dynegy's common stock by stockholders could trigger an “ownership change,” and apart from the application of the provisions of our current Stockholder Protection Rights Agreement, we will have limited control over the timing of any such sales or dispositions of our common stock.

More specifically, depending on prevailing interest rates and our market value at the time of such future ownership change, an ownership change under Section 382 of the Code would establish an annual limitation which might prevent full utilization of the deferred tax assets attributable to our previously incurred federal NOLs and AMT credits against the total future taxable income of a given year. The recent stockholder activity increases the likelihood that previously incurred federal NOLs and AMT credits will become subject to the limitations set forth in Sections 382 and 383 of the Code.

The magnitude of such limitations and their effect on us are difficult to assess and depend in part on our value at the time of any such ownership change and prevailing interest rates. For accounting purposes, at December 31, 2010, Dynegy’s net operating loss deferred tax asset attributable to its previously incurred federal NOLs was approximately $222 million and its AMT credits were approximately $271 million.

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”~~ ~~for further discussion~~Business," which is incorporated herein by reference. Substantially all of ~~our~~the assets of the Gas segment, including the power generation facilities weowned ~~own~~by DPC, one of our indirect wholly-owned subsidiaries, are pledged as collateral to secure the repayment of, and ~~our~~ other obligations under, the DPC Credit ~~Facility~~Agreement. Please read Note 1820—Debt for further discussion.

Our principal executive office located in Houston, Texas, is held under a lease that expires in ~~December 2017~~2022. We also lease additional offices or warehouses in the states of California, ~~Colorado,~~ Illinois, ~~Indiana,~~ New York, ~~Pennsylvania~~ and Texas.

Item 3. Legal Proceedings

Please read Note 2223—Commitments and Contingencies—Legal Proceedings for a description of our material legal proceedings, which is incorporated herein by reference.

36Item 4. Mine Safety Disclosures

~~TABLE~~Not ~~OF CONTENTS~~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.

Dynegy’s common stock, $0.01 par value per share, is listed and traded on the New York Stock Exchange under the ticker symbol “DYN.” The number of stockholders of record of its common stock as of March 3, 2011, based upon records of registered holders maintained by its transfer agent, was 11,763.

On May 21, 2010, Dynegy’s stockholders approved a reverse stock split of outstanding common stock at a reverse ratio of 1-for-5. This reverse stock split was effected on May 25, 2010. The following table sets forth, for the fiscal periods indicated, the high and low closing sales prices for Dynegy’s common stock on the NYSE after giving effect to this reverse stock split (including for share prices prior to May 25, 2010), as reported on the New York Stock Exchange Composite Tape.

Summary of Dynegy’s Common Stock Price

	High		Low
2011:
First Quarter (through March 3, 2011)	$	6.29	$	5.57
2010:
Fourth Quarter	$	5.89	$	4.44
Third Quarter		5.10		2.78
Second Quarter		6.80		3.85
First Quarter		9.95		6.10
2009:
Fourth Quarter	$	13.15	$	9.05
Third Quarter		12.75		8.90
Second Quarter		12.35		7.25
First Quarter		13.45		5.20

During the fiscal years ended December 31, 2010 and 2009, Dynegy’s Board of Directors did not elect to pay a cash common stock dividend. Please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Dividends on Dynegy Common Stock” for further discussion of its dividend policy and the impact of dividend restrictions contained in its financing agreements. Dynegy has not paid a dividend on any class of its common stock since 2002. Any decision to pay a dividend will be at the discretion of Dynegy’s Board of Directors, and subject to the terms of its then-outstanding indebtedness, but Dynegy does not expect to pay a dividend on its common stock in the foreseeable future. Please read Note 23—Capital Stock—Common Stock for further discussion.

Stockholder Protection Rights Agreement. On November 22, 2010, Dynegy’s Board of Directors adopted a Stockholder Protection Rights Plan (as subsequently amended, the “Rights Plan”) and declared a dividend of one stock purchase right (collectively, the “Rights”) for each share of common stock held by stockholders of record as of the close of business on December 2, 2010.

Dynegy’s Board of Directors adopted this short-term, narrowly tailored Rights Plan to prevent any person from obtaining control or de facto control of Dynegy without offering a control premium to all Dynegy stockholders. The issuance of the Rights is not intended to prevent a sale of control of Dynegy that is determined by Dynegy’s Board of Directors to be fair, advisable and in the best interests of all Dynegy stockholders. The Rights Plan provides that, unless terminated earlier by Dynegy, the Rights will expire following Dynegy’s next annual meeting of stockholders after the filing of the Form 10-K for the fiscal year 2010, unless the Rights Plan is approved by Dynegy’s stockholders (in which case it will expire at the first subsequent annual meeting at which it is not approved by a stockholder vote).

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Following distribution of the Rights, each Right will entitle its holder to purchase fractions of Participating Preferred Stock having economic and voting terms similar to those of one share of Dynegy’s common stock for an exercise price of $12.50 (subject to adjustment).

The Rights will be exercisable for shares of Dynegy common stock if Dynegy announces that a person or group has acquired 20 percent or more of Dynegy’s common stock or any person or group acquires more than 30 percent of Dynegy’s common stock. Under the Rights Plan, synthetic ownership of Dynegy’s common stock in the form of certain derivative securities counts towards the 20 percent and 30 percent ownership thresholds, if Dynegy’s Board of Directors determines that the owner of such derivative securities is seeking to use the existence of such securities for the purpose or effect of changing or influencing control of Dynegy.

The Rights Plan also exempts from its provisions all-cash, fully financed offers for all outstanding shares of Dynegy’s common stock that provide for a per share price in excess of $5.00 and meet certain other requirements. If the Rights become exercisable for Dynegy’s common stock, all Rights holders (other than the person or group triggering the Rights) will be entitled to purchase Dynegy’s common stock at a 50 percent discount. For example, if at the time the Rights become exercisable for Dynegy’s common stock the exercise price is still $12.50 and Dynegy’s common stock has a per share market value of $5, each Right would be exercisable for five shares of common stock ($25 of market value) at an exercise price of $12.50, (i.e., five shares of common stock at a 50 percent discount). Rights held by the person or group triggering the Rights will become void and will not be exercisable. If any person or group acquires between 10 percent and 50 percent of Dynegy’s common stock, Dynegy’s Board of Directors may, at its option, cause the exchange of one share of Dynegy common stock for each Right.

The distribution of the Rights is not taxable to stockholders. Until their distribution, the Rights will trade with Dynegy’s common stock. Dynegy’s Board of Directors may terminate the Rights Plan prior to the time the Rights are triggered. Please read Note 23—Capital Stock—Stockholder Protection Rights Agreement for further discussion.

Shareholder Agreements. In November 2009, as part of the transactions with LS Power, Dynegy and LS Power terminated a then-existing shareholder agreement and entered into a second shareholder agreement (the “New Shareholder Agreement”) which, among other things, generally restricts LS Power from increasing its ownership for a specified period up to 30 months. The New Shareholder Agreement does not, however, include any of the special rights (such as Board rights, special approval rights or preemption rights) previously associated with LS Power’s ownership.

Stockholder Return Performance Presentation. The graph below compares the cumulative 5-year total return of holders of Dynegy’s common stock with the cumulative total returns of the S&P Midcap 400 index, and a customized peer group. The peer group includes: Calpine Corp., NRG Energy Inc. and GenOn Energy. The graph tracks the performance of a $100 investment in Dynegy’s common stock, the peer group, and the index (with the reinvestment of all dividends) from December 31, 2005 to December 31, 2010.

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	12/05		12/06		12/07		12/08		12/09		12/10
Dynegy Inc.		100.00		149.59		147.52		41.32		37.40		23.22
S&P Midcap 400		100.00		110.32		119.12		75.96		104.36		132.16
Peer Group		100.00		127.39		211.71		82.56		95.35		90.33

The stock price performance included in this graph is not necessarily indicative of future stock price performance.

The above stock price performance comparison and related discussion is not to be deemed incorporated by reference by any general statement incorporating by reference this Form 10-K into any filing under the Securities Act of 1933 or under the Securities Exchange Act of 1934, or otherwise, except to the extent that we specifically incorporate this stock price performance comparison and related discussion by reference, and is not otherwise deemed “filed” under the Acts.

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Unregistered Sales of Equity Securities and Use of Proceeds. When restricted stock awarded by Dynegy becomes taxable compensation to employees, shares may be withheld to cover the employees’ withholding taxes. Information on Dynegy’s purchases of equity securities by means of such share withholdings during the quarter follows:

Period	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 to October 31, 2010		359	$	4.82		—		N/A
November 1 to November 30, 2010		—	$	—		—		N/A
December 1 to December 31, 2010		—	$	—		—		N/A
Total		359	$	4.82		—		N/A

These were the only repurchases of equity securities made by Dynegy during the three months ended December 31, 2010. Dynegy does not have a stock repurchase program.

DHI

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

Securities Authorized for Issuance Under Equity Compensation Plans

Please read Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters—Dynegy for information regarding securities authorized for issuance under our equity compensation plans.

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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."

Dynegy’s Selected Financial Data



	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		)

	Year Ended December 31,
	December 31,
	2010			2009			2008			2007			2006
	2011(2)			2010			2009			2008			2007
	(in millions, except per share data)
	(in millions)
Statement of Operations Data (1):
Balance Sheet Data:
Revenues	$	2,323		$	2,468		$	3,324		$	2,918		$	1,758
Current assets	$	3,569		$	2,180		$	1,988		$	2,780		$	1,614
Depreciation and amortization expense		(392	)		(335	)		(346	)		(306	)		(208	)
Current liabilities	3,051			1,562			1,848			1,681			999
Goodwill impairment		—			(433	)		—			—			—
Property and equipment, net	2,821			6,273			7,117			8,934			9,017
Impairment and other charges, exclusive of goodwill impairment shown separately above		(148	)		(538	)		—			—			(9	)
Total assets	8,311			9,949			10,903			14,174			13,107
General and administrative expenses		(163	)		(159	)		(157	)		(203	)		(196	)
Long-term debt (excluding current portion) (5)	1,069			4,626			4,775			6,072			5,939
Operating income (loss)		(11	)		(834	)		744			576			220
Current portion of long-term debt	7			148			807			64			51
Interest expense and debt extinguishment costs (2)		(363	)		(461	)		(427	)		(384	)		(631	)
Capital leases not already included in long-term debt	—			—			4			4			5
Income tax (expense) benefit		197			315			(90	)		(140	)		116
Total equity	32			2,719			3,003			4,583			4,620
Income (loss) from continuing operations		(235	)		(1,040	)		188			105			(242	)
Income (loss) from discontinued operations (3)		1			(222	)		(17	)		166			(92	)
Cumulative effect of change in accounting principles		—			—			—			—			1
Net income (loss)	$	(234	)	$	(1,262	)	$	171		$	271		$	(333	)
Net income (loss) attributable to Dynegy Inc. common stockholders		(234	)		(1,247	)		174			264			(342	)
Basic earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders	$	(1.96	)	$	(6.25	)	$	1.14		$	1.10		$	(2.72	)
Basic net income (loss) per share attributable to Dynegy Inc. common stockholders		(1.95	)		(7.60	)		1.04			1.75			(3.72	)
Diluted earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders	$	(1.96	)	$	(6.25	)	$	1.14		$	1.10		$	(2.72	)
Diluted net income (loss) per share attributable to Dynegy Inc. common stockholders		(1.95	)		(7.60	)		1.04			1.75			(3.72	)
Shares outstanding for basic EPS calculation		120			164			168			151			92
Shares outstanding for diluted EPS calculation		121			165			168			151			102
Cash dividends per common share	$	—		$	—		$	—		$	—		$	—
Cash Flow Data:
Net cash provided by (used in) operating activities	$	423		$	135		$	319		$	341		$	(194	)
Net cash provided by (used in) investing activities		(534	)		251			(102	)		(817	)		358
Net cash provided by (used in) financing activities		(69	)		(608	)		148			433			(1,342	)
Cash dividends or distributions to partners, net		—			—			—			—			(17	)
Capital expenditures, acquisitions and investments		(531	)		(594	)		(640	)		(504	)		(163	)

41_______________________________________________________________________________

~~TABLE OF CONTENTS~~34

	December 31,
	2010		2009		2008		2007		2006
	(in millions)
Balance Sheet Data (4):
Current assets	$	2,244	$	2,038	$	2,803	$	1,663	$	1,989
Current liabilities		1,565		1,847		1,702		999		1,166
Property and equipment, net		6,273		7,117		8,934		9,017		4,951
Total assets		10,013		10,953		14,213		13,221		7,537
Long-term debt (excluding current portion)		4,626		4,775		6,072		5,939		3,190
Notes payable and current portion of long-term debt		148		807		64		51		68
Capital leases not already included in long-term debt		—		4		4		5		6
Total equity		2,746		2,979		4,485		4,529		2,267

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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) ~~Includes~~We ~~$249~~completed ~~million~~the ofDMG ~~debt~~Transfer ~~conversion~~effective ~~costs~~September ~~for~~1, ~~the~~2011. ~~twelve~~Please ~~months~~read ~~ended~~Note ~~December~~3—Chapter ~~31,~~11 ~~2006~~Cases for further discussion.

(3) ~~Discontinued~~Includes ~~operations~~$21 ~~include~~million ~~the~~and ~~results~~$46 million of ~~operations~~debt ~~from~~extinguishment costs for the ~~following~~year ~~businesses:~~ended December 31, 2011 and 2009, respectively.

●(4) ~~The~~Discontinued ~~Arlington~~operations ~~Valley~~include ~~and~~the ~~Griffith~~results ~~power~~of ~~generation~~operations ~~facilities~~from ~~(collectively,~~ the ~~Arizona~~following ~~power generation facilities”) (sold fourth quarter 2009);~~businesses:

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

●▪ ~~Heard~~Bluegrass ~~County~~ power generating facility (sold ~~second~~fourth quarter 2009);

●▪ ~~Calcasieu~~Heard County power generating facility (sold ~~first~~second quarter ~~2008~~2009); ~~and~~

●▪ ~~CoGen~~Calcasieu ~~Lyondell~~ power generating facility (sold ~~third~~first quarter ~~2007~~2008).; and

~~(4)~~▪ ~~The~~CoGen ~~merger~~Lyondell ~~with~~power LSgenerating ~~Power~~facility (~~April~~sold 2,third quarter 2007) ~~was accounted for under the purchase method of accounting~~. ~~Accordingly, the purchase price was allocated to the assets acquired and liabilities assumed based on their estimated fair values as of the effective date of the transaction.~~

42(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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~~Dynegy~~Table ~~Holdings’~~of ~~Selected Financial Data~~Contents

	Year Ended December 31,
	2010			2009			2008			2007			2006
	(in millions, except per share data)
Statement of Operations Data (1):
Revenues	$	2,323		$	2,468		$	3,324		$	2,918		$	1,758
Depreciation and amortization expense		(392	)		(335	)		(346	)		(306	)		(208	)
Goodwill impairment		—			(433	)		—			—			—
Impairment and other charges, exclusive of goodwill impairment shown separately above		(148	)		(538	)		—			—			(9	)
General and administrative expenses		(158	)		(159	)		(157	)		(184	)		(193	)
Operating income (loss)		(6	)		(836	)		744			595			223
Interest expense and debt extinguishment costs (2)		(363	)		(461	)		(427	)		(384	)		(579	)
Income tax (expense) benefit		184			313			(138	)		(105	)		89
Income (loss) from continuing operations		(243	)		(1,046	)		222			165			(217	)
Income (loss) from discontinued operations (3)		1			(222	)		(17	)		166			(91	)
Net income (loss)	$	(242	)	$	(1,268	)	$	205		$	331		$	(308	)
Net income (loss) attributable to Dynegy Holdings Inc.	$	(242	)	$	(1,253	)	$	208		$	324		$	(308	)
Cash Flow Data:
Net cash provided by (used in) operating activities	$	423		$	152		$	319		$	368		$	(205	)
Net cash provided by (used in) investing activities		(520	)		790			(87	)		(688	)		357
Net cash provided by (used in) financing activities		(69	)		(1,193	)		146			369			(1,235	)
Capital expenditures, acquisitions and investments		(517	)		(596	)		(626	)		(350	)		(155	)

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

	December 31,
	2010		2009		2008		2007		2006
	(in millions)
Balance Sheet Data (1):
Current assets	$	2,180	$	1,988	$	2,780	$	1,614	$	1,828
Current liabilities		1,562		1,848		1,681		999		1,165
Property and equipment, net		6,273		7,117		8,934		9,017		4,951
Total assets		9,949		10,903		14,174		13,107		8,136
Long-term debt (excluding current portion)		4,626		4,775		6,072		5,939		3,190
Notes payable and current portion of long-term debt		148		807		64		51		68
Capital leases not already included in long-term debt		—		4		4		5		6
Total equity		2,719		3,003		4,583		4,620		3,036

(1) The LS Power assets were contributed to DHI contemporaneously with the merger with LS Power (April 2, 2007). This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities were recorded by DHI at Dynegy’s historical cost on Dynegy’s date of acquisition. Additionally, the Sithe Energies assets were contributed to DHI on April 2, 2007. This contribution was accounted for as a transaction between entities under common control. As such, the assets and liabilities were recorded by DHI at Dynegy’s historical cost on Dynegy’s date of acquisition, January 31, 2005. In addition, DHI’s historical financial statements have been adjusted in all periods presented to reflect the contribution as though DHI had owned these assets beginning January 31, 2005.

(2) Includes $204 million of debt conversion costs for the twelve months ended December 31, 2006.

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

● The Arizona power generation facilities (sold fourth quarter 2009);

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

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● 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).

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 ~~companies~~company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three ~~separate~~ segments in our consolidated financial statements: (i) the ~~GEN-MW~~Coal segment ("Coal"); (ii) the ~~GEN-WE;~~Gas segment ("Gas") and (iii) the ~~GEN-NE. Because~~Dynegy ofNortheast ~~the~~segment ~~diversity~~("DNE"). ~~among~~Prior ~~their~~to ~~respective~~2011, ~~operations~~we ~~and~~reported ~~how~~results wefor ~~allocate~~the ~~our~~following ~~resources~~segments: (i) GEN-MW, we(ii) GEN-WE ~~report~~and ~~the~~(iii) GEN-NE. ~~results~~Accordingly, ofwe ~~each~~have ~~business~~recast asthe acorresponding ~~separate~~items of segment ininformation ~~our~~for ~~consolidated~~all ~~financial~~prior ~~statements~~periods. Our consolidated financial results also reflect corporate-level expenses such as ~~general and administrative,~~ 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 ~~GEN-MW~~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.

~~Going~~Chapter 11 ~~Concern~~Cases. ~~Our~~ On ~~accompanying~~November 7, ~~consolidated financial statements have been prepared assuming that we will continue as a going concern~~2011, ~~which contemplates realization of assets and~~ the ~~satisfaction~~DH ofDebtor ~~liabilities~~Entities infiled the ~~normal~~DH ~~course~~Chapter 11 ~~of business for the twelve month period following the date of these consolidated financial statements~~Cases. ~~However,~~On ~~continued~~July ~~low power prices over the past two years have had a significant adverse impact on our business. Further~~6, ~~as our credit rating has declined~~2012, ~~counterparty~~Dynegy ~~requirements~~commenced ~~for~~the ~~posting~~Dynegy ~~collateral~~Chapter in11 ~~support of our risk management positions have become more stringent~~Case. ~~Over~~ Only the ~~next~~DH ~~twelve~~Debtor ~~months,~~Entities weand ~~expect that we will continue to need to utilize~~ our ~~Credit~~parent ~~Facility,~~Dynegy ~~through~~sought ~~the~~relief ~~issuance~~under ~~of letters of credit and/or through~~ the ~~drawing~~Bankruptcy ~~of cash~~Code, orand ~~secure~~none ~~additional sources~~ of ~~capital~~our toother ~~continue~~direct toor ~~meet~~indirect ~~our~~subsidiaries ~~operating~~are ~~needs~~debtors thereunder. The ~~agreements~~normal ~~governing our existing Credit Facility require us~~ day-to-day ~~meet~~operations ~~specific financial covenants both as a matter~~ of ~~course and as a precondition to~~ the ~~incurrence~~natural ofgas-fired ~~additional~~power ~~debt~~generation ~~and~~facilities toheld ~~the~~by ~~making~~DPC ofhave ~~restricted~~continued ~~payments~~without ~~or asset sales, among other things~~interruption. ~~These~~ ~~specific~~The ~~financial~~commencement ~~covenants are required to be calculated on a quarterly basis and become more restrictive over the course~~ of ~~2011. Using~~ the ~~latest~~Chapter 11 ~~available~~Cases ~~forward~~did ~~commodity price curves and considering our current derivative contracts, we project that it is likely that we will~~ not beconstitute able to comply with our EBITDA to Consolidated Interest Expense covenant as currently set forth in our Credit Facility, particularly in the third and fourth quarters of 2011. Furthermore, we expect that our available liquidity will continue to be reduced as a ~~result~~default ~~of borrowing limitations~~ under ~~the~~either ~~covenant~~of ~~regarding~~ the ~~ratio of Secured Debt to EBITDA, as defined in our~~ Credit ~~Facility~~Agreements. To ~~continue~~Please Note as3—Chapter a11 ~~going~~Cases ~~concern~~for ~~over~~further ~~the~~discussion ~~next~~of ~~twelve~~the ~~months,~~Chapter 11 weCases ~~must~~and ~~either (i) meet~~ the ~~financial~~related ~~covenants~~Settlement soAgreement ~~that~~and wePlan ~~can~~Support ~~access our Credit Facility, or (ii) amend or replace our Credit Facility or otherwise secure additional capital~~Agreement.

AtReorganization ~~December~~Activity. On 31August 5, ~~2010~~2011, weDynegy ~~have~~completed the ~~following~~Reorganization ~~obligations~~to ~~outstanding~~facilitate ~~under~~the execution of the Credit ~~Facility:~~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 ~~$68~~Agreements. In ~~million~~connection ~~due~~with ~~April~~the ~~2013~~Reorganization, ~~under~~subsidiaries ~~the~~from ~~Term~~Dynegy's ~~Loan~~Gas, B;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 $~~850~~2.1 billion ~~million~~through ~~due~~October 15, ~~April~~2026. ~~2013~~Subsequent to the exchange, DGIN assigned its rights to receive payments under the ~~Term~~Undertaking ~~Facility~~Agreement ~~(fully~~to ~~collateralized~~us byin exchange for the Promissory Note in the amount of $~~850~~1.25 billion ~~million~~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 ~~non-current~~Dynegy's ~~restricted~~obligations ~~cash~~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 $~~375~~192 million of the Sithe Senior Notes for approximately $217 million. inIn connection with the Sithe Tender Offer and consent solicitation, we amended the indenture under which the Sithe Senior Notes were issued ~~letters~~to eliminate or modify substantially all of ~~credit~~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.

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Recent transactions. Beginning in 2010 and extending through January 2011, we engaged in an ongoing review of our operating and strategic opportunities and risks. That review was conducted against a backdrop of continuing declines in the market prices of natural gas and wholesale electricity. These declines have reduced the outlook for the cash flow that can be expected to be generated by us in the next several years. Our declining cash flow, combined with our high level of indebtedness and the probable need to incur additional indebtedness to fund operations and required environmental capital expenditures led us to conclude that the risks of pursing a standalone business strategy are considerable.

On August 13, 2010, Dynegy entered into a merger agreement with an affiliate of The Blackstone Group L.P. (as amended, the “Blackstone Merger Agreement”), pursuant to which Dynegy would be acquired and Dynegy’s stockholders would receive $4.50 per share in cash. On November 16, 2010, the agreement was amended to increase the merger consideration to $5.00 per share in cash. The Blackstone Merger Agreement was not approved by Dynegy’s stockholders at a special stockholders’ meeting on November 23, 2010 and was subsequently terminated by the parties in accordance with the terms of the agreement. The Blackstone Merger Agreement requires Dynegy to pay Blackstone a termination fee in the amount of approximately $16 million in the event that within 18 months of November 23, 2010, Dynegy consummates an alternative transaction having an aggregate value of more than $4.50 per share.

On November 23, 2010, we commenced the solicitation of transaction proposals from a broad group of potentially interested parties, including Icahn Enterprises L.P. (“Icahn”) and other potential strategic and financial buyers. As a result of those efforts, on December 15, 2010, Dynegy’s Board of Directors unanimously approved a merger agreement between Dynegy and an affiliate of Icahn (as amended, the “Icahn Merger Agreement”). In connection with the Icahn Merger Agreement, Icahn launched a cash tender offer on December 22, 2010 for all of the issued and outstanding shares of common stock at $5.50 per share (the “Tender Offer”). On January 25, 2011, Dynegy announced that it did not receive any bona fide acquisition proposals. At the expiration time of the Tender Offer on February 18, 2011, an insufficient number of shares had been tendered in response to the Tender Offer, and as a result the Icahn Merger Agreement automatically terminated. In connection with the termination and as required by the Icahn Merger Agreement, in February 2011, Dynegy paid $5 million to Icahn with respect to expenses incurred by Icahn related to the Icahn Merger Agreement, and we may be required to pay additional fees of $11 million in the event that within 18 months of February 18, 2011, Dynegy consummates an alternative transaction having an aggregate value of more than $5.50 per share.

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Business Discussion

The following is a brief discussion of each of our ~~power generation~~ segments, including a list of key factors that have affected, and are ~~expected to continue to affect, their respective earnings and cash flows. We also present a brief discussion of our corporate-level expenses.~~

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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. ~~For~~Power ~~example,~~supplies asimilarly ~~warm~~vary ~~summer~~by orregion aand ~~cold~~are ~~winter~~impacted ~~typically~~significantly ~~increases~~by ~~demand~~available ~~for~~generating ~~electricity. Conversely~~capacity, ~~the~~transmission ~~recent~~capacity ~~recessionary~~and ~~economic~~federal ~~environment~~and ~~has~~state ~~negatively~~regulation. ~~impacted~~The ~~demand for electricity, and the~~ proliferation of advanced shale gas drilling has increased domestic natural gas supplies, ~~suppressing~~which ~~natural~~has ~~gas~~caused ~~prices.~~a ~~Power~~decline ~~supplies~~in ~~similarly~~power ~~vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation~~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 ~~see~~read Item 1. Business—Environmental Matters for further discussion); and

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

46Please read "Item 1A. Risk Factors" for additional factors that could affect our future operating results, financial condition and cash flows.

~~TABLE~~In OFaddition ~~CONTENTS~~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.

~~Please~~Coal. Our ~~read~~assets ~~Item~~in ~~1A.~~Coal ~~Risk~~are ~~Factors~~primarily ~~for~~coal-fired ~~additional~~facilities ~~factors~~but ~~that~~also ~~could~~include ~~affect~~two ~~our~~natural ~~future~~gas-fired ~~operating~~peaking ~~results,~~facilities. ~~financial~~The ~~condition~~Coal segment was transferred to Dynegy effective September 1, 2011 and ~~cash~~reacquired ~~flows~~from Dynegy effective June 5, 2012. The following specific factors affect or could affect the performance of this reportable segment:

In• ~~addition~~Our ability to ~~these~~maintain ~~overarching~~sufficient ~~factors~~coal inventories, ~~other~~which ~~factors~~is ~~have~~dependent ~~influenced,~~upon the continued performance of the mines and ~~are~~railroads ~~expected~~for todeliveries ~~continue~~of tocoal ~~influence,~~in ~~earnings~~a consistent and ~~cash~~timely ~~flows~~manner, ~~for~~and ~~our~~its ~~three~~impact ~~reportable~~on ~~segments~~our ~~within~~ability ~~the~~to ~~power~~serve ~~generation~~the ~~business~~critical aswinter ~~further~~and ~~described~~summer ~~below.~~on-peak loads;

~~Power~~• ~~Generation—Midwest~~Costs ~~Segment. Our~~of ~~assets~~transportation inrelated ~~GEN-MW~~to ~~include~~ coal~~-fired~~ ~~facilities and natural gas-fired facilities. The following specific factors affect or could affect the performance of this reportable segment:~~deliveries;

●• Our ~~ability~~requirement to ~~maintain~~utilize ~~sufficient~~a ~~coal~~significant ~~inventories,~~amount ~~which is dependent upon the continued performance~~ of ~~the~~cash ~~railroads~~ for ~~deliveries~~capital ofexpenditures ~~coal~~required ~~in a consistent and timely manner, and its impact on our ability~~ to ~~serve~~comply with the ~~critical~~remaining ~~winter~~Consent ~~and~~Decree ~~summer on-peak loads~~work;

●• ~~Our~~Regional ~~requirement~~renewable toenergy ~~utilize~~mandates aand ~~significant~~initiatives ~~amount~~that ofmay ~~cash~~alter ~~for~~supply ~~capital~~conditions ~~expenditures~~within ~~required~~the toISO ~~comply~~and ~~with~~our generating units' positions in the ~~Midwest~~aggregate ~~Consent~~supply ~~Decree~~stack;

~~● Regional renewable energy mandates and initiatives that may alter supply conditions within the ISO and our generating units’ positions in the aggregate supply stack;~~37

●Table ~~Changes~~of ~~in the MISO market design or associated rules; and~~Contents

●• Changes in the ~~existing~~MISO ~~PJM~~market ~~RPM~~design ~~capacity markets~~ or inassociated ~~the~~rules; ~~bilateral MISO capacity markets~~ and ~~any resulting effect on future capacity revenues.~~

~~Power~~• ~~Generation—West~~Changes ~~Segment. Our assets~~ in ~~GEN-WE are all natural gas-fired power generating facilities with~~ the ~~exception~~existing ofbilateral ~~our~~MISO ~~fuel~~capacity ~~oil-fired~~markets ~~Oakland~~and ~~facility. The~~any ~~following~~resulting ~~specific~~effect ~~factors~~on ~~impact~~future orcapacity ~~could impact the performance of this reportable segment:~~revenues.

● Gas. Our ~~ability~~assets toin ~~maintain~~Gas ~~and~~are ~~operate~~all natural gas-fired power generating facilities with the exception of our ~~plants~~fuel inoil-fired aOakland ~~manner~~facility. ~~that~~The ~~ensures~~following wespecific ~~receive~~factors ~~full~~impact ~~capacity~~or ~~payments~~could ~~under~~impact ~~our~~the ~~various~~performance ~~tolling~~of ~~agreements;~~this reportable segment:

●• Our ability to maintain ~~the~~and ~~necessary~~operate ~~permits~~our toplants ~~continue~~in toa ~~operate~~manner ~~our~~that ~~Moss~~ensures ~~Landing~~we ~~and~~receive ~~Morro~~full ~~Bay~~capacity ~~facilities~~payments ~~with~~under ~~once-through,~~our ~~seawater~~various ~~cooling~~tolling ~~systems~~agreements; ~~and~~

●• ~~The~~Our ~~cost~~ability ~~incurred~~to maintain the necessary permits to ~~demolish~~continue ~~and~~to ~~remediate~~operate ~~the~~our ~~South~~Moss Landing and Morro Bay ~~facility.~~facilities with once-through, seawater cooling systems;

~~Power~~• ~~Generation—Northeast~~The ~~Segment. Our~~costs ~~assets~~incurred into ~~GEN-NE~~demolish ~~include natural gas, fuel oil~~ and ~~coal-fired~~remediate ~~power generating facilities. The following specific factors impact or could impact~~ the ~~performance~~South ofBay ~~this~~facility; ~~reportable segment:~~and

●• ~~Our~~Changes ~~ability~~in tothe ~~maintain~~existing ~~sufficient~~bilateral ~~coal~~CAISO ~~and~~resource ~~fuel~~adequacy ~~oil~~markets ~~inventories, including continued deliveries of coal~~ and ~~oil~~any inresulting aeffect ~~consistent~~on ~~and~~future ~~timely~~capacity ~~manner, and continued access to uninterrupted natural gas supplies, to serve the winter and summer on-peak loads;~~revenues.

●DNE. Our ~~The~~assets ~~additional~~in ~~costs~~DNE ~~imposed~~include bynatural ~~state-driven~~gas, ~~environmental~~fuel ~~compliance~~oil ~~initiatives~~and ~~aimed~~coal-fired atpower ~~reducing~~generating ~~mercury~~facilities. ~~emission~~To ~~levels~~the ~~and~~extent ~~other~~our ~~constituents~~subsidiaries ~~such~~continue asto ~~CO2,~~be ~~NOx~~the operator and ~~SO2~~commercial asmanager ~~well~~of asthese ~~more~~assets, ~~restrictive~~the ~~measures~~following ~~for~~specific ~~cooling~~factors ~~water~~impact ~~intakes~~or ~~for~~could ~~fish~~impact ~~protection;~~the performance of this reportable segment:

●• ~~Changes~~The inamount ~~NYISO/ISO-NE~~of ~~market~~time ~~rules~~that orwill ~~state-specific~~be ~~mandates~~required ~~that~~to ~~favor~~sell the leased Roseton and~~/or~~ ~~subsidize~~Danskammer ~~renewable~~facilities ~~energy~~in ~~sources~~accordance with the terms of the Settlement Agreement and ~~demand~~Plan ~~response~~Support ~~initiatives;~~Agreement and the time to secure necessary applicable federal and state regulatory approvals;

●• ~~Our~~Future ~~ability~~operating tocosts, ~~preserve~~including ~~and/or~~property ~~capture~~taxes ~~value~~and ~~around planned transmission upgrades designed to improve transfer limits around known constraints.~~labor;

47• 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;

~~TABLE~~• OFThe ~~CONTENTS~~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 ~~general~~interest, depreciation and ~~administrative~~amortization and ~~interest~~taxes. Significant items impacting future earnings and cash flows include:

●• ~~Interest~~Resolution ~~expense,~~of ~~which~~the ~~reflects~~Chapter ~~debt~~11 ~~with~~Cases aand ~~weighted-average~~our ~~interest~~ability ~~rate~~to ofobtain ~~approximately~~support ~~seven~~for ~~percent~~the Plan;

●• ~~General~~Access ~~and~~to ~~administrative~~capital ~~costs,~~markets ~~which~~on ~~will~~reasonable ~~be impacted by~~terms, ~~among~~interest ~~other~~rates ~~things, (i) staffing levels~~ and ~~associated~~other ~~expenses;~~costs ~~(ii)~~of ~~funding requirements under our pension plans~~liquidity; ~~(iii) any future corporate-level litigation reserves or settlements and (iv) our ability to realize planned cost savings reflected in our financial forecasts; and~~

●• ~~Income~~Interest ~~taxes,~~expense; ~~which will be impacted by our ability to realize our net operating losses~~ and ~~alternative minimum tax credits.~~

~~Other~~• ~~also~~Income ~~includes our legacy CRM operations~~taxes, which ~~primarily~~will ~~consists~~be ofimpacted aby ~~minimal~~our ~~number~~ability ofto ~~legacy~~realize ~~natural~~value ~~gas~~from ~~trading~~our ~~positions~~NOLs ~~that~~and ~~will~~AMT ~~remain until 2017~~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, ~~collateral requirements,~~ fixed capacity payments and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll.

~~Our~~As a result of the Reorganization, our primary sources of internal liquidity are cash flows from operations, and cash on hand,. ~~short-term~~Cash ~~investments~~on ~~and~~hand ~~available~~includes ~~capacity~~cash ~~under~~proceeds ~~our~~from the DPC Credit ~~Facility~~Agreement, of which ~~the~~is ~~revolver~~limited ~~capacity~~in ofuse ~~$1,080~~and ~~million~~distribution isas ~~scheduled~~further todescribed ~~mature~~ in ~~April~~footnote ~~2012~~1 ~~and~~to the ~~term~~liquidity ~~letter~~table ofbelow. ~~credit~~Please ~~capacity~~read ofNote ~~$850~~20—Debt ~~million~~for isfurther ~~scheduled to mature in April 2013~~information.

~~Our~~On ~~cash~~September ~~on hand and short-term investments as of December 31~~1, ~~2010 and our internal forecasted cash flows from operations for~~ 2011, ~~are~~we ~~not~~completed ~~expected~~the toDMG beTransfer. ~~sufficient~~Effective toJune ~~fund our planned $265 million 2011 capital expenditure program and our $148 million 2011 debt service requirements. Furthermore~~5, ~~using the latest available forward commodity price curves and considering our current derivative contracts~~2012, we ~~project~~reacquired ~~that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant contained in our Credit Facility, particularly in~~ the ~~third~~Coal ~~and~~segment ~~fourth~~(including ~~quarters of 2011~~DMG). ~~Accordingly,~~ asPlease ~~described~~read atNote ~~Going~~27—Subsequent ~~Concern~~Events ~~above,~~for wefurther ~~are attempting to amend or replace our existing Credit Facility~~discussion.

WeOur ~~may~~primary ~~also seek additional~~ sources of ~~liquidity in~~external ~~an effort to secure sufficient cash to meet our operating needs. These additional sources of~~ liquidity ~~could~~are ~~include~~proceeds ~~asset~~from ~~sales,~~capital ~~public~~market ortransactions ~~private~~to ~~issuances~~the ofextent ~~debt, equity or equity-linked securities, debt for equity swaps, or any combination of these. Please read Capital Structuring Transactions and Asset Dispositions below for more detail. However,~~ we ~~cannot~~engage ~~provide any assurances that we will be successful~~ in ~~accomplishing~~such ~~any of these plans~~transactions.

~~Please~~Current read the discussion above regarding Going Concern, as well as the discussion below regarding our Revolver Capacity, and Note 18 Debt—Credit Facility for a further discussion of the financial covenants contained in the Credit FacilityLiquidity. ~~For~~ The ~~additional~~following ~~discussion~~tables ofsummarize ~~factors that may affect~~ our ~~ability~~liquidity toposition at ~~continue~~September as7, a2012 ~~going concern~~ and ~~the potential consequences of our failure to do so~~December 31, ~~please see Item 1A—Risk Factors~~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

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	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

~~Current Liquidity. The following table summarizes our consolidated revolver capacity and liquidity position at March 3, 2011, December 31, 2010 and December 31, 2009:~~_______________________________________________________________________________

	March 3, 2011			December 31, 2010			December 31, 2009
	(in millions)
Revolver capacity (1) (2)	$	954		$	954		$	1,080
Borrowings against revolver capacity		—			—			—
Term letter of credit capacity, net of required reserves	825				825			825
Plum Point and Sandy Creek letter of credit capacity (3)	—				—			102
Available contingent letter of credit facility capacity (4)	—				—			—
Outstanding letters of credit (3)	(392		)		(375	)		(536	)
Unused capacity	1,387				1,404			1,471
Cash—DHI	319				253			419
Short-term investments—DHI (5)	74				90			—
Total available liquidity—DHI	1,780				1,747			1,890
Cash—Dynegy	46				38			52
Short-term investments—Dynegy (5)	9				16			—
Total available liquidity—Dynegy	$	1,835		$	1,801		$	1,942

(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.

(12) WeOn ~~currently~~August ~~have~~5, a2011, ~~syndicate~~we ofborrowed ~~lenders~~$600 ~~participating~~million inunder the ~~revolving~~DMG Credit Agreement. A portion of ~~our~~the proceeds from the DMG Credit ~~Facility~~Agreement ~~with~~borrowing ~~commitments~~was ~~ranging~~used ~~from~~to make a $30200 million restricted payment to a parent holding company of DMG. The DMG Credit Agreement limits further distributions by DMG to its parent to $~~165~~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,

(2) As of March 3, 2011 and December 31, 2010, DHI’s available liquidity under the Credit Facility was reduced by $126 million as a result of borrowing limitations under the covenant regarding the ratio of Secured Debt to EBITDA. Although our available liquidity is reduced, we have adequate liquidity to meet expected needs for the remainder of the first quarter. Further reduction in capacity may occur based on our ratio of Secured Debt to EBITDA at March 31, 2011, June 30, 2011, September 30, 2011 and December 31, 2011. Please see Revolver Capacity below for further discussion. Additionally, using the latest available forward commodity price curves and considering our current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant, as defined in our Credit Facility, particularly in the third and fourth quarters of 2011.39

~~(3)~~Table ~~Reflects reduction~~ of $102 million of capacity as of January 1, 2010 due to the deconsolidation of PPEA Holding and the subsequent sale of our interest in PPEA Holding. Please read Note 2—Summary of Significant Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.Contents

~~(4)~~and ~~Under~~interest ~~the~~in ~~terms~~and to one hundred percent (100%) of the ~~Contingent~~issued LCand ~~Facility,~~outstanding upmembership tointerests ~~$150~~of ~~million~~Coal ofHoldco ~~capacity~~("DMG ~~can~~Acquisition"). ~~become~~As ~~available~~such, ~~contingent~~liquidity onposition ~~changes~~amounts inare ~~forward~~presented ~~spark~~for ~~spreads~~DMG ~~and~~as ~~power~~of ~~prices~~September ~~for~~7, 2012, but not as of December 31, 2011.

(53) WeOther ~~invest~~cash ~~our~~consists ~~available~~of ~~cash~~$305 ~~balances~~million inand ~~certain~~$305 ~~investments~~million ~~permitted~~at byDynegy ~~our~~Gas ~~internal~~HoldCo, ~~policies~~LLC ("Gas HoldCo"); $14 million and ~~external~~$28 ~~financing~~million ~~agreements~~at Dynegy Administrative Services Company; $49 million and $30 million at DH; and $20 million and $3 million at Dynegy Northeast Generation, Inc. ~~Please~~as ~~read~~of ~~Note~~September ~~2—Summary~~7, 2012 and December 31, 2011, respectively. Other cash also consists of ~~Significant~~$173 ~~Accounting~~million ~~Policies—Short-Term~~at ~~Investments~~Coal ~~and~~Holdco ~~Note~~as ~~6—Investments~~of ~~for~~September ~~further~~7, ~~discussion~~2012.

~~Cash~~(4) onThe ~~Hand. At~~LC ~~March~~facilities 3,were ~~2011~~collateralized ~~and~~with ~~December~~cash ~~31,~~proceeds ~~2010,~~received ~~Dynegy~~under ~~had~~the ~~cash~~New onCredit ~~hand~~Agreements. The amount of ~~$365~~the ~~million~~LC ~~and~~availability ~~$291~~plus ~~million,~~any ~~respectively,~~unused asrequired ~~compared~~reserves toof ~~$471~~3 ~~million~~percent aton the ~~end~~unused ofcapacity, ~~2009.~~may ~~The~~be ~~increase~~withdrawn infrom ~~cash~~the onLC ~~hand~~facilities atwith ~~March~~three 3,days ~~2011~~written ~~compared~~notice ~~with~~for ~~December~~unrestricted ~~31,~~use ~~2010~~in isthe ~~primarily~~operations ~~related~~of to the ~~expiration~~ ofapplicable anentity. ~~agreement~~LC ~~and~~capacity ~~the~~as ~~subsequent release~~ of ~~$50~~September ~~million~~7, of2012 ~~restricted~~reflects ~~cash. The~~a ~~decrease~~reduction in ~~cash~~capacity onfor ~~hand~~DPC atfollowing ~~December~~the ~~31,~~requested ~~2010~~release asof ~~compared~~unused tocash ~~the~~collateral ~~end~~from ofrestricted ~~2009~~cash. isActual ~~primarily~~commitment ~~attributable~~amounts tounder ~~cash~~each ~~used~~of ~~for~~the ~~purchases~~New ofCredit ~~short-term~~Agreements ~~investments,~~have ~~debt~~not ~~service~~been reduced, and ~~capital~~we ~~expenditures~~can ~~partially~~increase ~~offset~~the byLC ~~cash~~capacity ~~generated~~up ~~from~~to the ~~operating~~original ~~activities~~commitment ofamount ~~our~~in ~~power~~the ~~generation~~future ~~business~~by posting additional cash collateral.

49(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.

~~TABLE~~(6) OFThe ~~CONTENTS~~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.

At(7) ~~March~~Does 3,not ~~2011~~reflect ~~and~~our ~~December~~ability ~~31, 2010, DHI had cash on hand of $319 million and $253 million, respectively, as compared~~ to ~~$419~~use ~~million at~~ the ~~end~~first oflien ~~2009. The~~structure ~~increase~~as indescribed ~~cash on hand at March 3, 2011 compared with December 31, 2010 is primarily related to the expiration of an agreement and the subsequent release of $50 million of restricted cash. The decrease~~ in ~~cash~~"Collateral onPostings" hand at December 31, 2010 as compared to the end of 2009 is primarily attributable to cash used for purchases of short-term investments, debt service and capital expenditures partially offset by cash generated from the operating activities of our power generation businessbelow.

~~Revolver~~DPC ~~Capacity~~Restricted Payments. ~~DHI’s~~ In ~~available~~addition ~~liquidity~~to ~~under~~ the ~~Credit Facility was reduced by~~ $~~126~~ 400 million, asin ofthe ~~December 31~~aggregate, ~~2010 as a result~~ of ~~borrowing~~proceeds ~~limitations~~from ~~under~~ the ~~covenant~~DPC ~~regarding~~Credit ~~the~~Agreement ~~ratio~~that ofwas ~~Secured~~initially ~~Debt~~distributed to ~~EBITDA~~Gas ~~(as~~HoldCo, ~~defined therein). The effect of reduced availability under~~ the DPC Credit ~~Facility~~Agreement islimit ~~less~~distributions ~~available~~by ~~liquidity~~DPC to ~~DHI. Further~~its ~~reduction~~parent ~~in capacity~~of $135 ismillion ~~likely~~per ~~to occur at March 31~~year, ~~2011,~~provided ~~June~~the ~~30,~~borrower ~~2011, September 30, 2011~~ and ~~December~~its ~~31,~~subsidiaries ~~2011. Additionally,~~possess asat ~~discussed~~least in$50 million ~~Going~~of ~~Concern~~unrestricted ~~above,~~cash ~~using the latest available forward commodity price curves~~ and ~~considering~~short-term ~~our~~investments ~~current derivative contracts, we project that it is likely that we will not be able to comply with our EBITDA to Consolidated Interest Expense covenant,~~ as ~~currently~~of ~~set~~the ~~forth in~~date ~~our~~of ~~Credit Facility, particularly in~~ the ~~third~~proposed ~~and fourth quarters of 2011~~distribution. In ~~such~~December ~~event~~2011, ~~the~~DPC ~~Credit~~made ~~Facility~~a ~~may~~distribution beof ~~terminated by the lenders and outstanding amounts thereunder accelerated. Accordingly, we are~~$135 ~~attempting~~million to ~~amend~~its ~~or replace our existing Credit Facility~~parent. Please read ~~Going Concern above, Financial Covenants below and~~ Note 1820—Debt~~—Credit~~ ~~Facility~~ for further discussion ~~of our Credit Facility~~.

~~Capital-Structuring~~Collateral ~~Transactions~~Postings. ~~In light of our probable covenant non-compliance, we are attempting to amend or replace our existing Credit Facility.~~ We ~~may~~use ~~also~~a ~~seek~~significant ~~additional~~portion ~~sources~~ of ~~liquidity in order to ensure that we have sufficient cash available to meet~~ our ~~operating~~capital ~~needs. These~~resources ~~additional~~in ~~sources~~the ofform ~~liquidity could include asset sales, public or private issuances~~ of ~~debt, equity or equity-linked securities,, debt for equity swaps, or any combination of these. Matters to be considered include depressed or dilutive prices for assets,~~ cash ~~interest expense, covenant compliance~~ and ~~maturity~~letters ~~profile,~~of ~~all~~credit to besatisfy ~~balanced~~counterparty ~~with~~collateral ~~an attempt to maintain adequate liquidity~~demands. ~~The~~ ~~receptiveness~~These ofcounterparty ~~the~~collateral ~~traditional~~demands ~~capital~~reflect ~~markets~~our tonon-investment angrade ~~offering~~credit ofratings ~~debt or equity securities cannot be assured~~ and ~~may~~counterparties' beviews ~~negatively~~of ~~impacted by, among other things, the going concern emphasis paragraph in~~ our ~~most~~financial ~~recent~~condition ~~audit~~and ~~report,~~ability ~~recent changes~~ to ~~our~~satisfy ~~senior management and Dynegy’s Board of Directors,~~ our ~~non-investment~~performance ~~grade credit ratings~~obligations, ~~significant~~as ~~debt~~well ~~maturities,~~as ~~business~~commodity ~~prospects~~prices and other factors. ~~beyond~~The ~~our~~following ~~control,~~table ~~including~~summarizes ~~current~~our ~~and~~collateral ~~projected~~postings ~~market~~to ~~conditions. Any~~third ~~issuance~~parties ~~of equity~~ by ~~Dynegy~~legal ~~likely~~entity ~~would~~at ~~have~~September ~~other~~7, ~~effects as well~~2012, ~~including stockholder dilution~~December 31, 2011 and ~~our ability to issue debt securities may be limited by our financing agreements~~December 31, ~~including our Credit Facility~~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

_______________________________________________________________________________


(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

Table of Contents

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. ~~Dynegy’s~~ Our ~~and DHI’s~~ cash flow ~~provided~~used byin operations totaled $~~423~~1 million for the twelve months ended December 31, ~~2010~~2011. During the period, our power generation business provided positive cash flow from operations of $~~938~~348 million from the operation of our power generation facilities, ~~primarily~~offset ~~reflecting~~by ~~positive earnings for the period and approximately $290 million of cash received from our futures clearing manager. The receipt of this cash is partly due to lower commodity prices and~~ a ~~reduction~~use of ~~margin requirements; the remaining~~ cash ~~was returned as a result~~ of ~~the posting of~~ $85349 million offrom ~~short-term~~corporate ~~investments in substitute of cash. Corporate~~ and other operations ~~included a use of cash of approximately $515 million by Dynegy and DHI,~~ primarily due to interest payments to service debt, ~~and~~employee ~~general~~related payments and ~~administrative~~restructuring ~~expenses~~costs.

~~Dynegy’s~~Our cash flow provided by operations totaled $~~135~~423 million for the twelve months ended December 31, ~~2009~~2010. ~~DHI’s~~ ~~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~~ 938 million~~. Cash~~ ~~provided~~from by the ~~operations~~operation of our power generation facilities, ~~was~~primarily ~~partly~~reflecting ~~offset~~positive byearnings afor ~~$173~~the ~~million~~period ~~increase~~and inapproximately ~~cash~~$290 million ~~collateral postings. Other included a use~~ of cash ofreceived ~~approximately~~from ~~$584~~our ~~million~~futures ~~and~~clearing ~~$567~~manager. ~~million~~The byreceipt ~~Dynegy~~of ~~and~~this ~~DHI,~~cash ~~respectively,~~was ~~primarily~~partly due to ~~interest~~lower ~~payments~~commodity toprices ~~service~~and ~~debt~~a ~~and~~reduction ~~general~~of ~~and~~margin ~~administrative~~requirements; ~~expenses. Dynegy’s~~the ~~operating~~remaining cash ~~flow~~was ~~also~~returned ~~reflected~~as a result of the ~~payment~~posting of $19 85 million toof LSshort-term ~~Power~~investments in ~~conjunction~~lieu ~~with~~of ~~the~~cash. ~~dissolution~~Corporate and other operations included a use of ~~DLS~~cash ~~Power~~of ~~Holdings~~approximately $515 million, primarily due to interest payments to service debt and ~~DLS~~general ~~Power~~and ~~Development~~administrative expenses.

50Our 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.

~~TABLE~~Future OFOperating ~~CONTENTS~~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.

Dynegy’s and DHI’s cash flow provided by operations totaled $319 million for the twelve months ended December 31, 2008. During the period, our power generation business provided positive cash flow from the operations of our power generation facilities of $869 million, reflecting positive earnings for the period, partly offset by additional collateral requirements due to an increase in the volume of our hedging positions and increased payments associated with our DNE leveraged lease. Please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease for further discussion of the DNE lease payments. Other included a use of approximately $550 million in cash primarily due to interest payments to service debt, general and administrative expenses and a $17 million legal settlement payment, partially offset by interest income.

Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the price of natural gas and its correlation to power prices, the cost of coal and fuel oil, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, our ability to achieve the cost savings contemplated in our cost reduction programs and the level of our ability to capture value associated with commodity price volatility. Given current forward commodity price curves, our future operating cash flows are likely to be insufficient to fund our planned capital expenditure program and our debt service requirements.

Collateral Postings. We use a significant portion of our capital resources, in the form of cash, short-term investments and letters of credit, to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. At December 31, 2010, we had approximately $75 million of our cash collateral postings and $57 million of our letter of credit collateral postings related to our hedging activities. The following table summarizes our consolidated collateral postings to third parties by line of business at March 3, 2011, December 31, 2010 and December 31, 2009:

	March 3, 2011		December 31, 2010		December 31, 2009
	(in millions)
By Business:
Generation business	$	459	$	377	$	638
Other (1)		85		85		189
Total	$	544	$	462	$	827
By Type:
Cash and short-term investments (2)	$	152	$	87	$	291
Letters of credit		392		375		536
Total	$	544	$	462	$	827

(1) March 3, 2011 and December 31, 2010 reflect the reduction of $102 million of capacity and corresponding outstanding letters of credit due to the deconsolidation and subsequent sale of our interest in PPEA Holding. Please read Note 2—Summary of Significant Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.

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

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The change in letters of credit postings from December 31, 2009 to December 31, 2010 and to March 3, 2011 are primarily related to a $102 million decrease due to the removal of the PPEA letter of credit as a result of the deconsolidation and subsequent sale of our interest in PPEA Holding and lower commodity prices. Collateral postings of cash and short-term investments also decreased from December 31, 2009 to December 31, 2010 due to lower commodity prices and a reduction of margin requirements during 2010. Collateral postings increased from December 31, 2010 to March 3, 2011 due to an increase in margin requirements in 2011.

In addition to cash and letters of credit posted as collateral, we have granted additional permitted first priority liens on the assets currently subject to first priority liens under our Credit Facility as collateral under certain of our commodity derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under the Credit Facility. The fair value of our commodity derivatives collateralized by first priority liens, netted by counterparty, included liabilities of $20 million, $30 million and $31 million at March 3, 2011, December 31, 2010 and December 31, 2009, respectively.

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

Investing Activities

Capital Expenditures. We continue to tightly manage our operating costs and capital expenditures. We had approximately $~~333~~196 million, $~~612~~333 million and $~~611~~ 612 million in capital expenditures during the twelve months ended December 31, ~~2010~~2011, ~~2009~~2010 and ~~2008~~2009, respectively. Our capital spending by reportable segment was as follows:

	December 31,
	2010		2009		2008
	(in millions)
GEN-MW	$	300	$	533	$	530
GEN-WE		19		45		29
GEN-NE		8		28		36
Other		6		6		16
Total	$	333	$	612	$	611

~~Capital~~Table ~~spending in our GEN-MW segment primarily consisted~~ of environmental and maintenance capital projects, as well as approximately $104 million and $203 million spent on development capital related to the Plum Point Project during the years ended December 31, 2009 and 2008, respectively. Capital spending in our GEN-WE and GEN-NE segments primarily consisted of maintenance projects.Contents

We expect capital expenditures for 2011 to approximate $265 million, which is comprised of $213 million, $14 million, $35 million and $3 million in GEN-MW, GEN-WE, GEN-NE and Other, respectively. The $213 million of spending planned for GEN-MW includes approximately $145 million of environmental expenditures, of which approximately $140 million is related to the Midwest Consent Decree, approximately $53 million is related to maintenance on our coal and natural gas facilities, and approximately $15 million is related to capitalized interest. Other spending primarily includes maintenance capital projects and environmental projects. The capital budget is subject to revision as opportunities arise or circumstances change. Our ability to fund these capital expenditures is dependent on our access to sufficient liquidity; see Going Concern above.



	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

52_______________________________________________________________________________

~~TABLE~~(1) OFOnly ~~CONTENTS~~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.

~~The~~Capital ~~Midwest~~spending ~~Consent Decree was finalized~~ in ~~July~~our ~~2005. It~~Coal ~~prohibits~~segment usprimarily ~~from~~consisted ~~operating certain~~ of ~~our~~environmental ~~power~~and ~~generating~~maintenance ~~facilities after certain dates unless specified emission control equipment is installed. Our long-term~~ capital ~~expenditures in the GEN-MW segment will be significantly impacted by the Midwest Consent Decree. We anticipate our total costs associated with the Midwest Consent Decree~~ projects, ~~which~~as wewell ~~expect~~as ~~to incur through 2013, to be~~ approximately $~~960~~ 104 million, ~~which~~spent ~~includes~~on ~~approximately~~development ~~$730~~capital ~~million~~related ~~spent~~ to ~~date. This~~the ~~estimate,~~Plum ~~which~~Point isProject ~~broken~~during ~~down~~the by year ~~below~~ended December 31, ~~includes~~2009. aCapital ~~number~~spending ofin ~~assumptions about uncertainties that are beyond~~ our ~~control. For~~Gas ~~instance,~~and weDNE ~~have~~segments ~~assumed~~primarily ~~for~~consisted ~~purposes~~ of ~~this~~maintenance ~~estimate that labor and material costs will increase at four percent per year over the remaining project term~~projects. ~~The~~ ~~following are the estimated remaining capital expenditures required to comply with the Midwest Consent Decree:~~

2011		2012		2013
		(in millions)
$	140	$	80	$	10

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.

IfIn ~~the~~2005, ~~costs~~we ofsettled ~~these~~a ~~capital~~lawsuit ~~expenditures~~filed ~~become~~by ~~great~~the ~~enough~~EPA toand ~~render~~ the ~~operation~~United States Department of Justice in the ~~affected~~U.S. ~~facility~~District orCourt ~~facilities~~for ~~uneconomical,~~the weSouthern ~~could,~~District atof ~~our~~Illinois ~~option,~~that ~~cease~~alleged toviolations ~~operate~~of the ~~facility~~Clean orAir ~~facilities~~Act and ~~forego~~related ~~these~~federal ~~capital~~and ~~expenditures~~Illinois ~~without~~regulations ~~incurring~~concerning ~~any~~certain ~~further~~maintenance, ~~obligations~~repair ~~under~~and ~~the~~replacement ~~Midwest~~activities at our Baldwin generating station. A consent decree (the “Consent Decree”) was finalized in July 2005. ~~Further,~~ Among ifother provisions of the Consent Decree, we ~~fail~~are required to ~~meet~~not operate certain ~~performance~~of ~~standards~~our ~~under~~power ~~the~~generating ~~Midwest~~facilities after specified dates unless certain emission control equipment is installed. As of June 30, 2012, only Baldwin Unit 2 has material Consent Decree ~~our~~work ~~production~~yet ~~may~~to be ~~affected Please~~performed, ~~read~~which ~~Note~~is ~~22—Commitments~~scheduled ~~and~~to ~~Contingencies—Other~~be ~~Commitments~~completed ~~and~~by ~~Contingencies—Midwest~~the ~~Consent~~end ~~Decree~~of ~~for~~2012. We ~~further~~have ~~discussion~~spent approximately $902 million through June 30, 2012 related to these Consent Decree projects.

~~Please~~The ~~read~~SPDES ~~Note~~permit 1renewal ~~—Organization~~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 ~~Operations~~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—~~Going~~Chapter ~~Concern~~11 Cases for further discussion regarding the Roseton lease.

~~The~~Asset ~~SPDES~~Dispositions. Proceeds ~~permits~~from ~~renewal~~asset ~~application~~sales atin ~~our~~2009 ~~Roseton~~totaled ~~power~~$1,095 million. ~~generating~~Of ~~facility and~~ the ~~NPDES~~total ~~permit~~$1,476 million atin ~~our~~cash ~~Moss~~proceeds ~~Landing~~received ~~power~~at ~~generating~~the ~~facility~~closing ~~have~~of ~~been~~the ~~challenged~~LS byPower ~~local~~Transactions, ~~environmental~~$990 million ~~groups~~related ~~which~~to ~~contend~~ the ~~existing~~disposition ~~once-through~~of ~~water~~assets, ~~cooling~~including ~~systems~~our ~~currently~~interest in ~~place~~the ~~should~~Sandy beCreek ~~replaced~~Project. ~~with~~We ~~closed-cycle~~also ~~cooling~~received ~~systems. A~~$175 million ~~decision~~from tothe ~~install~~release aof ~~closed-cycle~~restricted ~~cooling~~cash ~~system~~on atour ~~the~~consolidated ~~Roseton~~balance orsheets ~~Moss~~that ~~Landing~~had ~~facilities~~been ~~would~~used beto ~~made~~support onour afunding ~~case-by-case~~commitment ~~basis~~to ~~considering~~the ~~all~~Sandy ~~relevant~~Creek ~~factors~~Project. atPlease ~~such~~read ~~time~~Note 5—Dispositions, ~~including~~Contract ~~any~~Terminations ~~relevant~~and ~~costs~~Discontinued orOperations—Dispositions ~~applicable~~and ~~remediation~~Contract ~~requirements. If~~Terminations—LS ~~mandated~~Power ~~installation~~Transactions offor ~~closed-cycle~~further ~~cooling~~information. ~~systems~~The atremaining ~~either~~$214 million of ~~these~~cash ~~facilities~~received ~~would~~upon ~~result~~closing inthe aLS ~~material~~Power ~~capital~~Transactions ~~expenditure~~related ~~that~~to ~~renders~~ the ~~operation~~issuance of a$235 million ~~plant~~of ~~uneconomical,~~notes wepayable ~~could, at our option,~~ and ~~subject~~is toincluded ~~any~~in ~~applicable~~Financing ~~financing~~Activities. ~~agreements~~Please orread ~~other~~"—Financing ~~obligations,~~Activities" ~~reduce~~below ~~operations~~and orNote ~~cease~~21—Related toParty ~~operate~~Transactions—Transactions ~~such~~with ~~facility~~LS ~~and~~Power ~~forego~~for ~~these~~further ~~capital expenditures~~discussion.

~~Please~~Additionally, ~~read~~during ~~Item~~2009, 7.we ~~Management’s~~sold ~~Discussion~~the ~~and~~Heard ~~Analysis~~County ofpower ~~Financial~~generation ~~Condition~~facility ~~and~~for ~~Results~~approximately of$105 million, ~~Operations—Liquidity~~net ~~and Capital Resources—Disclosure~~ of ~~Contractual~~transaction ~~Obligations and Contingent Financial Commitments—Off-Balance Sheet Arrangements—DNE Leveraged Lease for further discussion of early lease termination payments~~costs. Please read Note 225—~~Commitments and Contingencies—Legal Proceedings—Roseton State Pollutant Discharge Elimination System Permit~~Dispositions, ~~and~~Contract ~~—Commitments~~Terminations and ~~Contingencies~~Discontinued Operations—~~Legal~~Discontinued ~~Proceedings~~Operations—~~Moss~~Heard ~~Landing~~County ~~National Pollutant Discharge Elimination System Permit~~ for further discussion.

~~Asset~~Other ~~Dispositions. Proceeds~~Investing ~~from asset sales in 2009 totaled $652 million and $1,095 million for Dynegy and DHI, respectively~~Activities. Of Cash ~~the~~inflows ~~total $936 million and $1,476 million in cash proceeds received by Dynegy and DHI, respectively, at the closing of the LS Power Transactions, $547 million and $990 million~~ related to ~~the~~maturities ~~disposition~~ of ~~assets,~~short-term ~~including~~investments ~~our~~for ~~interest in~~ the ~~Sandy~~twelve ~~Creek~~months ~~Project,~~ended ~~for Dynegy and DHI~~December 31, ~~respectively. We~~2011 ~~also~~totaled ~~received~~ $~~175~~419 million ~~from the release of restricted cash on our consolidated balance sheets that was used to support our funding commitment to the Sandy Creek Project~~. ~~Please~~ ~~read~~Cash ~~Note~~outflows ~~4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions—LS Power Transactions~~ for ~~further~~purchases ~~information. The remaining $214 million~~ of ~~cash~~short-term ~~received~~investments ~~upon~~during ~~closing~~ the LStwelve ~~Power~~months ~~Transactions~~ended ~~relates~~December 31, to2011 ~~the~~totaled ~~issuance of~~ $~~235~~244 million ~~of notes payable, and is included in Financing Activities~~. ~~Please read “—Financing Activities” below and Note 19—Related Party Transactions 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 4—Dispositions, Contract Terminations and Discontinued Operations—Discontinued Operations—Heard County for further discussion.42

53Table of Contents

~~TABLE~~Cash OFinflows ~~CONTENTS~~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.

~~Proceeds~~Cash ~~from~~inflows ~~asset sales in 2008 totaled $451 million, net of transaction costs,~~ related to ~~the~~short-term ~~sales~~investments ofduring the ~~Rolling~~year ~~Hills~~ended ~~power generating facility~~December 31, ~~Calcasieu~~2009 ~~power~~totaled ~~generating~~$16 ~~facility~~million, ~~the~~reflecting ~~NYMEX~~a ~~shares~~distribution ~~and~~of ~~seats,~~our ~~and~~short-term ~~the beneficial interest in Oyster Creek~~investments.

~~Consistent~~There ~~with~~was ~~industry~~a ~~practice,~~$222 wemillion ~~regularly~~cash ~~evaluate~~inflow ~~our~~related ~~generation~~to ~~fleet~~restricted ~~based~~cash ~~primarily~~balances onduring ~~geographic~~the ~~location,~~twelve ~~fuel~~months ~~supply~~ended December 31, ~~market~~2011 ~~structure,~~primarily ~~market~~due ~~recovery~~to ~~expectations,~~(i) the ~~regulatory~~release orof ~~legislative~~$850 million ~~risks~~upon ~~and~~the ~~cash~~termination ~~flows. We~~of ~~consider~~the ~~divestitures~~Company's offormer ~~assets~~Fifth ~~where~~Amended ~~the~~and ~~balance~~Restated ofCredit Agreement, (ii) the ~~above~~release ~~factors~~of ~~suggests~~$43 million ~~that~~upon ~~such~~the ~~assets’~~completion ~~earnings~~of ~~potential~~the isSithe ~~limited~~Tender orOffer, ~~that~~(iii) the ~~benefits~~return ~~that~~of ~~can~~$75 bemillion ~~captured~~cash ~~through~~collateral aand ~~divestiture outweigh~~ (iv) the ~~benefits~~release of ~~continuing~~$50 million related to ~~own~~the ~~and~~expiration ~~operate~~of ~~such~~a ~~assets. As~~security ~~future~~and ~~operating~~deposit ~~cash~~agreement. ~~flows~~These ~~are~~decreases ~~likely~~in torestricted becash ~~insufficient~~were topartially ~~fund~~offset ~~our~~by ~~planned~~increases ~~capital~~of ~~expenditure program~~$662 million, ~~lease~~$103 ~~obligations~~ million and ~~our~~$27 million ~~debt~~associated ~~service~~with ~~requirements,~~the ~~additional~~DPC ~~asset~~Credit ~~divestures~~Agreement, ~~will~~the beDMG ~~considered~~Credit toAgreement ~~supplement~~and ~~our~~a ~~liquidity~~DH ~~position,~~Letter ~~potentially~~of atCredit ~~terms~~Reimbursement ~~not~~and ~~favorable~~Collateral toAgreement, usrespectively.

~~Other~~There ~~Investing~~was ~~Activities. Cash~~also ~~inflows~~a ~~related to short-term investments during the year ended December 31, 2010 totaled~~ $~~326~~441 million ~~and~~cash ~~$310~~outflow ~~million~~as ~~for~~a ~~Dynegy~~result ~~and DHI, respectively, reflecting maturities and early redemptions~~ of ~~short-term investments. Cash outflows related to purchases of short-term investments during~~ the ~~year~~DMG ~~ended~~Transfer ~~December~~on ~~31,~~September ~~2010 totaled $508 million and $477 million for Dynegy and DHI~~1, ~~respectively~~2011.

~~Cash~~There ~~inflows~~was a $15 million cash outflow related to ~~short-term~~our ~~investments~~funding ~~during~~commitment obligation under the ~~year~~PPEA ~~ended~~Sponsor ~~December~~Support ~~31,~~Agreement ~~2009~~and ~~totaled~~a $173 million ~~and~~cash ~~$16~~outflow ~~million~~due ~~for~~to ~~Dynegy~~changes ~~and~~in ~~DHI,~~restricted ~~respectively,~~cash ~~reflecting~~balances aduring ~~distribution~~the ~~from~~year ~~our~~ended ~~short-term~~December 31, ~~investments~~2010. ~~Cash~~ ~~outflows~~There ~~related~~was toa ~~short-term~~$190 ~~investments~~million cash inflow during the year ended December 31, ~~2008~~2009 ~~totaled~~related ~~$27~~to ~~million~~changes ~~and~~in ~~$25~~restricted ~~million~~cash ~~for~~balances ~~Dynegy~~primarily ~~and~~due ~~DHI,~~to ~~respectively,~~the asrelease aof ~~result~~$175 million of arestricted ~~reclassification~~cash ~~from~~that ~~cash~~was ~~equivalents~~used to ~~short-term~~support ~~investments~~our funding commitment to the Sandy Creek Project.

~~Dynegy~~Other ~~made~~included $1610 million ~~in contributions to DLS Power Holdings during the year ended December 31, 2008. We received a distribution of approximately $7 million~~ and ~~repayment of approximately~~ $3 million of anproperty ~~affiliate~~insurance ~~receivable~~claim ~~upon~~proceeds ~~the sale of a partial interest in Sandy Creek~~ during the ~~year~~twelve months ended December 31, ~~2008. Please~~2011 ~~read~~and ~~Note~~2009, ~~15—Variable Interest Entities—Sandy Creek for further discussion~~respectively.

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 for both Dynegy and DHI. There was a $190 million cash inflow during the year ended December 31, 2009 for both Dynegy and DHI, 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. There was an $80 million cash inflow during the year ended December 31, 2008 due to changes in restricted cash balances primarily due to a reduction of our cash collateral as a result of SCEA’s sale of an 11 percent undivided interest in the Sandy Creek Project, the release of restricted cash and the use of restricted cash for the ongoing construction of the Plum Point project, partially offset by interest income.

DHI’s affiliate transactions during the year ended December 31, 2010 included $2 million. DHI’s affiliate transactions during the year ended December 31, 2009 included $97 million related to the LS Power Transactions. Dynegy repurchased 245 million of its Class B shares with a fair value of $443 million (based on a share price of $9.05 on November 30, 2009, as adjusted for the 1-for-5 reverse stock split of Dynegy’s common stock that became effective on May 25, 2010) from LS Power by exchanging assets owned by DHI for the shares. In order to effect this exchange, Dynegy paid $540 million in cash to a subsidiary of LS Power in exchange for the shares, immediately following which a separate subsidiary of LS Power paid $540 million of cash to DHI in exchange for the assets. The $97 million represents the difference between the $540 million of cash received by DHI and the $443 million fair value of the shares received by Dynegy.

Other included $3 million and $7 million of insurance proceeds received during the years ended December 31, 2009 and 2008, respectively. Additionally, included in Other for Dynegy for the year ended December 31, 2008 is $4 million of proceeds from the liquidation of an investment.

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Financing Activities

Historical Cash Flow from Financing Activities. ~~Dynegy’s~~ Cash ~~and~~flow ~~DHI’s~~provided ~~net~~by ~~cash~~financing ~~used~~activities intotaled ~~financing~~$375 ~~activities~~million during the twelve months ended December 31, ~~2010~~2011. ~~totaled~~Proceeds ~~$69~~from ~~million~~long-term ~~due~~borrowings ~~to the payments~~ of $622,022 million, innet ~~aggregate~~of ~~principal~~$44 ~~amount~~million onof ~~our~~debt ~~Sithe~~issuance ~~9.00~~costs, ~~percent~~consisted ~~secured bonds due 2013 and $6 million~~ of ~~financing fees.~~:

~~Dynegy’s~~• ~~net~~$1,078 ~~cash~~million ~~used~~of incash ~~financing~~proceeds ~~activities~~from ~~during~~ the ~~twelve months ended December 31~~$1,100 ~~2009 totaled $608~~ million~~. Repayments~~ ofDPC ~~borrowings~~Credit ~~were $890 million, and consisted of the following:~~Agreement;

●• $~~421~~588 million inof ~~aggregate~~cash ~~principal~~proceeds ~~amount~~from onthe ~~our~~$600 ~~6.875~~million ~~percent~~DMG ~~senior~~Credit ~~unsecured notes due 2011 (“2011 Notes”)~~Agreement; and

●• $~~412~~400 million infrom ~~aggregate~~a ~~principal~~borrowing ~~amount~~under onthe ~~our~~revolving ~~8.75~~portion ~~percent~~of ~~senior~~our ~~unsecured~~former ~~notes~~Fifth ~~due~~Amended ~~2012~~and ~~(“2012~~Restated ~~Notes”);~~Credit ~~and~~Agreement.

●These ~~$57~~proceeds ~~million~~were inpartially ~~aggregate~~offset ~~principal~~by ~~amount~~repayments onof ~~our~~borrowings ~~Sithe~~of ~~9.00~~$1,626 ~~percent~~million, ~~secured~~which ~~bonds~~consisted ~~due~~of ~~2013.~~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 ~~the~~an ~~Credit~~amendment ~~Facility~~of ~~Amendment~~our ~~No.~~former 4Fifth Amended and Restated Credit Agreement.

~~DHI’s~~Summarized ~~net~~Debt ~~cash~~and ~~used~~Other inObligations. The ~~financing~~following ~~activities~~table ~~during~~depicts ~~the~~our ~~twelve~~third ~~months~~party ~~ended~~debt ~~December 31~~obligations, ~~2009~~and ~~totaled $1,193 million. This included~~ the ~~net~~extent ~~$608~~to ~~million~~which ~~used~~they inare ~~repayments~~secured ~~and~~as ~~extinguishment costs, net~~ of ~~borrowings,~~December ~~incurred by Dynegy~~31, as2011 ~~set~~and ~~forth above, as well as $585 million in aggregate dividend payments to Dynegy.~~2010:

Dynegy’s net cash provided by financing activities during the twelve months ended December 31, 2008 totaled $148 million and DHI’s net cash provided by financing activities during the twelve months ended December 31, 2008 totaled $146 million. The cash provided by financing activities primarily related to $192 million of proceeds from borrowings under the PPEA Credit Agreement Facility, partly offset by a $45 million principal payment on our 9.00 percent Sithe secured bonds due 2013.



	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

55_______________________________________________________________________________

~~TABLE~~(1) OFOur ~~CONTENTS~~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.

~~Summarized~~(2) ~~Debt~~Represents ~~and~~present ~~Other~~value ~~Obligations. The~~of ~~following~~future ~~table~~lease ~~depicts~~payments ~~our~~associated ~~consolidated~~with ~~third party debt obligations, including~~ the ~~present~~leases ~~value~~ of the ~~DNE~~Roseton ~~leveraged~~and ~~lease~~Danskammer ~~payments~~facilities discounted at 10 percent at December 31, ~~and~~2010. In December 2011, the ~~extent~~Bankruptcy toCourt ~~which~~entered ~~they~~a ~~are~~stipulated ~~secured~~order asapproving the rejection of ~~December~~the ~~31,~~leases. ~~2010~~For additional discussion please read Note 3—Chapter 11 Cases and ~~2009:~~"Contractual Obligations" below.

	December 31, 2010			December 31, 2009
	(in millions)
First secured obligations	$	918		$	918
Unsecured obligations		3,644			3,645
Lease obligations (1)		590			626
Total corporate obligations		5,152			5,189
PPEA and Sithe secured non-recourse obligations (2)		225			1,031
Total obligations		5,377			6,220
Less: Lease obligations (1)		(590	)		(626	)
Other (3)		(13	)		(12	)
Total notes payable and long-term debt (4)	$	4,774		$	5,582


(3)	Consists of net discounts on debt.

(1) Represents present value of future lease payments associated with the DNE lease financing discounted at 10 percent.

(2) Includes PPEA’s non-recourse project financing of $644 million and tax-exempt bonds of $100 million as of December 31, 2009. Reflects reduction of $744 million as of January 1, 2010 due to the deconsolidation and subsequent sale of our interest in PPEA Holding. Please read Note 2—Summary of Significant Accounting Policies—Accounting Policies Adopted—Variable Interest Entities for further discussion.

(3) Consists of net discounts on debt of $13 million and $12 million at December 31, 2010 and 2009, respectively.


(4)	Does not include letters of credit.

Please read Note 1820—Debt for further discussion of these items. Our consolidated debt maturity profile as of December 31, ~~2010~~2011, ~~includes~~excluding ~~$148~~the ~~million~~senior notes and debentures that are subject to compromise in ~~2011~~the bankruptcy process, ~~$164~~as of December 31, 2011 includes $7 million in 2012, $~~1,002~~ 7 million in 2013, ~~zero~~$6 million in 2014, $~~772~~ 6 million in 2015, ~~and approximately~~ $21,~~688~~ 050 million ~~thereafter. Maturities~~in ~~for~~2016 ~~2011~~and ~~represent~~zero ~~principal~~thereafter, ~~payments~~all onof ~~our~~which ~~Senior~~relate ~~Unsecured~~to ~~Notes due 2011 and~~ the ~~Sithe~~DPC ~~Senior~~Credit ~~Notes~~Agreement.

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

56The 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

~~TABLE OF CONTENTS~~44

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

Period Ended:	(i) Secured Debt: EBITDA	(ii) EBITDA: Consolidated Interest Expense
	No greater than:	No less than:
December 31, 2010	3.50 : 1	1.30 : 1
March 31, 2011	3.50 : 1	1.35 : 1
June 30, 2011	3.50 : 1	1.40 : 1
September 30, 2011	3.25 : 1	1.60 : 1
December 31, 2011	3.00 : 1	1.60 : 1
Thereafter	2.50 : 1	1.75 : 1

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

WeFinancial ~~are~~Covenants. Following inthe ~~compliance~~termination ~~with~~of ~~these~~DH's ~~covenants~~Fifth asAmended ofand ~~December~~Restated 31Credit Agreement on August 5, ~~2010~~2011, we are no longer subject to any financial covenants.

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

Using the latest available forward commodity price curves and considering our current hedging contracts, we project that it is likely that we will not be able to comply with the EBITDA to Consolidated Interest Expense covenant contained in our Credit Facility, particularly in the third and fourth quarters of 2011. Please see Going Concern above for further discussion.

Subject to certain exceptions, DHI and its relevant subsidiaries are subject to restrictions on asset sales, incurring additional indebtedness, limitations on investments and certain limitations on dividends and other payments with respect to capital stock. Please read Note 18—Debt—Credit Facility for further discussion of our amended Credit Facility.

For additional discussion of factors that may affect our ability to continue as a going concern and the potential consequences of our failure to do so, please see Item 1A—Risk Factors.

Dividends on Dynegy Common Stock. Dividend payments on Dynegy’s common stock are at the discretion of its Board of Directors and subject to limits contained in our Credit Facility and applicable law. Dynegy did not declare or pay a cash dividend on its common stock for the year ended December 31, 2010 and it does not expect to pay a dividend on its common stock in the foreseeable future.

Credit Ratings

Our credit rating status is currently “"non-investment grade”;" ~~our senior unsecured debt is rated “CCC” by Standard & Poor’s, “Caa2” by Moody’s,~~ and ~~“CCC” by Fitch. On March 1, 2011, Standard & Poor’s downgraded~~ our ~~corporate~~current ~~family~~ ratings toare “CCC” from “B-” based on near-term risk of covenant default under the Credit Facility and the recently announced Board of Directors and management restructuring. The agency also reduced our senior secured bank facilities rating to “B-” from “B+”, and senior unsecured debt rating to “CCC” from “B-”, while removing all ratings from credit watch with negative implications. The Standard & Poor's rating outlook is negative. On October 1, 2010, Moody’s issued a rating action to conclude their prior review. The corporate family rating was downgraded to “Caa1”; the senior secured rating downgraded to “B1”; and the senior unsecured rating was confirmed at “Caa2.” The Moody's rating outlook is negative. On November 24, 2010, Fitch removed the ratings watch and downgraded the issuer default rating for Dynegy Inc. and Dynegy Holdings Inc. to “CCC” from “B-”; reduced our senior secured bank facilities to “B+” from “BB-”; and reduced our senior unsecured debt to “CCC” from “B”. The Fitch rating outlook remains negative. The downgrades did not trigger any obligations under our financing arrangements; however, as ~~a result of the March 1, 2011 Standard & Poor's downgrade, we have received demands to post additional collateral in support of certain of our operational agreements in 2011.~~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

~~TABLE OF CONTENTS~~_______________________________________________________________________________


(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 ~~our~~the contractual obligations of the Company and its consolidated subsidiaries as of December 31, ~~2010~~2011. Cash obligations reflected are not discounted and do not include accretion or dividends.

	Expiration by Period
	Total		Less ~~than~~than1 1 Year		1 –- 3 Years		3 - 5 Years		More ~~than~~than5 5 Years
	(in millions)
Long-term debt (including current portion)	$	4,774	$	148	$	1,166	$	772	$	2,688
Debt subject to compromise	$	3,570	$	88	$	—	$	1,832	$	1,650
Interest payments on debt		1,798		357		635		514		292
Interest payments on debt subject to compromise	1,763		278		548		409		528
Operating leases		925		138		363		305		119
Long-term debt (including current portion)	1,076		7		13		1,056		—
Coal commitments (1)		647		215		262		170		—
Interest payments on debt	464		101		199		164		—
Capacity payments		156		35		68		47		6
Coal commitments (1)	449		179		184		86		—
Interconnection obligations		17		1		2		2		12
Operating leases	378		324		35		12		7
Construction service agreements		314		56		79		101		78
Capacity payments	257		39		78		55		85
Pension funding obligations		53		12		41		—		—
Interconnection obligations	16		1		2		2		11
Other obligations		87		26		29		21		11
Construction service agreements	258		29		95		94		40
Total contractual obligations	$	8,771	$	988	$	2,645	$	1,932	$	3,206
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) ~~are~~include ~~included~~approximately $3.6 billion in ~~the~~senior ~~December~~notes ~~31,~~and ~~2010~~debentures ~~consolidated~~issued ~~balance~~by ~~sheet. Please~~the ~~read~~Company ~~Note~~that ~~18—Debt~~are ~~for~~subject ~~further~~to ~~discussion.~~

Interest Payments on Debt. Interest payments on debt represent periodic interest payment obligations associated with our long-term debt (including current portion). Please read Note 18—Debt for further discussion.45

~~Operating~~Table ~~Leases. Operating~~of leases includes the minimum lease payment obligations associated with our DNE leveraged lease. Please read “—Liquidity and Capital Resources—Off-Balance Sheet Arrangements—DNE Leveraged Lease” for further discussion. Amounts also include minimum lease payment obligations associated with office and office equipment leases.Contents

Incompromise ~~addition, we are 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~~bankruptcy ~~party agreements are approximately $14 million each year for the years 2011 through 2012, and approximately $17 million in aggregate for the period from 2013 through lease expiration~~process. ~~The~~ ~~charter~~Please ~~party~~read ~~rates~~Note ~~payable~~3—Chapter ~~under~~11 ~~the~~Cases ~~two charter party agreements vary in accordance with market-based rates for similar shipping services. The $14 million~~ and ~~$17~~Note ~~million~~19—Liabilities ~~amounts~~Subject 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. We have sub-chartered both VLGCs to aCompromise ~~wholly~~for ~~owned~~further ~~subsidiary of Transammonia Inc~~discussion. The terms of the sub-charters are identical to the terms of the original charter agreements. We continue to rely on the sub-charters with a subsidiary of Transammonia to satisfy the obligations of our two charter party agreements. To date, the subsidiary of Transammonia has complied with the terms of the sub-charter agreements.

58Interest 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.

~~TABLE~~Long-Term OFDebt ~~CONTENTS~~(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.

~~Coal~~Interest ~~Commitments. At~~Payments ~~December~~on ~~31,~~Debt. Interest ~~2010,~~payments weon ~~had~~debt ~~contracts~~represent inestimated ~~place~~periodic tointerest ~~purchase~~payment ~~coal~~obligations ~~for~~associated ~~various of our generation facilities~~ with ~~minimum~~the ~~commitments~~DPC ofCredit ~~$647 million~~Agreement. ~~Obligations~~ ~~related~~Please toread ~~the~~Note ~~purchase~~20—Debt—DPC ofCredit ~~coal~~Agreement ~~are~~for ~~$636~~further ~~million through 2015, and obligations related to the transportation are $11 million through 2013~~discussion.

~~Capacity~~Coal ~~Payments~~Commitments. ~~Capacity~~ At ~~payments~~December 31, ~~include~~2011, ~~fixed~~our ~~obligations~~subsidiaries ~~associated~~had ~~with~~contracts ~~transmission,~~in ~~transportation~~place ~~and~~to ~~storage~~purchase ~~arrangements~~coal ~~totaling~~for ~~approximately~~various generation facilities. Obligations related to the purchase of the coal are $~~156~~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.

~~Interconnection~~Operating ~~Obligations~~Leases. ~~Interconnection~~ Operating ~~obligations~~leases ~~represent~~include an$300 million, ~~obligation~~which ~~with~~represented ~~respect~~our best estimate of the amount of the allowed claim related to ~~interconnection~~the ~~services~~termination ~~for~~of ~~our~~the ~~Ontelaunee~~DNE ~~facility. This~~lease ~~agreement~~and ~~expires~~is subject to compromise in ~~2027~~the bankruptcy process as of December 31, 2011. ~~Our~~ ~~obligation~~Please ~~under~~read ~~this~~Note ~~agreement~~3—Chapter is11 ~~approximately~~Cases $1and ~~million~~Note ~~per~~19—Liabilities ~~year~~Subject ~~through~~to ~~the~~Compromise ~~term~~for offurther ~~the~~discussion. ~~contract~~Operating leases also includes minimum lease payment obligations associated with office and office equipment leases.

~~Construction~~In ~~Service~~addition, ~~Agreements~~a subsidiary of the Company is party to two charter party agreements relating to two VLGCs previously utilized in our former global liquids business. ~~Construction~~ ~~service~~The aggregate minimum base commitments of the charter party agreements ~~represent~~are ~~obligations~~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 ~~respect~~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 ~~long~~a wholly-~~term~~owned ~~plant~~subsidiary ~~maintenance~~of Transammonia Inc. The terms of the sub-charters are identical to the terms of the original charter agreements. ~~Our~~ ~~obligation~~The ~~under~~subsidiary ~~these~~of the Company relies on the sub-charters with a subsidiary of Transammonia to satisfy the obligations of the two charter party agreements. isTo ~~approximately~~date, ~~$314~~the ~~million~~subsidiary of Transammonia has complied with the terms of the sub-charter agreements.

~~Pension~~Capacity ~~Funding Obligations~~Payments. ~~Amounts~~ Capacity payments include ~~estimated~~fixed ~~defined benefit pension funding~~ obligations ~~for~~associated ~~2011—$12~~with ~~million~~transmission, ~~2012—$23~~transportation ~~million~~ and ~~2013—$18~~storage ~~million. Although~~arrangements wetotaling ~~expect~~approximately ~~to continue to incur funding obligations subsequent to 2013, we cannot confidently estimate the amount of such obligations at this time and, therefore, have not included them in the table above~~$257 million. ~~Please read Note 24—Employee Compensation, Savings and Pension Plans—Pension and Other Post-Retirement Benefits—Obligations and Funded Status for further discussion.~~

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.

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