Edgar Filing: DYNEGY INC.

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2011

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

For the transition period from to

Commission file number: 001-33443

DYNEGY INC.

(Exact name of registrant as specified in its charter)

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

1000 Louisiana, Suite 5800
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer o		Accelerated filer x

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

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

Indicate the number of shares outstanding of our classes of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 122,710,776 shares outstanding as of November 8, 2011.

Table of Contents

DYNEGY INC.

TABLE OF CONTENTS

		Page
PART I. FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets:
September 30, 2011 and December 31, 2010		4
Condensed Consolidated Statements of Operations:
For the three and nine months ended September 30, 2011 and 2010		5
Condensed Consolidated Statements of Cash Flows:
For the three and nine months ended September 30, 2011 and 2010		6
Condensed Consolidated Statements of Comprehensive Income (Loss):
For the three and nine months ended September 30, 2011 and 2010		7
Notes to Condensed Consolidated Financial Statements		8

Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	45
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	74
Item 4.	CONTROLS AND PROCEDURES	75

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS	76
Item 1A.	RISK FACTORS	76
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	79
Item 3.	Defaults Upon Senior Securities	80
Item 6.	EXHIBITS	81

Table of Contents

DEFINITIONS

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

ASC		Accounting Standards Codification
ASU		Accounting Standards Update
BACT		Best available control technology
BART		Best available retrofit technology
BTA		Best technology available
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		The California Independent System Operator
CAMR		Clean Air Mercury Rule
CARB		California Air Resources Board
CAVR		The Clean Air Visibility Rule
CCR		Coal Combustion Residuals
CEQA		California Environmental Quality Act
CERCLA		The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
CO2		Carbon Dioxide
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
DH		Dynegy Holdings, LLC (formerly known as Dynegy Holdings Inc.)
DMSLP		Dynegy Midstream Services L.P.
EBITDA		Earnings before interest, taxes, depreciation and amortization
EGU		Electric generating unit
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
GAAP		Generally Accepted Accounting Principles of the United States of America
GEN Finance		Dynegy Gen Finance Company, LLC
GHG		Greenhouse Gas
HAPs		Hazardous air pollutants, as defined by the Clean Air Act
ICC		Illinois Commerce Commission
IMA		In-market asset availability
ISO		Independent System Operator
ISO-NE		Independent System Operator New England
MACT		Maximum achievable control technology
MGGA		Midwest Greenhouse Gas Accord
MGGRP		Midwestern Greenhouse Gas Reduction Program
MISO		Midwest Independent Transmission System Operator, Inc.
MMBtu		One million British thermal units
MW		Megawatts
MWh		Megawatt hour
NOL		Net operating loss
NOx		Nitrogen oxide
NPDES		National Pollutant Discharge Elimination System
NRG		NRG Energy, Inc.
NSPS		New Source Performance Standard
NYISO		New York Independent System Operator
NYSDEC		New York State Department of Environmental Conservation
OAL		Office of Administrative Law
OTC		Over-the-counter
PJM		PJM Interconnection, LLC
PPEA		Plum Point Energy Associates, LLC
PPEA Holding		Plum Point Energy Associates Holding Company, LLC
PSD		Prevention of significant deterioration
RACT		Reasonably available control technology
RCRA		Resource Conservation and Recovery Act
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must Run
SEC		U.S. Securities and Exchange Commission
SIP		State Implementation Plan
SO2		Sulfur dioxide
SPDES		State Pollutant Discharge Elimination System
VaR		Value at Risk
VIE		Variable Interest Entity
WCI		Western Climate Initiative

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)

	September 30, 2011			December 31, 2010
ASSETS
Current Assets
Cash and cash equivalents	$	881		$	291
Restricted cash and investments	164			81
Short-term investments	—			106
Accounts receivable, net of allowance for doubtful accounts of $31 and $32, respectively	180			230
Accounts receivable, affiliates	—			1
Inventory	105			121
Assets from risk-management activities	2,016			1,199
Deferred income taxes	4			12
Broker margin account	22			80
Prepayments and other current assets	208			123
Total Current Assets	3,580			2,244
Property, Plant and Equipment	8,749			8,593
Accumulated depreciation	(2,571		)	(2,320		)
Property, Plant and Equipment, Net	6,178			6,273
Other Assets
Restricted cash and investments	633			859
Assets from risk-management activities	136			72
Intangible assets	104			141
Other long-term assets	475			424
Total Assets	$	11,106		$	10,013

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	166		$	134
Accrued interest	118			36
Accrued liabilities and other current liabilities	95			109
Liabilities from risk-management activities	2,099			1,138
Notes payable and current portion of long-term debt (Note 10)	3,357			148
Short term debt, affiliates (Note 10)	200			—
Total Current Liabilities	6,035			1,565
Long-term debt	1,656			4,426
Long-term debt, affiliates	—			200
Long-Term Debt	1,656			4,626
Other Liabilities
Liabilities from risk-management activities	159			99
Deferred income taxes	454			641
Other long-term liabilities	315			336
Total Liabilities	8,619			7,267
Commitments and Contingencies (Note 9)
Stockholders’ Equity
Common Stock, $0.01 par value, 420,000,000 shares authorized at September 30, 2011 and December 31, 2010; 123,316,599 and 121,687,198 shares issued and outstanding at September 30, 2011 and December 31, 2010, respectively	1			1
Additional paid-in capital	6,073			6,067
Subscriptions receivable	(2		)	(2		)
Accumulated other comprehensive loss, net of tax	(50		)	(53		)
Accumulated deficit	(3,464		)	(3,196		)
Treasury stock, at cost, 729,190 and 628,014 shares at September 30, 2011 and December 31, 2010, respectively	(71		)	(71		)
Total Stockholders’ Equity	2,487			2,746
Total Liabilities and Stockholders’ Equity	$	11,106		$	10,013

See the notes to condensed consolidated financial statements.

Table of Contents

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Revenues	$	516		$	775		$	1,347		$	1,872
Cost of sales	(298		)	(334		)	(801		)	(873		)

Gross margin, exclusive of depreciation shown separately below	218			441			546			999
Operating and maintenance expense, exclusive of depreciation shown separately below	(107		)	(110		)	(323		)	(341		)
Depreciation and amortization expense	(73		)	(96		)	(274		)	(261		)
Impairment and other charges	(1		)	(134		)	(2		)	(135		)
General and administrative expenses	(32		)	(51		)	(97		)	(110		)

Operating income (loss)	5			50			(150		)	152
Losses from unconsolidated investments	—			—			—			(34		)
Interest expense	(107		)	(92		)	(285		)	(272		)
Debt extinguishment costs	(21		)	—			(21		)	—
Other income and expense, net	—			1			4			3

Loss from continuing operations before income taxes	(123		)	(41		)	(452		)	(151		)
Income tax benefit (Note 12)	48			17			184			80

Loss from continuing operations	(75		)	(24		)	(268		)	(71		)
Income from discontinued operations, net of taxes	—			—			—			1

Net loss	$	(75	)	$	(24	)	$	(268	)	$	(70	)

Loss Per Share (Note 13):
Basic loss per share:
Loss from continuing operations	$	(0.61	)	$	(0.20	)	$	(2.20	)	$	(0.59	)
Income from discontinued operations	—			—			—			0.01

Basic loss per share	$	(0.61	)	$	(0.20	)	$	(2.20	)	$	(0.58	)

Diluted loss per share:
Loss from continuing operations	$	(0.61	)	$	(0.20	)	$	(2.20	)	$	(0.59	)
Income from discontinued operations	—			—			—			0.01

Diluted loss per share	$	(0.61	)	$	(0.20	)	$	(2.20	)	$	(0.58	)

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

See the notes to condensed consolidated financial statements.

Table of Contents

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)

	Nine Months Ended September 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(268	)	$	(70	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization	291			273
Impairment and other charges	2			135
Losses from unconsolidated investments, net of cash distributions	—			34
Risk-management activities	139			(123		)
Deferred income taxes	(183		)	(79		)
Debt extinguishment costs	21			—
Other	37			55
Changes in working capital:
Accounts receivable	48			11
Inventory	11			15
Broker margin account	(26		)	353
Prepayments and other assets	(46		)	7
Accounts payable and accrued liabilities	87			111
Changes in non-current assets	(67		)	(51		)
Changes in non-current liabilities	4			(1		)

Net cash provided by operating activities	50			670

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(185		)	(270		)
Unconsolidated investments	—			(15		)
Maturities of short-term investments	475			143
Purchases of short-term investments	(284		)	(428		)
Decrease (increase) in restricted cash and investments	142			(53		)
Other investing	11			9

Net cash provided by (used in) investing activities	159			(614		)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs of $44 and $5, respectively	2,022			(5		)
Repayments of borrowings	(1,623		)	(31		)
Debt extinguishment costs	(21		)	—
Net proceeds from issuance of capital stock	3			—

Net cash provided by (used in) financing activities	381			(36		)

Net increase in cash and cash equivalents	590			20
Cash and cash equivalents, beginning of period	291			471

Cash and cash equivalents, end of period	$	881		$	491

Other non-cash investing activity:
Non-cash capital expenditures	$	(1	)	$	10

See the notes to condensed consolidated financial statements.

Table of Contents

DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)

	Three Months Ended September 30,
	2011			2010

Net loss	$	(75	)	$	(24	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $1 and zero)	1			1

Other comprehensive income, net of tax	1			1

Comprehensive loss	$	(74	)	$	(23	)

	Nine Months Ended September 30,
	2011			2010

Net loss	$	(268	)	$	(70	)
Amortization of unrecognized prior service cost and actuarial loss (net of tax expense of $2 and $1)	3			3

Other comprehensive income, net of tax	3			3

Comprehensive loss	$	(265	)	$	(67	)

See the notes to condensed consolidated financial statements.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Note 1—Organization and Basis of Presentation

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. Unless the context indicates otherwise, throughout this report, the terms “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries. The year-end condensed consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2010, filed on March 8, 2011, which we refer to as our “Form 10-K”.

Reorganization

In August 2011, we completed a reorganization of our subsidiaries (the “Reorganization”), whereby, (i) substantially all of our coal-fired power generation facilities are held by Dynegy Midwest Generation, LLC (“DMG”), (ii) substantially all of our natural gas-fired power generation facilities are held by Dynegy Power, LLC (“DPC”), an indirect wholly owned subsidiary of Dynegy Holdings, LLC (“DH”) and (iii) 100 percent of the ownership interests of Dynegy Northeast Generation, Inc., the entity that indirectly holds the equity interest in the subsidiaries that operate the Roseton and Danskammer power generation facilities, including the leased units, are held by DH. 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 located in the Midwest, totaling 3,132 MW of generating capacity. The DPC and DMG asset portfolios were designed to be separately financeable. DPC and DMG are bankruptcy remote, thereby accommodating the financings reflected by the credit agreements and to provide us with greater flexibility in our efforts to address leverage and liquidity issues and to realize the value of our assets. Please read Note 10—Debt—New Credit Agreements for discussion of the new credit agreements. Our remaining assets (including our leasehold interests in the Danskammer and Roseton facilities) are not a part of either DPC or DMG.

DMG Acquisition. On September 1, 2011, Dynegy and Dynegy Gas Investments, LLC (“DGIN”), a direct wholly owned subsidiary of DH, entered into a Membership Interest Purchase Agreement pursuant to which DGIN sold 100 percent of the outstanding membership interests of Dynegy Coal HoldCo, LLC (“Coal HoldCo”), a wholly owned subsidiary of DGIN, to Dynegy (the “DMG Acquisition”). Our management and Board of Directors, as well as DGIN’s board of managers, concluded that the fair value of the acquired equity stake in Coal HoldCo at the time of the transaction was approximately $1.25 billion, after taking into account all debt obligations of DMG, including in particular DMG’s $600 million, five-year senior secured term loan facility. Dynegy provided this value to DGIN in exchange for Coal HoldCo through Dynegy’s obligation, pursuant to an Undertaking Agreement (the “Undertaking Agreement”), to make certain specified payments over time which coincide in timing and amount with the payments of principal and interest that DH is obligated to make under a portion of its $1.1 billion of 7.75 percent senior unsecured notes due 2019 and its $175 million of 7.625 percent senior debentures due 2026. The Undertaking Agreement does not provide any rights or obligations with respect to any outstanding DH notes or debentures, including the notes and debentures due in 2019 and 2026.

Immediately after closing the DMG Acquisition, DGIN assigned its right to receive payments under the Undertaking Agreement to DH in exchange for a promissory note (the “Promissory Note”) in the amount of $1.25 billion that matures in 2027 (the “Assignment”). The Promissory Note bears annual interest at a rate of 4.24 percent, which will be payable upon maturity. As a condition to Dynegy’s consent to the Assignment, the Undertaking Agreement was amended and restated to be between DH and Dynegy and to provide for the reduction of Dynegy’s obligations if the outstanding principal amount of any of DH’s $3.5 billion of outstanding notes and debentures is decreased as a result of any exchange offer, tender offer or other purchase or repayment by Dynegy or its subsidiaries (other than DH and its subsidiaries, unless Dynegy guarantees the debt securities of DH 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.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

There was no impact on our condensed consolidated financial position, results of operations or cash flows as the transaction was between Dynegy and its wholly owned subsidiaries.

Overview of Bankruptcy Remote and Ring-Fencing Measures. The Reorganization created new companies, some of which are “bankruptcy remote.” In addition, as part of the Reorganization, some companies within our portfolio were reorganized into ring-fenced groups. The special purpose bankruptcy remote entities entered into limited liability company operating agreements, which contain certain restrictions including not allowing the “bankruptcy remote” or “ring-fenced” companies to act as an agent for a non ring-fenced company. Furthermore, bankruptcy remote and ring-fenced companies are required to present themselves to the public as separate entities and correct misunderstandings that they are not separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Additionally, they pay liabilities from their own funds, they conduct business in their own names (other than any business relating to the trading activities of us and our subsidiaries), they observe a higher level of formalities, and they have restrictions on pledging their assets for the benefit of certain other persons.

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

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

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

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

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Going Concern

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

As noted above, we recently completed the Reorganization and in connection therewith, certain of our subsidiaries (DPC and DMG) entered into two new credit agreements on August 5, 2011 which resulted in the repayment in full and termination of commitments under our former Fifth Amended and Restated Credit Agreement. While these new credit agreements were designed to provide sufficient operating liquidity for DPC and DMG for the foreseeable future, they contain certain restrictions related to distributions by DPC and DMG to their respective parent companies, including us and DH. Please read Note 10—Debt—New Credit Agreements for further discussion.

Also as noted above, on September 1, 2011, we completed the DMG Acquisition, pursuant to which Dynegy acquired 100 percent of the outstanding membership interests of Coal HoldCo from a wholly owned subsidiary of DH. As a result of that transaction, Dynegy has an unsecured obligation of $1.25 billion to DH under the Undertaking Agreement, and DH has an unsecured obligation of $1.25 billion to DGIN under the Promissory Note.

On November 7, 2011, DH still had significant debt service requirements in connection with its outstanding notes and debentures, and there were significant payment obligations related to the leasehold interests in the Danskammer and Roseton facilities. On that date, DH and four of its wholly owned subsidiaries, Dynegy Northeast Generation, Inc., Hudson Power, L.L.C., Dynegy Danskammer, L.L.C. and Dynegy Roseton, L.L.C. (collectively, the “Debtor Entities”), filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of New York, Poughkeepsie Division (the “Chapter 11 Cases”). We and our subsidiaries, other than the five Debtor Entities, did not file voluntary petitions for relief and are not debtors under Chapter 11 of the Bankruptcy Code. Please see Note 15—Subsequent Events—Bankruptcy Filing for further information.

The Reorganization, DMG Acquisition, and Chapter 11 Cases represent steps in addressing our liquidity concerns. Over the next twelve months, under the strategic direction of the Finance and Restructuring Committee of our Board of Directors, we may participate in additional debt restructuring activities, which may include direct or indirect transfers of our subsidiaries’ equity interests, refinancing of existing debt and lease obligations, and/or further reorganizations of our subsidiaries as well as other similar initiatives. However, we cannot provide any assurances that we will be successful in accomplishing any such activities.

Our ability to continue as a going concern is dependent on many factors, including, among other things, the generation by DPC and DMG of sufficient positive operating results to enable DPC and DMG to make certain restricted distributions to their parents (as described in Note 10—Debt), the terms and conditions of an approved plan of reorganization that allows the Debtor Entities to emerge from bankruptcy, execution of any further restructuring strategies, and the successful execution of the company-wide cost reduction initiatives that are ongoing. The accompanying unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the foregoing uncertainties except for the reclassification of the DH Senior Notes and Debentures, including the Subordinated Capital Income Securities reflected as affiliated debt, and associated deferred financing costs due to the Chapter 11 Cases discussed above. Please read Note 10—Debt—Senior Notes and Debentures and Subordinated Capital Income Securities for further discussion.

Note 2—Accounting Policies

Use of Estimates

The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal and recurring nature that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors. The preparation of consolidated financial statements in conformity with generally accepted accounting principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things, (i) developing fair value assumptions, including estimates of future cash flows and discount rates, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets, (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and indemnifications, (vi) estimating various factors used to value our pension assets and liabilities and (vii) determining the primary beneficiary of variable interest entities (“VIEs”). Actual results could differ materially from our estimates.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Accounting Principles Not Yet Adopted

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

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

Note 3—Investments

The amortized cost basis, unrealized gains and losses and fair values of investments in available for sale investments is shown in the table below:

	Investments as of December 31, 2010
	Cost Basis		Gross Unrealized Gains		Gross Unrealized Losses		Fair Value
	(in millions)
Available for Sale investments:
Commercial Paper	$	45	$	—	$	—	$	45
Certificates of Deposit	20		—		—		20
Corporate Securities	6		—		—		6
U.S. Treasury and Government Securities (1)	120		—		—		120

Total—Dynegy	$	191	$	—	$	—	$	191

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

(1) Includes $85 million in Broker margin account on our unaudited condensed consolidated balance sheets in support of transactions with our futures clearing manager.

We did not have any investments as of September 30, 2011.

Note 4—Risk Management Activities, Derivatives and Financial Instruments

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

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

Many of our contractual arrangements are derivative instruments and must be accounted for at fair value. We also manage commodity price risk by entering into capacity forward sales arrangements, tolling arrangements, RMR contracts, fixed price coal purchases and other arrangements that do not receive fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase normal sales”. As a result, the gains and losses with respect to these arrangements are not reflected in the unaudited condensed consolidated statements of operations until the settlement dates.

Quantitative Disclosures Related to Financial Instruments and Derivatives

The following disclosures and tables present information concerning the impact of derivative instruments on our unaudited condensed consolidated balance sheets and statements of operations. In the table below, commodity contracts primarily consist of derivative contracts related to our power generation business that we have not designated as accounting hedges, that are entered into for purposes of economically hedging future fuel requirements and sales commitments and securing commodity prices. As of September 30, 2011, our commodity derivatives were comprised of both long and short positions; a long position is a contract to purchase a commodity, while a short position is a contract to sell a commodity. As of September 30, 2011, we had net long/(short) commodity derivative contracts outstanding in the following quantities:

Contract Type	Hedge Designation	Quantity		Unit of Measure	Net Fair Value
		(in millions)			(in millions)
Commodity contracts:
Electric energy (1)	Not designated	(26	)	MW	$	73
Natural gas (1)	Not designated	(25	)	MMBtu	$	(162	)
Heat rate derivatives	Not designated	(3)/27		MW/MMBtu	$	(18	)
Other (2)	Not designated	2		Misc.	$	1

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

(2) Comprised of emissions, coal, crude oil and fuel oil options, swaps and physical forwards.

Derivatives on the Balance Sheet. We execute a significant volume of transactions through futures clearing managers. Our daily cash payments (receipts) to (from) our futures clearing managers consist of three parts: (i) fair value of open positions (exclusive of options) (“Daily Cash Settlements”); (ii) initial margin requirements of open positions (“Initial Margin”); and (iii) fair value related to options (“Options”, and collectively with Daily Cash Settlements and Initial Margin, “Collateral”). We do not offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we do not elect to offset the fair value amounts recognized for the Daily Cash Settlements paid or received against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. As a result, our unaudited condensed consolidated balance sheets present derivative assets and liabilities, as well as related Collateral, as applicable, on a gross basis.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

We have used short-term investments to collateralize a portion of our collateral requirements. The broker required that we post approximately 103 percent of any collateral requirement collateralized with short-term investments. Accordingly, our Broker margin account included approximately $3 million related to this requirement at December 31, 2010. Additionally, we posted $7 million of short-term investments which were not utilized as collateral at December 31, 2010. There were no short-term investments in our Broker margin account at September 30, 2011.

In addition to the transactions we execute through the futures clearing managers, we also execute transactions through a bilateral counterparty. Our transactions with this counterparty are collateralized using only cash collateral. As of September 30, 2011, we had $41 million posted with this counterparty, which is included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets.

The following table presents the fair value and balance sheet classification of derivatives in the unaudited condensed consolidated balance sheet as of September 30, 2011, and December 31, 2010 segregated between designated, qualifying hedging instruments and those that are not, and by type of contract segregated by assets and liabilities.

Contract Type	Balance Sheet Location	September 30, 2011			December 31, 2010
		(in millions)
Derivatives designated as hedging instruments:
Derivative Assets:
Interest rate contracts	Assets from risk management activities	$	—		$	1

Total derivatives designated as hedging instruments		—			1

Derivatives not designated as hedging instruments:
Derivative Assets:
Commodity contracts	Assets from risk management activities	2,152			1,265
Interest rate contracts	Assets from risk management activities	—			5
Derivative Liabilities:
Commodity contracts	Liabilities from risk management activities	(2,258		)	(1,231		)
Interest rate contracts	Liabilities from risk management activities	—			(6		)

Total derivatives not designated as hedging instruments		(106		)	33

Total derivatives, net		$	(106	)	$	34

Impact of Derivatives on the Consolidated Statements of Operations

The following discussion and tables include the location and amount of gains and losses on derivative instruments in our unaudited condensed consolidated statements of operations for the three and nine months ended September 30, 2011 and 2010, segregated between designated, qualifying hedging instruments and those that are not, by type of contract.

Cash Flow Hedges. We may enter into financial derivative instruments that qualify, and that we may elect to designate, as cash flow hedges. Interest rate swaps have been used to convert floating interest rate obligations to fixed interest rate obligations. We had no cash flow hedges in place during the three and nine months ended September 30, 2011 and 2010.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Fair Value Hedges. We also enter into derivative instruments that qualify, and that we may elect to designate, as fair value hedges. We previously used interest rate swaps to convert a portion of our non-prepayable fixed-rate debt into floating-rate debt. These derivatives and the corresponding hedged debt matured April 1, 2011. During the three and nine months ended September 30, 2011 and 2010, there was no ineffectiveness from changes in the fair value of hedge positions and no amounts were excluded from the assessment of hedge effectiveness. During the three and nine months ended September 30, 2011 and 2010, there were no gains or losses related to the recognition of firm commitments that no longer qualified as fair value hedges.

The impact of interest rate swap contracts designated as fair value hedges and the related hedged item on our unaudited condensed consolidated statement of operations for the three and nine months ended September 30, 2011 and 2010 was immaterial for all periods.

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

For the three-month period ended September 30, 2011, our revenues included approximately $16 million of mark-to-market losses related to this activity compared to $132 million of mark-to-market gains in the same period in the prior year. For the nine months ended September 30, 2011, our revenues included approximately $143 million of mark-to-market losses related to this activity compared to $127 million of mark-to-market gains in the same period in the prior year.

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statements of operations for the three months ended September 30, 2011 and 2010 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross margin we expect to realize when the underlying physical transactions settle.

Derivatives Not Designated as	Location of Gain ( Loss) Recognized in Income on	Amount of Gain (Loss) Recognized in Income on Derivatives for the Three Months Ended September 30,
Hedging Instruments	Derivatives	2011			2010
		(in millions)
Commodity contracts	Revenues	$	(54	)	$	106

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

The impact of derivative financial instruments that have not been designated as hedges on our unaudited condensed consolidated statements of operations for the nine months ended September 30, 2011 and 2010 is presented below. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments. Therefore, this presentation is not indicative of the economic gross margin we expect to realize when the underlying physical transactions settle.

Derivatives Not Designated as Hedging	Location of Gain (Loss) Recognized in Income on	Amount of Gain (Loss) Recognized in Income on Derivatives for the Nine Months Ended September 30,
Instruments	Derivatives	2011			2010
		(in millions)
Commodity contracts	Revenues	$	(124	)	$	246

Interest rate contracts	Interest expense	—			(1		)

Note 5—Fair Value Measurements

The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2011 and December 31, 2010. These financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value as of September 30, 2011
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—	$	299		$	31		$	330
Natural gas derivatives	—		1,818			1			1,819
Other derivatives	—		3			—			3

Total	$	—	$	2,120		$	32		$	2,152

Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(245	)	$	(13	)	$	(258	)
Natural gas derivatives	—		(1,978		)	(4		)	(1,982		)
Heat rate derivatives	—		—			(17		)	(17		)
Other derivatives	—		(1		)	—			(1		)

Total	$	—	$	(2,224	)	$	(34	)	$	(2,258	)

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	Fair Value as of December 31, 2010
	Level 1		Level 2			Level 3			Total
	(in millions)
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—	$	526		$	77		$	603
Natural gas derivatives	—		613			5			618
Other derivatives	—		44			—			44

Total assets from commodity risk management activities	—		1,183			82			1,265
Assets from interest rate swaps	—		6			—			6
Short-term investments:
Commercial paper	—		45			—			45
Certificates of deposit	—		20			—			20
Corporate securities	—		6			—			6
U.S. Treasury and government securities (1)	—		120			—			120

Total short-term investments	—		191			—			191

Total	$	—	$	1,380		$	82		$	1,462

Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—	$	(311	)	$	(28	)	$	(339	)
Natural gas derivatives	—		(825		)	—			(825		)
Heat rate derivatives	—		—			(31		)	(31		)
Other derivatives	—		(36		)	—			(36		)

Total liabilities from commodity risk management activities	$	—	$	(1,172	)	$	(59	)	$	(1,231	)
Liabilities from interest rate swaps	—		(6		)	—			(6		)

Total	$	—	$	(1,178	)	$	(59	)	$	(1,237	)

(1) Includes $85 million in Broker margin account on our unaudited condensed consolidated balance sheets in support of transactions with our futures clearing manager.

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

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:

	Three Months Ended September 30, 2011
	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Total
	(in millions)
Balance at June 30, 2011	$	35		$	—		$	(23	)	$	12
Total losses included in earnings	(14		)	(3		)	(1		)	(18		)
Settlements	(3		)	—			6			3

Balance at September 30, 2011	$	18		$	(3	)	$	(18	)	$	(3	)

Unrealized losses relating to instruments held as of September 30, 2011	$	(4	)	$	(4	)	$	(4	)	$	(12	)

	Nine Months Ended September 30, 2011
	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Total
	(in millions)
Balance at December 31, 2010	$	49		$	5		$	(31	)	$	23
Total losses included in earnings	(22		)	(8		)	(1		)	(31		)
Settlements	(9		)	—			14			5

Balance at September 30, 2011	$	18		$	(3	)	$	(18	)	$	(3	)

Unrealized losses relating to instruments held as of September 30, 2011	$	(1	)	$	(7	)	$	(4	)	$	(12	)

	Three Months Ended September 30, 2010
	Electricity Derivatives			Natural Gas Derivatives		Heat Rate Derivatives			Total
	(in millions)
Balance at June 30, 2010	$	23		$	5	$	(23	)	$	5
Total gains included in earnings	27			—		5			32
Sales and settlements:
Sales	—			—		(1		)	(1		)
Settlements	(2		)	—		(4		)	(6		)

Balance at September 30, 2010	$	48		$	5	$	(23	)	$	30

Unrealized gains relating to instruments still held as of September 30, 2010	$	28		$	—	$	1		$	29

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

	Nine Months Ended September 30, 2010
	Electricity Derivatives			Natural Gas Derivatives		Heat Rate Derivatives			Interest Rate Swaps			Total
	(in millions)
Balance at December 31, 2009	$	6		$	5	$	17		$	(50	)	$	(22	)
Deconsolidation of Plum Point	—			—		—			50			50
Total gains included in earnings	70			—		15			—			85
Purchases, sales and settlements:
Purchases	1			—		2			—			3
Sales	(13		)	—		(22		)	—			(35		)
Settlements	(16		)	—		(35		)	—			(51		)

Balance at September 30, 2010	$	48		$	5	$	(23	)	$	—		$	30

Unrealized gains (losses) relating to instruments still held as of September 30, 2010	$	60		$	—	$	(3	)	$	—		$	57

Gains and losses (realized and unrealized) for Level 3 recurring items are included in Revenues on the unaudited condensed consolidated statements of operations. We believe an analysis of instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio. We did not have any transfers between Level 1, Level 2 and Level 3 for the three and nine months ended September 30, 2011 and 2010.

Nonfinancial Assets and Liabilities. The following table sets forth by level within the fair value hierarchy our fair value measurements with respect to nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis. These assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value Measurements as of September 30, 2010
	Level 1		Level 2		Level 3		Total		Total Losses
	(in millions)
Assets held and used	$	—	$	—	$	275	$	275	$	(135	)
Equity method investment	—		—		—		—		(37		)

Total	$	—	$	—	$	275	$	275	$	(172	)

During the nine months ended September 30, 2010, long-lived assets held and used were written down to their fair value of $275 million, resulting in pre-tax impairment charges of $135 million, which is included in Impairment and other charges on our unaudited condensed consolidated statements of operations. Please read Note 6—Impairment Charges for further discussion.

On January 1, 2010, we recorded an impairment of our investment in PPEA Holding as part of our cumulative effect of a change in accounting principle. We determined the fair value of our investment using assumptions that reflected our best estimate of third party market participants’ considerations based on the facts and circumstances related to our investment at that time. The fair value of our investment on January 1, 2010 was considered a Level 3 measurement because the fair value was determined based on probability weighted cash flows resulting from various alternative scenarios including no change in the financing structure, a restructuring of the project debt and insolvency. These scenarios and the related probability weighting were consistent with the scenarios used at December 31, 2009 in our long-lived asset impairment analysis. At March 31, 2010, we fully impaired our investment in PPEA Holding due to the uncertainty and risk surrounding PPEA’s financing structure. Please read Note 7—Impairment and Restructuring Charges—2010 Impairment Charges—Other in our Form 10-K.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

The carrying values of financial assets and liabilities (cash, accounts receivable, restricted cash and investments, short-term investments and accounts payable) not presented in the table below approximate fair values due to the short-term maturities of these instruments. The fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes for the periods ending September 30, 2011 and December 31, 2010, respectively.

	September 30, 2011						December 31, 2010
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
	(in millions)
Interest rate derivatives designated as fair value accounting hedges (1)	$	—		$	—		$	1		$	1
Interest rate derivatives not designated as accounting hedges(1)	—			—			(1		)	(1		)
Commodity-based derivative contracts not designated as accounting hedges (1)	(106		)	(106		)	34			34
Term Loan B, due 2013	—			—			(68		)	(67		)
Term Facility, floating rate due 2013	—			—			(850		)	(845		)
DPC Credit Agreement due 2016 (2)	(1,078		)	(1,081		)	—			—
DMG Credit Agreement due 2016 (3)	(588		)	(580		)	—			—
Senior Notes and Debentures:
6.875 percent due 2011 (4)	—			—			(80		)	(79		)
8.75 percent due 2012	(89		)	(69		)	(89		)	(87		)
7.5 percent due 2015 (5)	(771		)	(504		)	(768		)	(592		)
8.375 percent due 2016 (6)	(1,044		)	(643		)	(1,043		)	(777		)
7.125 percent due 2018	(172		)	(102		)	(172		)	(116		)
7.75 percent due 2019	(1,100		)	(682		)	(1,100		)	(728		)
7.625 percent due 2026	(171		)	(97		)	(171		)	(107		)
Subordinated Debentures payable to affiliates, 8.316 percent, due 2027	(200		)	(76		)	(200		)	(83		)
Sithe Senior Notes, 9.0 percent due 2013 (7)	—			—			(233		)	(233		)
Other (8)	—			—			191			191

(1)	Included in both current and non-current assets and liabilities on the unaudited condensed consolidated balance sheets.
(2)	Includes unamortized discounts of $22 million at September 30, 2011.
(3)	Includes unamortized discounts of $12 million at September 30, 2011.
(4)	Payment in full was made on April 1, 2011, which was the maturity date of this debt.
(5)	Includes unamortized discounts of $14 million and $17 million at September 30, 2011 and December 31, 2010, respectively.
(6)	Includes unamortized discounts of $3 million and $4 million at September 30, 2011 and December 31, 2010, respectively.
(7)	Includes unamortized premiums of $8 million at December 31, 2010.
(8)	Other represents short-term investments, including $85 million of short-term investments included in the Broker margin account, at December 31, 2010.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Note 6—Impairment Charges

Casco Bay Impairment. On August 13, 2010, Dynegy entered into a merger agreement with an affiliate of The Blackstone Group L.P. (“Blackstone”), pursuant to which Dynegy would be acquired and our stockholders would receive $4.50 per share in cash. On November 16, 2010, the merger agreement was amended to increase the merger consideration to $5.00 per share in cash. The merger agreement was not approved by our stockholders at the special stockholders’ meeting on November 23, 2010 and was subsequently terminated by the parties in accordance with the terms of the agreement.

In August 2010, in connection with the merger agreement, we determined it was more likely than not that our Moss Landing, Morro Bay, Oakland and Casco Bay facilities would be disposed of before the end of their previously estimated useful lives, as Blackstone had entered into a separate agreement to sell these facilities to a third party upon the closing of the merger agreement. Based on the terms of the merger agreement and our impairment analysis of the impact of such agreement on the recoverability of the carrying value of our long-lived assets, we recorded a pre-tax impairment charge of $134 million ($81 million after-tax) during the three months ended September 30, 2010 to reduce the carrying value of our Casco Bay facility and related assets to its fair value. This charge is included in Impairment and other charges in our consolidated statements of operations in the Gas segment. Please read Note 14—Segment Information for further discussion of changes to our reportable segments.

In performing the impairment analysis, we concluded that the assets Blackstone planned to sell to a third party did not meet the criteria of “held for sale”, as the agreement to sell these assets was a contractual arrangement between Blackstone and the third party. Management had not committed to any plan to dispose of these assets prior to the end of their previously estimated useful lives. As such, we assessed the recoverability of the carrying value of these certain assets using expected cash flows from the proceeds from the potential sale of these assets, probability weighted with the expected cash flow from continuing to hold and use the assets. We performed this analysis considering a range of likelihoods that management considered reasonable regarding whether the sale of these assets would be completed. In any of the scenarios within this range of the probabilities we considered reasonable, the expected undiscounted cash flows from the Moss Landing, Morro Bay and Oakland facilities were sufficient to recover their carrying values, while the expected undiscounted cash flows from the Casco Bay facility were not. Therefore, we recorded an impairment charge to reduce the carrying value of the Casco Bay facility and related assets to its estimated fair value. We determined the fair value of the facility based on assumptions that reflect our best estimate of third party market participants’ considerations, and corroborated these assumptions based upon the terms of the proposed sale of the facilities. The merger agreement ultimately did not receive stockholder approval, and at December 31, 2010, we no longer considered it more likely than not that these facilities would be disposed of before the end of their currently estimated useful lives.

Other. In the first quarter of 2010, as a result of uncertainty and risk surrounding PPEA’s financing structure, we recorded a pre-tax impairment charge of approximately $37 million to reduce the carrying value of our investment in PPEA Holding to zero. In the fourth quarter 2010, we sold our interest in this investment. Please read Note 14—Unconsolidated Investments in our Form 10-K for additional information.

Our impairment analysis of our generating assets is based on forward-looking projections of our estimated future cash flows based on discrete financial forecasts developed by management for planning purposes. These projections incorporate certain assumptions including forward power and capacity prices, forward fuel costs and costs of complying with environmental regulations. As additional information becomes available regarding the significant assumptions used in our analysis, we may conclude that it is necessary to update our impairment analyses in future periods to assess the recoverability of our assets and additional impairment charges could be required.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Note 7—Accumulated Other Comprehensive Loss

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

	September 30, 2011			December 31, 2010
	(in millions)
Cash flow hedging activities, net	$	3		$	3
Unrecognized prior service cost and actuarial loss, net	(53		)	(56		)

Accumulated other comprehensive loss, net of tax	$	(50	)	$	(53	)

Note 8—Variable Interest Entities

PPEA Holding Company, LLC. Until the sale of our interest on November 10, 2010, we owned an approximate 37 percent interest in PPEA Holding, which through PPEA, its wholly-owned subsidiary, owned an approximate 57 percent undivided interest in the Plum Point Project. On November 10, 2010, we completed the sale of our interest in PPEA Holding to one of the other investors in PPEA Holding. Please read Note 7—Impairment and Restructuring Charges—2010 Impairment Charges—Other in our Form 10-K.

Due to the uncertainty and risk surrounding PPEA’s financing structure as a result of events that occurred in 2010, we concluded that there was an other-than-temporary impairment of our investment in PPEA Holding and fully impaired our equity investment at March 31, 2010. As a result, we recorded an impairment charge of approximately $37 million for the three months ended March 31, 2010, which is included in Losses from unconsolidated investments in our unaudited condensed consolidated statements of operations. The impairment was a Level 3 non-recurring fair value measurement and reflected our best estimate of third party market participants’ considerations including probabilities related to restructuring of the project debt and potential insolvency. Please read Note 5—Fair Value Measurements for further discussion.

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

	Three Months Ended September 30, 2010
	Total			Equity Share
	(in millions)
Revenues	$	13		$	—
Operating income	3			—
Net loss	(20		)	—

	Nine Months Ended September 30, 2010
	Total			Equity Share
	(in millions)
Revenues	$	13		$	—
Operating income	1			—
Net income (loss)	(53		)	3

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

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Losses from unconsolidated investments for the nine months ended September 30, 2010 were $34 million, which includes an impairment loss of $37 million, discussed above. This impairment was partially offset by equity earnings of $3 million, comprised primarily of mark-to-market gains related to PPEA’s interest rate swaps, partly offset by financing expenses.

Note 9—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. Pursuant to the requirements of FASB ASC 450 and related guidance, we record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, and nature of damages sought and the probability of success. Management regularly reviews all new information with respect to each such contingency and adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals and that such differences could be material.

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

Bondholder Litigation. On September 21, 2011, an ad-hoc group of bondholders (the “Avenue Plaintiffs”) of DH filed a complaint in the Supreme Court of the State of New York, County of New York, captioned Avenue Investments, L.P. et al v. Dynegy Inc., Dynegy Holdings, LLC, Dynegy Gas Investments, LLC, Clint C. Freeland, Kevin T. Howell and Robert C. Flexon (Index No. 652599/11) (“Avenue Investments Matter”). The Avenue Plaintiffs challenge the September 2011 DMG Acquisition. On September 27, 2011, the successor indenture trustees under the Roseton and Danskammer Indenture Agreements (the “Indenture Trustee Plaintiffs”) filed a complaint in the Supreme Court of the State of New York, captioned The Successor Lease Indenture Trustee et al v. Dynegy Inc., Dynegy Holdings, LLC, Dynegy Gas Investments, LLC, E. Hunter Harrison, Thomas W. Elward, Michael J. Embler, Robert C. Flexon, Vincent J. Intrieri, Samuel Merksamer, Felix Pardo, Clint C. Freeland, Kevin T. Howell John Doe 1, John Doe 2, John Doe 3, Etc. (Index No. 652642/2011). The Indenture Trustee Plaintiffs similarly challenge the DMG Acquisition. Plaintiffs in both actions allege, among other claims, breach of contract, breach of fiduciary duties, and violations of prohibitions on fraudulent transfers in connection with the DMG Acquisition and also seek to have the DMG Acquisition set aside, and request unspecified damages as well as attorneys’ fees. We filed motions to dismiss the actions on October 31, 2011. On November 7, 2011, Dynegy, DH and the Consenting Noteholders (as defined in Note 15—Subsequent Events) agreed to enter into a stipulation that suspends the prosecution of the Consenting Noteholders’ claims in the Avenue Investments Matter.

On November 4, 2011, the owner-lessors of the Danskammer and Roseton facilities (the “Owner Lessor Plaintiffs”) filed a lawsuit in NY state court, captioned Resources Capital Management Corp., Roseton OL, LLC and Danskammer OL, LLC, v. Dynegy Inc., Dynegy Holdings, Inc., Dynegy Holdings, LLC, Dynegy Gas Investments, LLC, Thomas W. Elward, Michael J. Embler, Robert C. Flexon, E. Hunter Harrison, Vincent J. Intrieri, Samuel J. Merksamer, Felix Pardo, Clint. C. Freeland, Kevin T. Howell, Icahn Capital LP, and Seneca Capital Advisors, LLC, alleging, among other claims, that the Reorganization, the DPC and DMG Credit Agreements, and the DMG Acquisition constitute an integrated scheme involving fraudulent transfers, breach of contract, and breach of fiduciary duties, and seek a judgment to unwind all the transactions. We believe the plaintiffs’ complaints in all three lawsuits lack merit and we will continue to oppose their claims vigorously.

Reorganization Litigation. On July 21, 2011, certain holders of obligations with potential recourse rights to DH initiated legal proceedings seeking to enjoin our restructuring efforts disclosed on July 10, 2011. The lawsuits, Libertyview Credit Opportunities Fund, L.P. et al v. Dynegy Holdings, Inc., (Index No. 651998/11) in the Supreme Court of the State of New York (the “New York Action”) and Roseton OL, LLC and Danskammer OL, LLC v. Dynegy Holdings, Inc., (C.A. No. 6689-VCP) in the Court of Chancery of the State of Delaware (the “Delaware Action”), sought to enjoin the proposed reorganization based on purported breaches of guarantees issued by DH in connection with two sale-leaseback transactions in which DH’s subsidiaries, Dynegy Roseton, L.L.C. and Dynegy Danskammer, L.L.C., leased certain power-generating facilities. Shortly after filing, the New York Action was stayed pending resolution of the Delaware Action. The plaintiffs in the Delaware Action filed a motion for a temporary restraining order (“TRO”) to enjoin the Reorganization on July 21, 2011. DH opposed the motion by arguing, among other things, that the unambiguous language of the Guaranties permitted the reorganization. On July 29, 2011, the Delaware court denied the TRO in the Delaware Action, finding that plaintiffs had failed to show a likelihood of success on the merits, irreparable harm or that the balancing of the equities weighed in their favor. Thereafter, plaintiffs sought certification of an interlocutory appeal, which was denied by the Delaware Chancery Court on August 4, 2011 and subsequently denied by the Delaware Supreme Court on August 5, 2011. Following the Delaware Supreme Court’s action, plaintiffs in the Delaware action voluntarily dismissed their claims without prejudice. Thereafter, the New York action was dismissed without prejudice by the New York court on its own initiative.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Stockholder Litigation Relating to the Blackstone and Icahn Merger Agreements. In connection with the 2010 and 2011 terminations of the merger agreement with an affiliate of The Blackstone Group L.P. and the merger agreement with an affiliate of Icahn Enterprises L.P., respectively, numerous stockholder lawsuits and one stockholder derivative lawsuit previously filed in the District Courts of Harris County, Texas, the Southern District of Texas, and the Court of Chancery of the State of Delaware were dismissed. On March 28, 2011, plaintiff’s lead class counsel in the consolidated Texas state court actions filed a motion seeking attorneys’ fees and expenses. In July 2011, the Court granted the motion and awarded approximately $2 million in fees and expenses. We are appealing the decision.

Gas Index Pricing Litigation. We, several of our affiliates, our former joint venture affiliate and other energy companies were named as defendants in numerous lawsuits in state and federal court claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications in the 2000-2002 timeframe. Many of the cases have been resolved. All of the remaining cases contain similar claims that individually, and in conjunction with other energy companies, we engaged in an illegal scheme to inflate natural gas prices in four states by providing false information to natural gas index publications. In November 2009, following defendants’ motion for reconsideration, the court invited defendants to renew their motions for summary judgment on preemption of plaintiffs’ state law claims, which were filed shortly thereafter. Plaintiffs concurrently moved to amend their complaints to add federal claims. In October 2010, the court denied plaintiffs’ motion to amend.

On July 18, 2011, the Court granted defendants’ motions for summary judgment, thereby dismissing all of plaintiffs’ state law claims. Plaintiffs are appealing the decision to the Ninth Circuit Court of Appeals.

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

Native Village of Kivalina and City of Kivalina v. ExxonMobil Corporation, et al. In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska initiated an action in federal court in the Northern District of California against DH and 23 other companies in the energy industry. Plaintiffs claim that defendants’ emissions of GHG including CO2 contribute to climate change and have caused significant damage to a native Alaskan Eskimo village through increased vulnerability to waves, storm surges and erosion. In September 2009, the court dismissed all of the plaintiffs’ claims based on lack of subject matter jurisdiction and because plaintiffs lacked standing to bring the suit. Shortly thereafter, plaintiffs appealed to the Ninth Circuit. The appeal was fully briefed and in February 2011, the Ninth Circuit issued an order staying the scheduling of oral argument until the United States Supreme Court’s ruling in AEP v. Connecticut (“AEP”). On June 20, 2011, the Supreme Court issued its decision in AEP. The Court was equally divided by a vote of 4-4 on the question of whether the plaintiffs had standing to bring the suit and, therefore, affirmed the court’s exercise of jurisdiction. On the merits the Court ruled by a vote of 8-0 that the CAA and EPA action authorized by the Act displace any federal common law right to seek abatement of carbon dioxide emissions from fossil fuel-fired power plants. In August 2011, the Ninth Circuit lifted its stay of the Kivalina proceedings and scheduled oral argument on November 28, 2011. On October 26, 2011, the Ninth Circuit issued an order allowing any party to file a supplemental brief by November 4, 2011 addressing the significance of the Supreme Court’s decision in AEP. We believe the plaintiffs’ suit lacks merit and we will continue to oppose their claims vigorously.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Illinova Generating Company Arbitration. In May 2007, our subsidiary Illinova Generating Company (“IGC”) received an adverse award in an arbitration brought by Ponderosa Pine Energy, LLC (“PPE”). The award required IGC to pay PPE $17 million, which IGC paid in June 2007 under protest while simultaneously seeking to vacate the award in the District Court of Dallas County, Texas. In March 2010, the Dallas District Court vacated the award, finding that one of the arbitrators had exhibited evident partiality. PPE is appealing that decision to the Fifth District Court of Appeals in Dallas, Texas. Coincident with the appeal, IGC filed a claim against PPE seeking recovery of the $17 million plus interest. In September 2010, the Dallas District Court ordered PPE to deposit the $17 million principal in an interest-bearing escrow account jointly owned by IGC and PPE pending the Dallas Court of Appeals decision, which has not yet been issued. As a result of the uncertainty surrounding the outcome of PPE’s appeal, our receivable from PPE is fully reserved at September 30, 2011.

Other Commitments and Contingencies

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

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

· Roseton SPDES Permit — In April 2005, the NYSDEC issued a Draft SPDES Permit renewal for the Roseton plant. The permit is opposed by environmental groups challenging the BTA determination. In October 2006, various holdings in the administrative law judge’s ruling admitting the environmental group petitioners to party status and setting forth the issues to be adjudicated in the permit renewal hearing were appealed to the Commissioner of NYSDEC by the petitioners, NYSDEC staff and us. The permit renewal hearing will be scheduled after the Commissioner rules on those appeals. We believe that the petitioners’ claims lack merit and we plan to oppose those claims vigorously.

· Moss Landing NPDES Permit — The California Regional Water Quality Control Board (“Water Board”) issued an NPDES permit for the Moss Landing power generating facility in 2000 that did not require closed cycle cooling. A local environmental group challenged the BTA determination of the permit. The Water Board’s decision was affirmed by the Superior Court in 2004 and by the Court of Appeals in 2007. The Supreme Court of California granted review in March 2008 and held oral argument in May 2011. On August 15, 2011, the Supreme Court of California issued its decision in this case, affirming the appellate court’s decision upholding the NPDES permit issued for Moss Landing.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

Guarantees and Indemnifications

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. Related to the indemnifications discussed below, we have accrued approximately $1 million as of September 30, 2011.

LS Power Indemnities. In connection with the LS Power Transactions we agreed in the purchase and sale agreement to indemnify LS Power against claims regarding any breaches in our representations and warranties and certain other potential liabilities. Claims for indemnification shall survive until twelve months subsequent to closing with exceptions for tax claims, which shall survive for the applicable statute of limitations plus 30 days, and certain other representations and potential liabilities, which shall survive indefinitely. The indemnifications provided to LS Power are limited to $1.3 billion in total; however, several categories of indemnifications are not available to LS Power until the liabilities incurred in the aggregate are equal to or exceed $15 million and are capped at a maximum of $100 million. Further, the purchase and sale agreement provides in part that we may not reduce or avoid liability for a valid claim based on a claim of contribution. In addition to the above indemnities related to the LS Power Transactions, we have agreed to indemnify LS Power against claims related to the Riverside/Foothills Project for certain aspects of the project. Namely, LS Power has been indemnified for any disputes that arise as to ownership, transfer of bonds related to the project, and any failure by us to obtain approval for the transfer of the payment in-lieu of taxes program already in place. The indemnities related solely to the Riverside/Foothills Project are capped at a maximum of $180 million and extend until the earlier of the expiration of the tax agreement or December 26, 2026. At this time, we have incurred no significant expenses under these indemnities. Please read Note 4—Dispositions, Contract Terminations and Discontinued Operations—Dispositions and Contract Terminations—LS Power Transactions in our Form 10-K for further discussion.

West Coast Power Indemnities. In connection with the sale of our 50 percent interest in West Coast Power to NRG on March 31, 2006, an agreement was executed to allocate responsibility for managing certain litigation and provide for certain indemnities with respect to such litigation. The indemnification agreement in relevant part provides that NRG assumes responsibility for all defense costs and any risk of loss, subject to certain conditions and limitations, arising from a February 2002 complaint filed at FERC by the California Public Utilities Commission alleging that several parties, including West Cost Power subsidiaries, overcharged the State of California for wholesale power. FERC found the rates charged by wholesale suppliers to be just and reasonable; however, this matter was appealed and ultimately remanded back to FERC for further review. On May 24, 2011 and May 26, 2011, FERC issued two orders in these dockets. The first order denied the request of the California Parties for consolidation of various dockets and denied their request for summary disposition on market manipulation issues. The second order addressed treatment of settled parties and the scope of hearing issues in the ongoing proceedings.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Targa Indemnities. During 2005, as part of our sale of our midstream business (“DMSLP”), we agreed to indemnify Targa Resources, Inc. (“Targa”) against losses it may incur under indemnifications DMSLP provided to purchasers of certain assets, properties and businesses disposed of by DMSLP prior to our sale of DMSLP. We have incurred no material expense under these prior indemnities. We have recorded an accrual of less than $1 million for remediation of groundwater contamination at the Breckenridge Gas Processing Plant sold by DMSLP in 2001. The indemnification provided by DMSLP to the purchaser of the plant has a limit of $5 million.

Illinois Power Indemnities. Dynegy has indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power from recovering costs incurred in connection with purchased natural gas and investments in specified items. Although there is no absolute limitation on Dynegy’s liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses. Dynegy has made certain payments in respect of these indemnities following regulatory action by the ICC, and has established reserves for further potential indemnity claims. Further events, which fall within the scope of the indemnity, may still occur. However, Dynegy is not required to accrue a liability in connection with these indemnifications, as management cannot reasonably estimate a range of outcomes or at this time considers the probability of an adverse outcome as only reasonably possible. Dynegy intends to contest any proposed regulatory actions.

Black Mountain Guarantee. Through one of our subsidiaries, we hold a 50 percent ownership interest in Black Mountain (Nevada Cogeneration) (“Black Mountain”), in which our partner is a Chevron subsidiary. Black Mountain owns the Black Mountain power generation facility and has a power purchase agreement with a third party that extends through April 2023. In connection with the power purchase agreement, pursuant to which Black Mountain receives payments which decrease in amount over time, we agreed to guarantee 50 percent of certain payments that may be due to the power purchaser under a mechanism designed to protect it from early termination of the agreement. At September 30, 2011, if an event of default due to early termination had occurred under the terms of the mortgage on the facility entered into in connection with the power purchase agreement, we could have been required to pay the power purchaser approximately $54 million under the guarantee.

Other Indemnities. We entered into indemnifications regarding environmental, tax, employee and other representations when completing asset sales such as, but not limited, to the Rolling Hills, Calcasieu, CoGen Lyondell and Heard County power generating facilities. As of September 30, 2011, no claims have been made against these indemnities. There is no limitation on our liability under certain of these indemnities. However, management is unaware of any existing claims.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Note 10—Debt

Sithe Senior Notes

On August 26, 2011, Sithe/ Independence Funding Corporation (“Sithe”) commenced a cash tender offer (“Sithe Tender Offer”) to purchase Sithe’s outstanding $192 million in principal amount of 9.0 percent Secured Bonds due 2013 (“Sithe Senior Notes”). Sithe also solicited consents to certain proposed amendments to the indenture governing the Sithe Senior Notes. At the expiration of the early consent period on September 9, 2011, Sithe entered into a supplemental indenture, which eliminated or modified substantially all of the restrictive covenants, certain events of default and certain other provisions. On September 12, 2011, Sithe accepted for purchase all Sithe Senior Notes validly tendered prior to the consent date and satisfied and discharged the indenture and remaining Sithe Senior Notes. Also on September 12, 2011, Sithe/Independence Power Partners, LP (“SIPP”) filed with the New York State Public Service Commission (the “NYPSC”), and certain other parties, a verified petition for approval of financing, seeking NYPSC authorization for SIPP to grant liens/security interests in its assets and properties as collateral security for the DPC Credit Agreement (as defined below). We anticipate that the NYPSC will issue an order on the petition in December 2011 or January 2012. On the final payment date, September 26, 2011, Sithe accepted to purchase substantially all of the Sithe Senior Notes that were tendered after the consent date.

Sithe purchased the Sithe Senior Notes at a price of 108 percent of the principal amount plus consent fees. Total cash paid to purchase the Sithe Senior Notes, including fees and accrued interest, was $217 million, which was funded from proceeds from the DPC Credit Agreement (as defined and discussed below). We recorded a charge of approximately $16 million associated with this transaction, of which $21 million is included in Debt extinguishment costs offset by the write-off of $5 million of premiums included in Interest expense on our unaudited condensed consolidated statements of operations. As a result of the successful cash tender offer and consent solicitation, $43 million in restricted cash previously held at Sithe was returned to DPC when the transaction closed.

We also made scheduled repayments of the Sithe Senior Notes totaling $33 million during the second quarter 2011.

New Credit Agreements

On August 5, 2011, we completed the Reorganization of our legal entity structure to facilitate the execution of two new credit agreements. Please read Note 1—Organization and Basis of Presentation—Reorganization for further discussion. The new credit agreements, which were entered into on August 5, 2011, provided for a $1,100 million, five year senior secured term loan to DPC and a $600 million, five year senior secured term loan to DMG. As further discussed below, these new credit agreements limit the amount of distributions that can be made by DPC and DMG. DPC and DMG have restricted consolidated net assets of approximately $1,964 million and $2,709 million, respectively, as of September 30, 2011 as a result of these new credit agreements.

DPC Credit Agreement. DPC entered into a $1,100 million senior secured term loan (the “DPC Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch (“CS”), as Administrative Agent and as Collateral Trustee, Credit Suisse Securities (USA) LLC and Goldman Sachs Lending Partners LLC, as Joint Bookrunners and Joint Lead Arrangers, Barclays Capital, the investment banking division of Barclays Bank PLC, as Co-Manager, other agents named therein and other financial institutions party thereto as lenders.

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

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

The proceeds of the borrowing under the DPC Credit Agreement were used by DPC to (i) repay an intercompany obligation of a DPC subsidiary to DH and to repay certain outstanding indebtedness under our Fifth Amended and Restated Credit Agreement, (ii) fund cash collateralized letters of credit and provide cash collateral for existing and future collateral requirements, (iii) repay approximately $192 million of debt relating to Sithe Energies, Inc. (the intermediate project holding company that indirectly holds the Independence facility in New York), (iv) make a $200 million restricted payment to a parent holding company of DPC, (v) pay related transaction fees and expenses and (vi) fund additional cash to the balance sheet to provide the DPC asset portfolio with liquidity for general working capital and liquidity purposes.

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

The DPC Borrower Obligations, the DPC Guarantees and any Hedging/Cash Management Arrangements are secured by first priority liens on and security interests in 100 percent of the capital stock of DPC (as discussed below) and substantially all of the present and after-acquired assets of DPC and each DPC Guarantor (collectively, the “DPC Collateral”). Accordingly, such assets are only available for the creditors of DGIH and its subsidiaries. In September 2011, as discussed above, Sithe completed the Sithe Tender Offer. Following authorization from the NYPSC and certain other parties, the equity and assets of SIPP and Sithe will be subject to a lien in favor of DPC’s secured parties. Please read Sithe Senior Notes above for further discussion of the Sithe Tender Offer and related regulatory approvals.

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

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

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

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

The DPC Credit Agreement limits distributions to $135 million per year provided the borrower and its subsidiaries possess at least $50 million of cash and cash equivalents and short-term investments as of the date of the proposed distribution.

DMG Credit Agreement. DMG entered into a $600 million senior secured term loan (the “DMG Credit Agreement”) with CS as Administrative Agent and as Collateral Trustee, Credit Suisse Securities (USA) LLC and Goldman Sachs Lending Partners LLC, as Joint Bookrunners and Joint Lead Arrangers, Barclays Capital, the investment banking division of Barclays Bank PLC, as Co-Manager, other agents named therein, and other financial institutions party thereto as lenders.

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

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

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

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

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

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

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

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

The DMG Credit Agreement limits distributions to $90 million per year provided the borrower and its subsidiaries possess at least $50 million of cash and cash equivalents and short-term investments as of the date of the proposed distribution.

Letter of Credit Facilities. DPC entered into a $300 million fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with Barclays Bank PLC (“Barclays”) pursuant to which Barclays agrees to issue letters of credit at DPC’s request provided that DPC deposits in an account controlled by Barclays an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereof.

DPC also entered into a $215 million fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with CS pursuant to which CS agreed to issue letters of credit at DPC’s request provided that DPC deposits in an account controlled by CS an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereof.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

DMG entered into a $100 million fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with CS pursuant to which CS agreed to issue letters of credit at DMG’s request provided that DMG deposits in an account controlled by CS an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereof.

DH entered into a $26 million fully cash collateralized Letter of Credit Reimbursement and Collateral Agreement with CS pursuant to which CS agreed to issue letters of credit at DH’s request provided that DH deposits in an account controlled by CS an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereof.

DH’s Credit Facility

During the second quarter 2011, we borrowed $400 million under our former Fifth Amended and Restated Credit Agreement. This borrowing was repaid on August 5, 2011 in connection with the closing of the two new credit agreements entered into as part of the Reorganization. Please read Note 1—Organization and Basis of Presentation—Reorganization for further discussion. In addition, our former term facility of $850 million was repaid with current restricted cash and the term loan of $68 million was repaid using proceeds from the DPC Credit Agreement.

Senior Notes and Debentures and Subordinated Capital Income Securities

We made scheduled repayments on our Senior Notes and Debentures of $80 million during the second quarter 2011.

As permitted under the Subordinated Capital Income Securities indenture, we deferred our $8 million June 2011 payment of interest.

On September 15, 2011, we commenced offers to exchange (the “Exchange Offers”) up to $1,250 million principal amount of the outstanding notes, debentures and capital income securities (the “Old Notes”) of DH, our direct, wholly-owned subsidiary, for our new 10 percent Senior Secured Notes due 2018 (the “New Notes”) and cash. On November 3, 2011, we terminated the Exchange Offers. As a result of the termination, all of the previously tendered (and not validly withdrawn) Old Notes were not accepted for exchange and were promptly returned to the holders thereof.

On November 7, 2011, DH filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. Please see Note 15—Subsequent Events—Bankruptcy Filing for further information. Accordingly, we have reclassified DH’s outstanding Senior Notes and Debentures, including the Subordinated Capital Income Securities reflected as affiliated debt, and associated deferred financing costs from long-term to current at September 30, 2011 on our unaudited condensed consolidated balance sheets.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Restricted Cash and Investments

The following table depicts our restricted cash and investments:

	September 30, 2011		December 31, 2010
	(in millions)
DPC LC facilities (1)	$	530	$	—
DMG LC facility (1)	103		—
DH LC facility (1)	27		—
DPC Collateral Posting Account (2)	101		—
DMG Collateral Posting Account (2)	36		—
DH Credit facility (3)	—		850
Sithe Energy (4)	—		40
GEN Finance (5)	—		50

Total restricted cash and investments	$	797	$	940

(1)	Includes cash posted to support the letter of credit reimbursement and collateral agreements described above. Please read note 10—Debt—New Credit Agreements—LC Facilities for further discussion.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

(2)	Amounts are restricted and may be used for future collateral posting requirements or released per the terms of the applicable DPC and DMG Credit Agreements.
(3)	Included cash posted to support the letter of credit component of our former Fifth Amended and Restated Credit Agreement. The amount was used in the third quarter 2011 to repay the term facility under our former Fifth Amended and Restated Credit Agreement.
(4)	Included amounts related to the terms of the indenture governing the Sithe Senior Debt. These agreements were terminated as a result of the successful Sithe Tender Offer and the restricted cash was reclassified to cash and cash equivalents during the third quarter 2011.
(5)	Included amounts restricted under the terms of a security and deposit agreement associated with a collateral agreement and commodity hedges entered into by GEN Finance. These agreements were terminated and the $50 million held in restricted cash was reclassified to cash and cash equivalents during the first quarter 2011.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Note 11—Employee Compensation, Savings and Pension Plans

We have various defined benefit pension plans and post-retirement benefit plans in which our past and present employees participate, which are more fully described in Note 24—Employee Compensation, Savings and Pension Plans in our Form 10-K.

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

	Pension Benefits						Other Benefits
	Three Months Ended September 30,
	2011			2010			2011		2010
	(in millions)
Service cost benefits earned during period	$	3		$	2		$	1	$	1
Interest cost on projected benefit obligation	4			4			1		1
Expected return on plan assets	(5		)	(4		)	—		—
Recognized net prior service cost	1			—			—		—
Recognized net actuarial loss	1			2			—		—

Net periodic benefit cost	$	4		$	4		$	2	$	2

	Pension Benefits						Other Benefits
	Nine Months Ended September 30,
	2011			2010			2011		2010
	(in millions)
Service cost benefits earned during period	$	9		$	8		$	2	$	2
Interest cost on projected benefit obligation	11			11			3		3
Expected return on plan assets	(13		)	(12		)	—		—
Recognized net prior service cost	1			—			—		—
Recognized net actuarial loss	4			4			—		—

Net periodic benefit cost	$	12		$	11		$	5	$	5

Contributions. During the nine months ended September 30, 2011 we made $11 million in contributions to our pension plans or other postretirement benefit plans. We made $18 million in contributions to our pension plans or other postretirement benefit plans during the nine months ended September 30, 2010. We expect to make contributions of approximately $12 million to our pension plans and $2 million to other benefit plans during 2011.

Note 12—Income Taxes

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions, except rates)
Income tax benefit	$	48		$	17		$	184		$	80

Effective tax rate	39		%	42		%	41		%	53		%

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

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

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

Note 13—Loss Per Share

Basic loss per share represents the amount of losses for the period available to each share of our common stock outstanding during the period. Diluted loss per share represents the amount of losses for the period available to each share of our common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period. Basic and diluted shares outstanding for all periods presented have been calculated to reflect the 1-for-5 reverse stock split effected May 25, 2010. Please read Note 23—Capital Stock in our Form 10-K for further discussion.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions, except per share amounts)
Loss from continuing operations for basic and diluted loss per share	$	(75	)	$	(24	)	$	(268	)	$	(71	)

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

Loss per share from continuing operations:

Basic	$	(0.61	)	$	(0.20	)	$	(2.20	)	$	(0.59	)
Diluted (1)	$	(0.61	)	$	(0.20	)	$	(2.20	)	$	(0.59	)

(1)	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per-share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for all periods presented.

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Note 14—Segment Information

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

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

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

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	181		$	298		$	37		$	—		$	516

Total revenues	$	181		$	298		$	37		$	—		$	516

Depreciation and amortization	$	(39	)	$	(33	)	$	—		$	(1	)	$	(73	)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	(12		)	(17		)	(3		)	—			(32		)

Operating income (loss)	$	4		$	28		$	(27	)	$	—		$	5

Interest expense													(107		)
Debt extinguishment costs													(21		)

Loss from continuing operations before income taxes													(123		)
Income tax benefit													48

Net loss													$	(75	)

Identifiable assets (domestic)	$	4,138		$	6,334		$	489		$	145		$	11,106

Capital expenditures	$	(51	)	$	(6	)	$	—		$	—		$	(57	)

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Segment Data as of and for the Three Months Ended September 30, 2010

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	296		$	380		$	99		$	—		$	775

Total revenues	$	296		$	380		$	99		$	—		$	775

Depreciation and amortization	$	(60	)	$	(35	)	$	—		$	(1	)	$	(96	)
Impairment and other charges	—			(134		)	—			—			(134		)
General and administrative expense	(14		)	(20		)	(4		)	(13		)	(51		)

Operating income (loss)	$	85		$	(37	)	$	18		$	(16	)	$	50

Other items, net	—			—			—			1			1
Interest expense													(92		)

Loss from continuing operations before income taxes													(41		)
Income tax benefit													17

Net loss													$	(24	)

Identifiable assets (domestic)	$	3,931		$	4,922		$	582		$	1,686		$	11,121

Capital expenditures	$	(55	)	$	(11	)	$	(1	)	$	(2	)	$	(69	)

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Segment Data as of and for the Nine Months Ended September 30, 2011

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	509		$	743		$	95		$	—		$	1,347

Total revenues	$	509		$	743		$	95		$	—		$	1,347

Depreciation and amortization	$	(169	)	$	(100	)	$	—		$	(5	)	$	(274	)

Impairment and other charges	—			—			(2		)	—			(2		)
General and administrative expense	(31		)	(42		)	(9		)	(15		)	(97		)
Operating income (loss)	$	(73	)	$	9		$	(65	)	$	(21	)	$	(150	)

Other items, net	—			1			—			3			4
Interest expense													(285		)
Debt extinguishment costs													(21		)

Loss from continuing operations before income taxes													(452		)
Income tax benefit													184

Net loss													$	(268	)

Identifiable assets (domestic)	$	4,138		$	6,334		$	489		$	145		$	11,106

Capital expenditures	$	(137	)	$	(47	)	$	(1	)	$	—		$	(185	)

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Segment Data as of and for the Nine Months Ended September 30, 2010

(in millions)

	Coal			Gas			DNE			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	722		$	924		$	226		$	—		$	1,872

Total revenues	$	722		$	924		$	226		$	—		$	1,872

Depreciation and amortization	$	(154	)	$	(103	)	$	—		$	(4	)	$	(261	)
Impairment and other charges	—			(134		)	(1		)	—			(135		)
General and administrative expense	(37		)	(49		)	(11		)	(13		)	(110		)

Operating income (loss)	$	138		$	2		$	32		$	(20	)	$	152

Losses from unconsolidated investments	—			—			—			(34		)	(34		)
Other items, net	—			1			—			2			3
Interest expense													(272		)

Loss from continuing operations before income taxes													(151		)
Income tax benefit													80

Loss from continuing operations													(71		)
Income from discontinued operations, net of taxes													1

Net loss													$	(70	)

Identifiable assets (domestic)	$	3,931		$	4,922		$	582		$	1,686		$	11,121

Capital expenditures and investments in unconsolidated affiliates	$	(220	)	$	(42	)	$	(2	)	$	(21	)	$	(285	)

Table of Contents

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(Unaudited)

For the Interim Periods Ended September 30, 2011 and 2010

Note 15—Subsequent Events

Interest Rate Agreements. On October 19, 2011, DPC and DMG entered into a variety of transactions to hedge interest rate risks associated with their recent financings. DPC entered into LIBOR interest rate caps at 2 percent with a notional value of $900 million through October 31, 2013. DPC also entered into LIBOR interest rate swaps with a notional value of $788 million commencing on November 1, 2013 through August 5, 2016. The notional value of the swaps decreases over time, reaching $744 million at the end of the term. DMG entered into LIBOR interest rate caps at 2 percent with a notional value of $500 million through October 31, 2013. DMG also entered into LIBOR interest rate swaps with a notional value of $313 million commencing on November 1, 2013 through August 5, 2016. These instruments, which meet the definition of a derivative, have not been designated as accounting hedges and will be accounted for at fair value.

Bankruptcy Filing

On November 7, 2011, the Debtor Entities filed the Chapter 11 Cases. Neither Dynegy nor any of its direct or indirect subsidiaries other than the five Debtor Entities sought protection from creditors, and none of those entities are debtors under Chapter 11 of the Bankruptcy Code. The Chapter 11 Cases have been assigned to the Honorable Judge Morris and are being jointly administered under the caption “In re: Dynegy Holdings, LLC et. al” Case No. 11-38111. To date, certain motions have been filed in opposition to the Chapter 11 Cases, which we believe lack merit and intend to oppose vigorously. The Debtor Entities will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

As noted above, the Debtor Entities are the only subsidiaries or affiliates of Dynegy that have filed the Chapter 11 Cases. Coal Holdco and its indirect, wholly-owned subsidiary, DMG, as well as all subsidiaries of DH other than the Debtor Entities, including DPC and all of its subsidiaries, are not included in the Chapter 11 Cases. The normal day-to-day operations of the coal-fired power generation facilities held by DMG and the gas-fired generation facilities held by DPC will continue without interruption. The commencement of the Chapter 11 Cases does not constitute a default under the DMG or DPC Credit Agreements.

In connection with the Chapter 11 Cases, the Debtor Entities intend, subject to Bankruptcy Court approval, to reject the leases of the Roseton and Danskammer power generation facilities located in Newburgh, New York. Although the Debtor Entities are prepared to surrender the Roseton and Danskammer facilities upon entry of an order authorizing the rejection of the leases, applicable federal and state regulatory requirements prevent the Debtor Entities from doing so immediately. Therefore, the Debtor Entities intend to operate the facilities to the extent necessary to comply with applicable federal and state regulatory requirements until operational control is permitted to be transitioned to the owners of the leased facilities, which are affiliates of Public Service Enterprise Group, Inc.

Also in connection with the Chapter 11 Cases, DH, as lender, and the other Debtor Entities, as borrowers, intend, subject to Bankruptcy Court approval, to enter into a $15 million Intercompany Revolving Loan Agreement that will be available to the borrowers for working capital and certain other administrative expenses during the Chapter 11 Cases.

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

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

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

· DH’s $1.25 billion promissory note to its subsidiary, DGIN, payable on September 1, 2027;

Table of Contents

· DH’s $26 million cash collateralized letter of credit facility between DH and CS, which is collateralized by a $27 million account maintained by Bank of New York Mellon; and

· Roseton and Danskammer’s sale-leaseback arrangements under which the rent payments paid by each of them are assigned to an indenture trustee for the respective facility. The indenture trustee then pays a portion of those payments to each of two pass-through trusts, and such pass-through trusts pay these amounts to holders of certificates in the pass-through trusts. The current total outstanding principal of the certificates is approximately $550 million. At September 30, 2011, the present value (discounted at 10 percent) of future rent payments was $603 million.

As the filing of the Chapter 11 Cases constituted an event of default, we have reclassified the DH Senior Notes and Debentures, including the Subordinated Capital Income Securities reflected as affiliated debt, as current obligations at September 30, 2011 as discussed in Note 10—Debt—Senior Notes and Debentures and Subordinated Capital Income Securities.

Support Agreement. The Chapter 11 Cases were filed in accordance with a Restructuring Support Agreement (the “Support Agreement”) among Dynegy, DH and certain holders (the “Consenting Noteholders”) of an aggregate of approximately $1.4 billion of DH’s Old Notes. The Debtor Entities’ proposed financial restructuring (the “Restructuring”), as outlined in the Support Agreement and the restructuring term sheet attached thereto (the “Term Sheet”), has the support of the Consenting Noteholders.

Pursuant to the Support Agreement, the Consenting Noteholders agree, upon the terms and subject to the conditions contained in the Support Agreement, to (i) vote their claims under the Old Notes in favor of the Restructuring and not withdraw or revoke such vote; except as permitted under the Support Agreement, (ii) not object to the Restructuring; (iii) not initiate legal proceedings inconsistent with or that would prevent, frustrate, delay or impede the Restructuring; (iv) not vote for, consent to, participate, solicit, support, formulate, entertain, encourage or engage in discussions or negotiations, or enter into any agreements relating to, any alternative to the Restructuring; and (v) not solicit, encourage, or direct any person or entity, including the indenture trustee under the indenture for the Old Notes, to undertake any such action. Additionally, the Consenting Noteholders agree not to transfer or assign their claims (the “Noteholder Claims”), including any voting rights, until December 7, 2011 (while definitive documentation for the Restructuring is agreed upon) and thereafter to only transfer or assign their claims to parties who also agree to assume and be bound by the Support Agreement, subject to certain exceptions and procedural requirements. Subject to fiduciary duties, Dynegy and DH agree to use their reasonable best efforts to (i) support and complete the Restructuring, (ii) take all necessary and appropriate actions in furtherance of the Restructuring and the transactions related thereto, (iii) complete the Restructuring and all transactions related thereto within the time-frames outlined in the Support Agreement, (iv) obtain all required governmental, regulatory and/or third-party approvals for the Restructuring and (v) take no actions inconsistent with the Support Agreement or the confirmation and consummation of the Plan (as defined below).

The Support Agreement may be terminated if (among other things): (i) a chapter 11 plan (the “Plan”) and other documents required to implement the Restructuring are not, with respect to any economic or other material term of the Restructuring, in form and substance acceptable to a Majority of the Consenting Noteholders by December 7, 2011; (ii) the Bankruptcy Court has not entered an order approving the disclosure statement related to the Plan (the “Disclosure Statement”) by March 15, 2012; (iii) the Bankruptcy Court has not entered an order confirming the Plan by June 15, 2012; or (iv) the Plan has not become effective by August 1, 2012.

The Term Sheet sets forth the material terms of the Restructuring pursuant to which unsecured claims of DH, including its outstanding Old Notes, will be cancelled and receive a combination of (i) $400 million cash, (ii) $1.0 billion aggregate principal amount of new secured notes (“New Secured Notes”) of Dynegy (or a cash payment in lieu thereof) and (iii) $2.1 billion of convertible securities of Dynegy (the “Convertible Securities”). Existing Dynegy common stock will remain outstanding. In connection with the Chapter 11 Cases, the Debtor Entities intend, subject to Bankruptcy Court approval, to reject the leases of the Roseton and Danskammer power generation facilities located in Newburgh, New York. It is a condition precedent to the consummation of the Restructuring that the rejection damage claims arising therefrom do not exceed $300 million subject to certain exceptions.

Table of Contents

The New Secured Notes will pay cash interest at an 11 percent annual rate and have a seven year maturity. The New Secured Notes will have a first priority security interest in and lien on a $55 million debt service account. The New Secured Notes will have customary high yield covenants including negative covenants restricting asset transfers, mergers, layering, dividends, incurrence of debt and liens, restricted payments and change of control with exceptions to be agreed upon. The New Secured Notes will be secured by a first priority security interest in (subject to certain exceptions and subject to applicable contractual and legal restrictions): (i) the assets of certain direct and indirect coal and gas wholly-owned subsidiaries of Dynegy and (ii) the equity interests in certain direct and indirect coal and gas subsidiaries of Dynegy.

The aggregate principal amount of New Secured Notes and the cash component of the Restructuring payments are subject to certain adjustments as more fully set forth in the Term Sheet. For example, the amount of New Secured Notes to be issued will be reduced (and the cash component increased) by specified amounts of excess cash at DH and its subsidiaries (other than the bankruptcy-remote entities that own Dynegy’s coal and gas fueled power generation businesses) and may also be increased or decreased based on the amount of the aggregate claims arising from the rejection of the Roseton and Danskammer leases. Additionally, Dynegy may, in lieu of issuing any New Secured Notes, provide for a cash payment equal to the aggregate principal amount of New Secured Notes (plus an amount equal to all interest that would have been accrued from the filing date of the Chapter 11 Cases); provided that such cash payment is funded by debt on terms that, taken as a whole (and subject to certain exceptions), are no less favorable to Dynegy than the terms of the New Secured Notes.

The Convertible Securities will earn payment-in-kind interest, commencing retroactively on November 7, 2011, at 4 percent through December 31, 2013, 8 percent thereafter through December 31, 2014 and 12 percent thereafter. The Convertible Securities will not be convertible at the option of the holder but will mandatorily convert into common stock comprising 97 percent of Dynegy’s fully diluted common stock on December 31, 2015, if not earlier redeemed. The Convertible Securities may be redeemable in whole by Dynegy at the following amounts: $1.95 billion prior to the 18 month anniversary of the filing of the Chapter 11 Cases; $2.0 billion thereafter through December 31, 2013; and $2.1 billion thereafter until the mandatory conversion date on December 31, 2015, in each case, plus accrued interest. The Convertible Securities have no voting or other governance rights, there will be no right to dividends or distributions on junior stock or any purchase, redemption, retirement or other acquisition for value of junior stock while any Convertible Securities remain outstanding, and specified covenants will be agreed upon, including restrictions on debt incurrence and certain extraordinary sales or acquisitions. In no event will the Convertible Securities ever give rise to a claim against Dynegy or any of its subsidiaries; provided, however, that the Convertible Securities will be structured to entitle the holders to enforce remedies to obtain the common equity of reorganized Dynegy in connection with an event of default.

The holders of DH’s Series B 8.316 percent Subordinated Capital Income Securities due 2027 would participate in the Restructuring as unsecured note holders, but their recovery would be subject to enforcement of their contractual subordination to the Old Notes. Alternatively, the subordinated note holders will be offered the opportunity to participate, without subordination, in the restructuring as unsecured note holders at $0.25 for every dollar of claims.

Accounting Impact. As a result of the filing of the Chapter 11 Cases, we are required under accounting standards to evaluate whether we should continue to consolidate DH and its consolidated subsidiaries, including the other Debtor Entities as well as the non-Debtor Entities included in our Gas segment, or whether we should deconsolidate DH and its consolidated subsidiaries, as of November 7, 2011. We are in the process of making this determination, and are considering factors including the following facts and assumptions:

· we own, directly or indirectly, 100 percent of the common stock of the Debtor Entities as well as the non-Debtor Entities consolidated by DH. The non-Debtor Entities consolidated by DH include the operations included in our Gas segment, which represent a significant portion of our business;

· the Chapter 11 Cases are unusual in that the Debtor Entities do not include the operations of the Gas segment, yet these non-Debtor Entities are consolidated for accounting purposes by DH;

· the Bankruptcy Court has a role in the decision making processes and our ability to control the outcome is limited;

Table of Contents

· there are uncertainties surrounding the nature, timing, and specifics of the Chapter 11 Cases;

· the Chapter 11 Cases were filed in accordance with a Restructuring Support Agreement (the “Support Agreement”) among Dynegy, DH and Consenting Noteholders, who hold an aggregate in excess of $1.4 billion of DH’s Old Notes and the Support Agreement contemplates that upon emergence from bankruptcy DH’s gas business will continue to be owned and operated by Dynegy;

· we do not expect the Debtor Entities to be in bankruptcy for a long period of time; and

· if the Restructuring is successful, one of the ultimate outcomes upon emergence is that we could issue cash, debt, and convertible securities in order to resolve the direct financial obligations of the Debtor Entities and obligations under their off-balance sheet arrangements, which would result in us continuing to own, directly or indirectly, 100 percent of the common stock of DH and/or its subsidiaries.

If we conclude that we should deconsolidate DH and its consolidated subsidiaries, the carrying values of the assets and liabilities of DH and its consolidated subsidiaries would be removed from the consolidated balance sheet. The difference between (i) the estimated fair value of our retained noncontrolling investment in DH at the date of deconsolidation, and (ii) the carrying amount of DH’s consolidated assets and liabilities would be reflected within the statement of operations as of November 7, 2011. The carrying amount of DH’s consolidated assets and liabilities was approximately $1.6 billion at September 30, 2011. Management’s assessment of fair value would consider, in part, estimates of the value of DH’s equity in the Gas segment, as well as estimates of debt and lease obligations. Additionally, this analysis would consider the inherent uncertainty in value resulting from the Chapter 11 Cases. Our market capitalization was approximately $508 million at September 30, 2011, which implies that there could be a significant loss on deconsolidation. However, management has not completed its assessment of the fair value of the investment in DH at this time given the complexities inherent in the valuation and the fact that the Chapter 11 Cases were so recently filed.

The following reflects selected financial information from DH’s unaudited condensed consolidated balance sheet as of September 30, 2011 (in millions).

Cash	$	386
Restricted cash and investments (including $128 million current)	658
Assets from risk management activities (including $1,947 million current)	2,078
Property, plant and equipment, net of accumulated depreciation	2,841
Undertaking due from Dynegy Inc.	1,250
Other	1,040

Total assets	$	8,253

Current liabilities and accrued liabilities	$	337
Liabilities from risk management activities (including $2,037 million current)	2,190
Long-term debt (including $3,554 million current)	4,636
Deferred income taxes	60
Other	172

Total liabilities	$	7,395

Total stockholder’s equity (1)	$	858

Table of Contents

(1) Note that in the normal course of business, payments have been made or cash has been received by DH on behalf of Dynegy, or by Dynegy on behalf of DH. As a result of such transactions, DH has recorded over time a receivable from Dynegy in the aggregate amount of $741 million at September 30, 2011. Consistent with prior periods, this receivable is classified as equity on DH’s consolidated balance sheets, and is thus included in stockholder’s equity above.

The following reflects selected financial information from DH’s unaudited condensed consolidated statements of operations, which includes the operating results from our Gas and DNE segments in operating income (loss). DH’s results from DMG are included in discontinued operations prior to the DMG Acquisition on September 1, 2011.

	Nine Months			Twelve Months
	Ended			Ended
	September 30, 2011			December 31, 2010
	(in millions)
Revenues	$	838		$	1,487
Operating income (loss)	(75		)	—
Net loss	(251		)	(242		)

If we conclude that DH and its consolidated subsidiaries should remain consolidated with Dynegy, our consolidated financial statements will reflect the activity of the Debtor Entities in accordance with financial reporting guidance by entities that have filed petitions with the Bankruptcy Court and expect to reorganize as going concerns under Chapter 11 of the Bankruptcy Code (FASB ASC 852). There will likely be significant charges incurred by the Debtor Entities as a result of reorganization and restructuring costs and the rejection of the leases of the Roseton and Danskammer power generation facilities.

Another accounting consideration resulting from the filings of the Chapter 11 Cases is that our ability to use our state deferred tax assets or that portion of our deferred tax assets comprised of federal NOLs and AMT credits, which totaled $222 million and $271 million, respectively, at December 31, 2010, will likely be limited or modified as a result of the bankruptcy proceeding and such limitation or modification may be significant, requiring us to evaluate whether valuation allowances would be required in the fourth quarter 2011.

Table of Contents

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended September 30, 2011 and 2010

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

The following discussion should be read together with the unaudited condensed consolidated financial statements and the notes thereto included in this report and with the audited consolidated financial statements and the notes thereto included in our Form 10-K.

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three separate segments in our unaudited condensed consolidated financial statements. Prior to this report, we reported results for the following segments: (i) GEN-MW, (ii) GEN-WE and (iii) GEN-NE. Beginning with the third quarter 2011, as a result of the Reorganization, our reportable segments are: (i) the Coal segment (“Coal”); (ii) the Gas segment (“Gas”) and (iii) the Dynegy Northeast segment (“DNE”). Accordingly, we have recast the corresponding items of segment information for all prior periods. Our unaudited condensed consolidated financial results also reflect corporate-level expenses such as interest and depreciation and amortization. General and administrative expenses are allocated to each reportable segment.

Bankruptcy Filing. On November 7, 2011, the Debtor Entities filed the Chapter 11 Cases. Neither Dynegy nor any of its direct or indirect subsidiaries other than the five Debtor Entities sought protection from creditors, and none of those entities are debtors under Chapter 11 of the Bankruptcy Code. The Chapter 11 Cases have been assigned to the Honorable Judge Morris and are being jointly administered under the caption “In re: Dynegy Holdings, LLC et. al” Case No. 11-38111. To date, certain motions have been filed in opposition to the Chapter 11 Cases, which we believe lack merit and intend to oppose vigorously. The Debtor Entities will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

As noted above, the Debtor Entities are the only subsidiaries or affiliates of Dynegy that have filed the Chapter 11 Cases. Coal Holdco and its indirect, wholly-owned subsidiary, DMG, as well as all other subsidiaries of DH other than the Debtor Entities, including DPC and all of its subsidiaries, are not included in the Chapter 11 Cases. The normal day-to-day operations of the coal-fired power generation facilities held by DMG and the gas-fired generation facilities held by DPC will continue without interruption. The commencement of the Chapter 11 Cases does not constitute a default under the DMG or DPC Credit Agreements.

In connection with the Chapter 11 Cases, the Debtor Entities intend, subject to Bankruptcy Court approval, to reject the leases of the Roseton and Danskammer power generation facilities located in Newburgh, New York. Although the Debtor Entities are prepared to surrender the Roseton and Danskammer facilities upon entry of an order authorizing the rejection of the leases, applicable federal and state regulatory requirements may prevent the Debtor Entities from doing so immediately. Therefore, the Debtor Entities intend to operate the facilities to the extent necessary to comply with applicable federal and state regulatory requirements until operational control is transitioned to the owners of the leased facilities, which are affiliates of Public Service Enterprise Group, Inc.

Also in connection with the Chapter 11 Cases, DH, as lender, and the other Debtor Entities, as borrowers, intend, subject to Bankruptcy Court approval, to enter into a $15 million Intercompany Revolving Loan Agreement that shall be used by the borrowers for working capital and certain other administrative expenses during the Chapter 11 Cases.

The Chapter 11 Cases were filed in accordance with the Support Agreement among Dynegy, DH and the Consenting Noteholders of an aggregate of approximately $1.4 billion of DH’s Old Notes. The Debtor Entities’ proposed Restructuring, as outlined in the Support Agreement and the Term Sheet, has the support of the Consenting Noteholders.

Please read Note 15—Subsequent Events—Bankruptcy Filing for further discussion.

Reorganization Activity. In August 2011, we completed the Reorganization of our subsidiaries, whereby (i) substantially all of our coal-fired power generation facilities are held by DMG, (ii) substantially all of our natural gas-fired power generation facilities are held by DPC and (iii) 100 percent of the ownership interests of Dynegy Northeast Generation, Inc., the entity that indirectly holds the equity interests in the subsidiaries that operate the Roseton and Danskammer power generation facilities, including the leased units, are held by DH. We completed the Reorganization of our legal entity structure to facilitate the execution of two new credit agreements. The new credit agreements, which were entered into August 5, 2011, consist of 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.

The proceeds of borrowings under the DPC Credit Agreement were used by DPC to (i) repay an intercompany obligation of a DPC subsidiary to DH and to repay certain outstanding indebtedness under DH’s Fifth Amended and Restated Credit Agreement, (ii) fund cash collateralized letters of credit and cash collateral for existing and future collateral requirements, (iii) repay approximately $192 million of debt relating to Sithe Energies, Inc. (the intermediate project holding company that indirectly holds the Independence facility in New York), (iv) make a $200 million restricted payment to a parent holding company of DPC, (v) pay related transaction fees and expenses and (vi) fund additional cash to the balance sheet to provide the DPC portfolio with liquidity for general working capital and liquidity purposes.

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

Please read Note 10—Debt—New Credit Agreements for further discussion of these new agreements.

DMG Acquisition. On September 1, 2011, Dynegy and DGIN completed the DMG Acquisition. Our management and board of directors, as well as DGIN’s board of managers, concluded that the fair value of the acquired equity stake in Coal HoldCo at the time of the transaction was approximately $1.25 billion, after taking into account all debt obligations of DMG, including in particular the DMG Credit Agreement. Dynegy provided this value to DGIN through the execution of the Undertaking Agreement. The Undertaking Agreement does not provide any rights or obligations with respect to any outstanding DH notes or debentures, including the notes and debentures due in 2019 and 2026.

Table of Contents

Immediately after closing the DMG Acquisition, DGIN assigned its right to receive payments under the Undertaking Agreement to DH in exchange for the Promissory Note. As a condition to Dynegy’s consent to the Assignment, the Undertaking Agreement was amended and restated to be between DH and Dynegy and to provide for the reduction of Dynegy’s obligations if the outstanding principal amount of any of DH’s $3.5 billion of outstanding notes and debentures is decreased as a result of any exchange offer, tender offer or other purchase or repayment by Dynegy or its subsidiaries (other than DH and its subsidiaries, unless Dynegy guarantees the debt securities of DH 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. Please read Note 1—Organization and Basis of Presentation—Reorganization—DMG Acquisition for further discussion.

Sithe Senior Notes. On September 26, 2011, we completed the Sithe Tender Offer, in which we repurchased approximately $192 million of the Sithe Senior Notes for approximately $217 million. In connection with the Sithe Tender Offer and consent solicitation, we amended the indenture under which the Sithe Senior Notes were issued to eliminate or modify substantially all of the restrictive covenants, certain events of default and certain other provisions and satisfied and discharged the indenture and remaining Sithe Senior Notes. Please read Note 10—Debt—Sithe Senior Notes for further discussion.

Going Concern

Also as noted above, on September 1, 2011, we completed the DMG Acquisition, pursuant to which Dynegy acquired 100 percent of the outstanding membership interests of Coal HoldCo from a wholly owned subsidiary of DH. As a result of that transaction, Dynegy has an unsecured obligation of $1.25 billion to DH under the Undertaking Agreement and DH has an unsecured obligation of $1.25 billion to DGIN under the Promissory Note.

Our ability to continue as a going concern is dependent on many factors, including, among other things, the generation by DPC and DMG of sufficient positive operating results to enable DPC and DMG to make certain restricted distributions to their parents (as described in Note 10—Debt), the terms and conditions of an approved plan of reorganization that allows the Debtor Entities to emerge from bankruptcy, execution of any further restructuring strategies, and the successful execution of the company-wide cost reduction initiatives that are ongoing. The accompanying unaudited condensed consolidated financial statements do not include any adjustments that might result from the outcome of the foregoing uncertainties except for the reclassification of our Senior Notes and Debentures, including the Subordinated Capital Income Securities reflected as affiliated debt, and associated deferred financing costs due to the Chapter 11 Cases discussed above. Please read Note 10—Debt—Senior Notes and Debentures and Subordinated Capital Income Securities for further discussion.

Table of Contents

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.

As a result of the Reorganization, our primary sources of internal liquidity are cash flows from operations and cash on hand. Please read Note 10—Debt for further information. Cash on hand includes cash proceeds from the DPC Credit Agreement and the DMG Credit Agreement, which is limited in use and distribution as further described in footnote 1 to the liquidity table below.

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

Current Liquidity. The following tables summarize our liquidity position at November 8, 2011 and September 30, 2011:

	November 8, 2011
	DPC (1)			DMG (1)			Other (2)			Total
	(in millions)
LC capacity, inclusive of required reserves (3)	$	530		$	103		$	27		$	660
Less: Required reserves (3)	(15		)	(3		)	(1		)	(19		)
Less: Outstanding letters of credit	(391		)	(58		)	(26		)	(475		)

LC availability	124			42			—			166
Cash and cash equivalents	106			210			452			768
Collateral Posting Account (4)	105			30			—			135

Total available liquidity (5)(6)	$	335		$	282		$	452		$	1,069

	September 30, 2011
	DPC (1)			DMG (1)			Other (2)			Total
	(in millions)
LC capacity, inclusive of required reserves (3)	$	530		$	103		$	27		$	660
Less: Required reserves (3)	(15		)	(3		)	(1		)	(19		)
Less: Outstanding letters of credit	(389		)	(76		)	(26		)	(491		)

LC availability	126			24			—			150
Cash and cash equivalents	172			249			460			881
Collateral Posting Account (4)	101			36			—			137

Total available liquidity (5)(6)	$	399		$	309		$	460		$	1,168

(1)

On August 5, 2011, we borrowed $1,100 million under the DPC Credit Agreement and $600 million under the DMG Credit Agreement, and repaid amounts outstanding under 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 and a portion of the proceeds from the DMG Credit Agreement borrowing was used to make a $200 million restricted payment to a parent holding company of DMG. The DPC Credit Agreement and the DMG Credit Agreement limit distributions by DPC and DMG to their parents to $135 million and $90 million per fiscal year, respectively. Please read “DPC and DMG Restricted Payments below” and Note 10—Debt—New Credit Agreements for further discussion.

Table of Contents

(2)	Other cash consists of $170 million and $190 million at Dynegy Gas HoldCo, LLC; $190 million and $190 million at Dynegy Coal HoldCo, LLC; $56 million and $56 million at Dynegy; $24 million and $14 million at Dynegy Administrative Services Company; $11 million and $3 million at DH; and $1 million and $7 million at Dynegy Northeast Generation, Inc as of November 8, 2011 and September 30, 2011, respectively.
(3)	The LC facilities were collateralized with cash proceeds received under the new credit agreements, with such proceeds currently included in Restricted cash and investments on our unaudited condensed consolidated balance sheets. The amount of the LC availability plus any unused required reserves of 3 percent on the unused capacity, may be withdrawn from the LC facilities with three days written notice for unrestricted use in the operations of the applicable entity.
(4)	The Collateral Posting Account included in the above liquidity tables is restricted per the new credit agreements and may be used for future collateral posting requirements or released per the terms of the applicable DPC and DMG Credit Agreements. Please read Note 10—Debt—New Credit Agreements for further discussion. Amounts are included in Restricted cash and investments on our unaudited condensed consolidated balance sheets.
(5)	Our 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.
(6)	Does not reflect our ability to use the first lien structure as described below.

Capital-Structuring Transactions. We believe the Reorganization and the new credit agreements aligned our asset base and increased our flexibility to address additional potential debt restructuring activities. On September 1, 2011, Dynegy and DGIN effected the DMG Acquisition whereby DGIN sold 100 percent of the outstanding membership interests of Coal HoldCo to Dynegy. Please read Note 1—Organization and Basis of Presentation—Reorganization—DMG Acquisition for further discussion. Further, on November 7, 2011 the Debtor Entities filed the Chapter 11 Cases. The Chapter 11 Cases were filed in accordance with the Support Agreement and accompanying Term Sheet. The Term Sheet sets forth the material terms of the Restructuring pursuant to which unsecured claims of DH, including its outstanding Old Notes, will be cancelled and receive a combination of (i) $400 million cash, (ii) $1.0 billion aggregate principal amount of New Secured Notes and (iii) $2.1 billion of Convertible Securities. Please read Note 15—Subsequent Events—Bankruptcy Filing for further discussion. If we are unable to implement the Restructuring of the Debtor Entities, as contemplated by the Support Agreement, we may be required to pursue alternative restructuring proposals which may include exploring alternative sources of external liquidity.

DPC and DMG Restricted Payments. Without regard to the $400 million, in the aggregate, of proceeds from the DPC Credit Agreement and the DMG Credit Agreement that was initially distributed to Dynegy Gas Holdco, LLC and Dynegy Coal Holdco, LLC, respectively, the DPC Credit Agreement and the DMG Credit Agreement limit distributions by DPC and DMG to their parents to $135 million and $90 million per year, respectively, provided the borrower and its subsidiaries possess at least $50 million of cash and cash equivalents and short-term investments as of the date of the proposed distribution. Please read Note 10—Debt—New Credit agreements for further discussion.

Table of Contents

Operating Activities

Historical Operating Cash Flows. Our cash flow provided by operations totaled $50 million for the nine months ended September 30, 2011. During the period, our power generation business provided positive cash flow from the operation of our power generation facilities. Our working capital was slightly positive primarily due to the seasonality of our cash flows and the timing of our interest payments to service debt partially offset by employee related payments and collateral posted to satisfy our counterparty collateral demands.

Our cash flow provided by operations totaled $670 million for the nine months ended September 30, 2010. During the period, our power generation business provided positive cash flow from operations of $992 million from the operation of our power generation facilities, primarily reflecting positive earnings for the period and approximately $353 million of cash received from our futures clearing manager. The receipt of this cash is partly due to lower commodity prices and a reduction of margin requirements; the remaining cash was returned as a result of the posting of short-term investments and a letter of credit in substitute of cash. Corporate and other operations included a use of approximately $322 million in cash, primarily due to interest payments to service debt and general and administrative expenses.

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

Collateral Postings. We use a significant portion of our capital resources in the form of cash and letters of credit to satisfy counterparty collateral demands. These counterparty collateral demands reflect our non-investment grade credit ratings and counterparties’ views of our financial condition and ability to satisfy our performance obligations, as well as commodity prices and other factors. At September 30, 2011, we had approximately $62 million of cash collateral postings and $284 million of letter of credit collateral postings related to our hedging activities. The following table summarizes our consolidated collateral postings to third parties by legal entity at November 8, 2011, September 30, 2011 and December 31, 2010:

	November 8, 2011		September 30, 2011		December 31, 2010
	(in millions)
Dynegy Power, LLC:
Cash and short-term investments (1)	$	84	$	69	$	—
Letters of credit	391		389		—

Total DPC	475		458		—

Dynegy Midwest Generation, LLC:
Cash and short-term investments (1)	17		4		—
Letters of credit	58		76		—

Total DMG	75		80		—

Dynegy Holdings, LLC:
Cash and short-term investments (1)	1		1		87
Letters of credit	26		26		375

Total DH	27		27		462

Total	$	577	$	565	$	462

(1)

Includes Broker margin account on our unaudited condensed consolidated balance sheets, as well as other collateral postings of $41 million as of September 30, 2011 included in Prepayments and other current assets on our unaudited condensed consolidated balance sheets. There were no short-term investments in our Broker margin account at November 8, 2011 or September 30, 2011. As of December 31, 2010, we had $85 million of short-term investments in our Broker margin account on our unaudited condensed consolidated balance sheet. Collateral at December 31, 2010 does not include approximately $7 million of cash received by the Company for in-the-money open positions. Please see Note 4—Risk Management Activities, Derivatives and Financial Instruments—Derivatives on the Balance Sheet for further discussion of the composition of the Broker Margin Account.

Table of Contents

The change in letters of credit postings from December 31, 2010 to September 30, 2011 is primarily due to contractual obligations under certain operational agreements. Collateral postings increased from September 30, 2011 to November 8, 2011 primarily due to market movements.

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 new credit agreements 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 new credit agreements. The fair value of our commodity derivatives collateralized by first priority liens, netted by counterparty, included liabilities of $161 million, $131 million and $30 million at November 8, 2011, September 30, 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.

Investing Activities

Capital Expenditures. We had approximately $185 million and $270 million in capital expenditures during the nine months ended September 30, 2011 and 2010, respectively. Our capital spending by reportable segment was as follows:

	For the Nine Months Ended
	September 30,
	2011		2010
	(in millions)
Coal	$	137	$	220
Gas	47		42
DNE	1		2
Other and eliminations	—		6

Total	$	185	$	270

Capital spending in our Coal segment primarily consisted of environmental and maintenance capital projects. Capital spending in our Gas and DNE segments primarily consisted of maintenance projects. The decrease in our capital expenditures is largely due to the completion of various Consent Decree projects in our Coal segment in 2010.

Other Investing Activities. There was a $142 million cash inflow related to restricted cash balances during the nine months ended September 30, 2011 primarily due to (i) the release of $850 million upon the termination of our former Fifth Amended and Restated Credit Agreement, (ii) the release of $43 million upon the completion of the Sithe Tender Offer, and (iii) the release of $50 million related to the expiration of a security and deposit agreement. These decreases in restricted cash were partially offset by increases of $631 million, $139 million and $27 million associated with the DPC Credit Agreement, the DMG Credit Agreement, and a DH Letter of Credit Reimbursement and Collateral Agreement with CS, respectively.

Table of Contents

Cash outflow for purchases of short-term investments during the nine months ended September 30, 2011 totaled $284 million. Cash inflow related to maturities of short-term investments for the nine months ended September 30, 2011 was $475 million. Other included $11 million of property insurance claim proceeds.

Cash outflow related to purchases of short-term investments during the nine months ended September 30, 2010 totaled $428 million. Cash inflow related to maturities from short-term investments for the nine months ended September 30, 2010 totaled $143 million. There was a $53 million cash outflow related to restricted cash balances during the nine months ended September 30, 2010, primarily due to an increase in the Sithe restricted cash balance. There was a $15 million cash outflow related to our PPEA funding commitment. Other included $9 million related to the distribution of an investment.

Financing Activities

Historical Cash Flow from Financing Activities. Cash flow provided by financing activities totaled $381 million for the nine months ended September 30, 2011. Proceeds from long-term borrowings of $2,022 million, net of $44 million of debt issuance costs, consisted of:

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

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

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

We also received $3 million from the proceeds of stock option exercises. These proceeds partially offset repayments of borrowings of $1,623 million, consisting of the following:

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

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

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

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

· $225 million of borrowings on Sithe senior debt.

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

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

Financing Trigger Events. Our debt instruments and other financial obligations include provisions which, if not met, could require early payment, additional collateral support or similar actions. These trigger events include the violation of covenants, defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions insolvency events, acceleration of other financial obligations and change of control provisions. We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.

Financial Covenants. Following the termination of our Fifth Amended and Restated Credit Agreement on August 5, 2011, we are no longer subject to any financial covenants.

Dividends on Common Stock. Dividend payments on our common stock are authorized at the discretion of our Board of Directors and applicable law, although if as a result of the Chapter 11 Cases the transactions contemplated by the Support Agreement are implemented, there will be restrictions on the ability of the Board of Directors to declare dividends on our common stock. We did not declare or pay a cash dividend on common stock during the quarter ended September 30, 2011.

Table of Contents

Credit Ratings

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

	Standard & Poor	Moody’s	Fitch

Dynegy Inc.:
Corporate Family Rating	CC	Caa3	CC
DH:
Senior Unsecured (1)	D	NR	CCC
DPC:
Senior Secured	B	B2	B

(1) Moody’s Investor Services withdrew its rating of the DH senior unsecured bonds after the Debtor Entities filed the Chapter 11 Cases.

Disclosure of Contractual Obligations and Contingent Financial Commitments

We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. Contingent financial commitments represent obligations that become payable only if certain pre-defined events occur, such as financial guarantees.

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

Table of Contents

RESULTS OF OPERATIONS

Overview

In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three and nine month periods ended September 30, 2011 and 2010. We have included our outlook for each segment at the end of this section.

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

Non-GAAP Performance Measures

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

We believe that the historical non-GAAP measures disclosed in our filings are only useful as an additional tool to help management and investors make informed decisions about our financial and operating performance. By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the comparable GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies’ non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

EBITDA and Adjusted EBITDA. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale of assets, (ii) the impacts of mark-to-market changes and (iii) impairment charges. We believe EBITDA and Adjusted EBITDA provide a meaningful representation of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our power generation fleet; consequently, it excludes the impact of mark-to-market accounting, impairment charges and gains and losses on sales of assets, which could be considered “non-operating” or “non-core” in nature, and includes the contributions of those plants classified as discontinued operations. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers and evaluate overall financial performance, we believe they provide useful information for our investors. In addition, many analysts, fund managers and other stakeholders that communicate with us typically request our financial results in an EBITDA and Adjusted EBITDA format.

As prescribed by the SEC, when Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is net income (loss). Because management does not allocate interest expense and income taxes on a segment level, the most directly comparable GAAP financial measure to Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss).

Table of Contents

Consolidated Summary Financial Information — Three Months Ended September 30, 2011

The following table provides summary financial data regarding our consolidated and segmented results of operations for the three month periods ended September 30, 2011 and 2010, respectively:

	Three Months Ended September 30,
	2011			2010			$ Change			% Change
	(dollars in millions)
Revenues	$	516		$	775		$	(259	)	(33	)%
Cost of sales	(298		)	(334		)	36			11	%

Gross margin, exclusive of depreciation shown separately below	218			441			(223		)	(51	)%
Operating and maintenance expense, exclusive of depreciation shown separately below	(107		)	(110		)	3			3	%
Depreciation and amortization expense	(73		)	(96		)	23			24	%
Impairment and other charges	(1		)	(134		)	133			99	%
General and administrative expenses	(32		)	(51		)	19			37	%

Operating income	5			50			(45		)	(90	)%
Interest expense	(107		)	(92		)	(15		)	(16	)%
Debt extinguishment costs	(21		)	—			(21		)	(100	)%
Other income and expense, net	—			1			(1		)	(100	)%

Loss from continuing operations before income taxes	(123		)	(41		)	(82		)	(200	)%
Income tax benefit	48			17			31			182	%

Net loss	$	(75	)	$	(24	)	$	(51	)	(213	)%

The following tables provide summary financial data regarding our operating income (loss) by segment for the three month periods ended September 30, 2011 and 2010, respectively:

	Three Months Ended September 30, 2011
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	181		$	298		$	37		$	—		$	516
Cost of sales	(80		)	(188		)	(30		)	—			(298		)

Gross margin, exclusive of depreciation shown separately below	101			110			7			—			218
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(46		)	(32		)	(30		)	1			(107		)
Depreciation and amortization expense	(39		)	(33		)	—			(1		)	(73		)
Impairment and other charges	—			—			(1		)	—			(1		)
General and administrative expense	(12		)	(17		)	(3		)	—			(32		)

Operating income (loss)	$	4		$	28		$	(27	)	$	—		$	5

Table of Contents

	Three Months Ended September 30, 2010
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	296		$	380		$	99		$	—		$	775
Cost of sales	(95		)	(191		)	(48		)	—			(334		)

Gross margin, exclusive of depreciation shown separately below	201			189			51			—			441
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(42		)	(37		)	(29		)	(2		)	(110		)
Depreciation and amortization expense	(60		)	(35		)	—			(1		)	(96		)
Impairment and other charges	—			(134		)	—			—			(134		)
General and administrative expense	(14		)	(20		)	(4		)	(13		)	(51		)

Operating income (loss)	$	85		$	(37	)	$	18		$	(16	)	$	50

The following tables provide summary financial data regarding our Adjusted EBITDA by segment for the three month periods ended September 30, 2011 and 2010, respectively.

	Three Months Ended September 30, 2011
	Coal		Gas			DNE			Other		Total
	(in millions)
Net loss											$	(75	)
Income tax benefit											(48		)
Interest expense and debt extinguishment costs											128

Operating income (loss)	$	4	$	28		$	(27	)	$	—	$	5
Depreciation and amortization expense	39		33			—			1		73

EBITDA	43		61			(27		)	1		78
Restructuring costs	4		11			—			—		15
Mark-to-market (income) loss, net	3		(20		)	26			4		13

Adjusted EBITDA	$	50	$	52		$	(1	)	$	5	$	106

	Three Months Ended September 30, 2010
	Coal			Gas			DNE			Other			Total
	(in millions)
Net loss													$	(24	)
Income tax benefit													(17		)
Interest expense													92
Other items, net													(1		)

Operating income (loss)	$	85		$	(37	)	$	18		$	(16	)	$	50
Other items, net	—			—			—			1			1
Depreciation and amortization expense	60			35			—			1			96

EBITDA	145			(2		)	18			(14		)	147
Impairments	—			134			—			—			134
Merger agreement transaction costs	—			—			—			10			10
Mark-to-market (income) loss, net	(74		)	(43		)	(16		)	1			(132		)

Adjusted EBITDA	$	71		$	89		$	2		$	(3	)	$	159

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $259 million from $775 million for the third quarter 2010 to $516 million for the third quarter 2011. Of this decrease, $148 million related to mark-to market losses on forward sales of power and other derivatives in 2011, compared to mark-to-market gains in 2010. Such losses totaled $16 million for the three months ended September 30, 2011, compared to $132 million of mark-to-market gains for the three months ended September 30, 2010. The mark-to-market losses for the three months ended September 30, 2011 included fees of approximately $8 million paid to brokers in connection with the Reorganization. The remaining decrease of $111 million is due to lower generated volumes, reduced capacity prices, and fewer revenues from option premiums offset by higher tolling revenues, as further described in our segment discussion below.

Table of Contents

Cost of Sales. Cost of sales decreased by $36 million from $334 million for the third quarter 2010 to $298 million for the third quarter 2011. This decrease is due to lower generation volumes and lower prices for coal and natural gas, as further described in our segment discussion.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. Operating and maintenance expense decreased by $3 million from $110 million for the third quarter 2010 to $107 million for the third quarter 2011. This decrease is largely due to the mothballing of the Vermilion facility and the retirement of the South Bay facility, as well as the timing of outages.

Depreciation and Amortization Expense. Depreciation expense decreased by $23 million from $96 million for the third quarter 2010 to $73 million for the third quarter 2011, as a result of fully depreciating the value of our Wood River Units 1-3 and Havana Units 1-5 in September 2010, as well as the Havana 6 Precipitator Rebuild retirement in 2010. In addition, the Vermilion facility was mothballed during the first quarter 2011.

Impairment and Other Charges. Impairment and other charges for the three months ended September 30, 2010 included a pre-tax asset impairment of $134 million related to our Casco Bay power generation facility and related assets. Please read Note 6—Impairment Charges for further discussion.

General and Administrative Expenses. General and administrative expenses decreased by $19 million from $51 million for the three months ended September 30, 2010 to $32 million for the three months ended September 30, 2011. The decrease was primarily driven by lower salary and benefits costs as a result of ongoing cost savings initiatives and approximately $10 million of costs associated with a merger transaction contemplated in 2010. These items were partially offset by $7 million of restructuring costs in 2011, primarily related to financial and legal advisors.

Interest Expense. Interest expense totaled $107 million and $92 million for the three months ended September 30, 2011 and 2010, respectively. The increase was primarily driven by the new credit agreements and associated higher borrowing and rates.

Debt Extinguishment Costs. Debt extinguishment costs totaled $21 million for the three months ended September 30, 2011 and were incurred in connection with the termination of the Sithe senior debt.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $48 million for the three month period ended September 30, 2011, compared to an income tax benefit from continuing operations of $17 million for the three months ended September 30, 2010. The effective tax rate in 2011 was 39 percent, compared to 42 percent for 2010.

For the three month periods ended September 30, 2011 and 2010, the difference between the effective rates of 39 percent and 42 percent, respectively, and the statutory rate of 35 percent resulted primarily from the impact of state taxes.

Adjusted EBITDA. Adjusted EBITDA decreased by $53 million from $159 million for the third quarter 2010 to $106 million for the third quarter 2011 primarily due to lower value received from our commercial activities. In addition, our revenues and cost of sales were lower due to lower generated volumes resulting primarily from the timing of planned outages, the retirement of the South Bay facility and the mothballing of the Vermilion facility. Finally, operating expenses decreased in large part due to the retirement of our South Bay facility.

Table of Contents

Discussion of Segment Results of Operations

Coal Segment. Above average temperatures in July 2011 resulted in higher power prices when compared to July 2010. However, both August and September 2011 saw lower temperatures as compared to 2010. This resulted in average prices across the three months being roughly the same for 2011 and 2010.

The following table provides summary financial data regarding our Coal segment results of operations for the three month periods ended September 30, 2011 and 2010, respectively:

	Three Months Ended September 30,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	185		$	205		$	(20	)	(10	)%
Capacity	6			6			—			—
Financial transactions:
Mark-to-market income (loss)	(3		)	74			(77		)	(104	)%
Financial settlements	(3		)	10			(13		)	(130	)%
Option premiums	(2		)	—			(2		)	(100	)%

Total financial transactions	(8		)	84			(92		)	(110	)%
Other (1)	(2		)	1			(3		)	(300	)%

Total revenues	181			296			(115		)	(39	)%
Cost of sales	(80		)	(95		)	15			16	%

Gross margin	$	101		$	201		$	(100	)	(50	)%

Million Megawatt Hours Generated	5.1			5.8			(0.7		)	(12	)%
In Market Availability for Coal Fired Facilities (2)	92		%	91		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	47		$	48		$	(1	)	(2	)%

(1)	Other includes ancillary services and other miscellaneous items.
(2)	Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.
(3)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

Gross margin for Coal decreased by $100 million from $201 million for the three months ended September 30, 2010, to $101 million for the three months ended September 30, 2011. The majority of this decrease related to a net change in mark-to-market income from income of $74 million to a loss of $3 million.

Energy revenues, and corresponding cost of sales, were lower primarily due to lower generated volumes. Lower generation resulted primarily from the mothballing of the Vermilion facility early in 2011.

Gas Segment. The third quarter saw a decrease in net generation of approximately 24 percent in ISO-NE and NYISO mainly due to lower demand and an increase in import generation. PJM had mixed results with year-over-year demand increasing for July and setting a new record for load demand, while August demand was down 4.8 percent.

In California, where our Moss Landing units are located, power prices declined significantly mainly due to two factors. First, robust snowpack in the Northwest and California led to strong hydro production with the Northwest’s second largest amount of hydro production since 1993. This coupled with another very mild summer led to historical lows in terms of spark-spreads. The following table provides summary financial data regarding our Gas segment results of operations for the three month periods ended September 30, 2011 and 2010, respectively:

Table of Contents

	Three Months Ended September 30,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	185		$	216		$	(31	)	(14	)%
Capacity	56			68			(12		)	(18	)%
Tolls	61			42			19			45	%
RMR	3			12			(9		)	(75	)%
Natural gas	39			34			5			15	%
Financial transactions:
Mark-to-market income	15			43			(28		)	(65	)%
Financial settlements	(62		)	(64		)	2			3	%
Option premiums	(10		)	21			(31		)	(148	)%

Total financial transactions	(57		)	—			(57		)	(100	)%
Other (1)	11			8			3			38	%

Total revenues	298			380			(82		)	(22	)%
Cost of sales	(188		)	(191		)	3			2	%

Gross margin	$	110		$	189		$	(79	)	(42	)%

Million Megawatt Hours Generated (2)	4.4			4.7			(0.3		)	(6	)%
Average Capacity Factor for Combined Cycle Facilities (3)	44		%	47		%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Commonwealth Edison (NI Hub)	$	48		$	49		$	(1	)	(2	)%
PJM West	$	58		$	65		$	(7	)	(11	)%
North Path 15 (NP 15)	$	40		$	39		$	1		3	%
New York—Zone A	$	47		$	53		$	(6	)	(11	)%
Mass Hub	$	56		$	66		$	(10	)	(15	)%
Average Market Spark Spreads ($/MWh) (5):
PJM West	$	28		$	33		$	(5	)	(15	)%
North Path 15 (NP 15)	$	7		$	8		$	(1	)	(13	)%
New York—Zone A	$	14		$	19		$	(5	)	(26	)%
Mass Hub	$	23		$	34		$	(11	)	(32	)%

Average natural gas price—Henry Hub ($/MMBtu) (6)	$	4.13		$	4.28		$	(0.15	)	(4	)%

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

(2) Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility for the three months ended September 30, 2011 and 2010, respectively.

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

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

(5) Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator or an 11.0 MMBtu/MWh heat rate fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.

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

Gross margin for Gas decreased by $79 million from $189 million for the three months ended September 30, 2010, to $110 million for the three months ended September 30, 2011. A portion of this decrease related to a net change in mark-to-market income from $43 million to $15 million. Additionally, Gas had less contributions from option premiums in 2011.

Table of Contents

Energy revenues, and corresponding cost of sales, were lower primarily due to lower generated volumes at Sithe and Casco Bay due to lower spark spreads, which made it less economical to operate the plants.

Capacity prices were lower in 2011 compared to 2010, reducing revenue by $12 million. RMR revenue was negatively impacted by the retirement of the South Bay facility on December 31, 2010.

These items were partially offset by increased tolling revenue of $19 million due to the new Moss Landing toll.

DNE Segment. During the third quarter, dark spreads were compressed by flat Zone G power prices and increased coal prices. In addition, increased imports from NE-ISO negatively impacted our results.

The following table provides summary financial data regarding our DNE segment results of operations for the three month periods ended September 30, 2011 and 2010, respectively:

	Three Months Ended September 30,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	37		$	67		$	(30	)	(45	)%
Capacity	5			12			(7		)	(58	)%
Financial transactions:
Mark-to-market income (loss)	(24		)	16			(40		)	(250	)%
Financial settlements	15			2			13			650	%
Option premiums	2			—			2			100	%

Financial transactions	(7		)	18			(25		)	(139	)%
Other (1)	2			2			—			—

Total revenues	37			99			(62		)	(63	)%
Cost of sales	(30		)	(48		)	18			38	%

Gross margin	$	7		$	51		$	(44	)	(86	)%

Million Megawatt Hours Generated	0.5			0.9			(0.4		)	(44	)%

In Market Availability for Coal Fired Facilities (2)	94		%	96		%
Average Capacity Factor—Coal	37		%	63		%
Average Capacity Factor—Gas	7		%	12		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	63		$	70		$	(7	)	(10	)%
Average Market Spark Spreads ($/MWh) (4):
Fuel Oil	$	(119	)	$	(59	)	$	(60	)	102	%

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

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

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

(4) Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator or an 11.0 MMBtu/MWh heat rate fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.

Table of Contents

Gross margin for DNE decreased by $44 million from $51 million for the three months ended September 30, 2010, to $7 million for the three months ended September 30, 2011. The majority of this decrease related to a net change in mark-to-market income from $16 million to a loss of $24 million.

Energy revenues, and corresponding cost of sales, decreased, largely due to lower generated volumes. In 2011, Danskammer began cycling units to reduce generation during non-profitable off-peak hours.

Capacity revenues decreased $7 million, due to significant decreases in capacity prices in the region, resulting in lower capacity revenues.

Consolidated Summary Financial Information — Nine Months Ended September 30, 2011

The following table provides summary financial data regarding our consolidated and segmented results of operations for the nine month periods ended September 30, 2011 and 2010, respectively:

	Nine Months Ended September 30,
	2011			2010			Change			% Change

Revenues	$	1,347		$	1,872		$	(525	)	(28	)%
Cost of sales	(801		)	(873		)	72			8	%

Gross margin, exclusive of depreciation shown separately below	546			999			(453		)	(45	)%
Operating and maintenance expense, exclusive of depreciation shown separately below	(323		)	(341		)	18			5	%
Depreciation and amortization expense	(274		)	(261		)	(13		)	(5	)%
Impairment and other charges	(2		)	(135		)	133			99	%
General and administrative expenses	(97		)	(110		)	13			12	%

Operating income (loss)	(150		)	152			(302		)	(199	)%
Losses from unconsolidated investments	—			(34		)	34			100	%
Interest expense	(285		)	(272		)	(13		)	(5	)%
Debt extinguishment costs	(21		)	—			(21		)	(100	)%
Other income and expense, net	4			3			1			33	%

Loss from continuing operations before income taxes	(452		)	(151		)	(301		)	(199	)%
Income tax benefit	184			80			104			130	%

Loss from continuing operations	(268		)	(71		)	(197		)	(277	)%
Income from discontinued operations, net of taxes	—			1			(1		)	(100	)%

Net loss	$	(268	)	$	(70	)	$	(198	)	(283	)%

Table of Contents

The following tables provide summary financial data regarding our operating income (loss) by segment for the nine month periods ended September 30, 2011 and 2010, respectively:

	Nine Months Ended September 30, 2011
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	509		$	743		$	95		$	—		$	1,347
Cost of sales	(257		)	(481		)	(63		)	—			(801		)

Gross margin, exclusive of depreciation shown separately below	252			262			32			—			546
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(125		)	(111		)	(86		)	(1		)	(323		)
Depreciation and amortization expense	(169		)	(100		)	—			(5		)	(274		)
Impairment and other charges	—			—			(2		)	—			(2		)
General and administrative expense	(31		)	(42		)	(9		)	(15		)	(97		)

Operating income (loss)	$	(73	)	$	9		$	(65	)	$	(21	)	$	(150	)

	Nine Months Ended September 30, 2010
	Coal			Gas			DNE			Other			Total
	(in millions)
Revenues	$	722		$	924		$	226		$	—		$	1,872
Cost of sales	(261		)	(520		)	(93		)	1			(873		)

Gross margin, exclusive of depreciation shown separately below	461			404			133			1			999
Operating and maintenance expense, exclusive of depreciation and amortization expense shown separately below	(132		)	(116		)	(89		)	(4		)	(341		)
Depreciation and amortization expense	(154		)	(103		)	—			(4		)	(261		)
Impairment and other charges	—			(134		)	(1		)	—			(135		)
General and administrative expense	(37		)	(49		)	(11		)	(13		)	(110		)

Operating income (loss)	$	138		$	2		$	32		$	(20	)	$	152

The following tables provide summary financial data regarding our Adjusted EBITDA by segment for the nine month periods ended September 30, 2011 and 2010, respectively.

	Nine Months Ended September 30, 2011
	Coal			Gas		DNE			Other			Total
	(in millions)
Net loss												$	(268	)
Income tax benefit												(184		)
Interest expense and debt extinguishment costs												306
Other items, net												(4		)

Operating income (loss)	$	(73	)	$	9	$	(65	)	$	(21	)	$	(150	)
Depreciation and amortization expense	169			100		—			5			274
Other items, net	—			1		—			3			4

EBITDA	96			110		(65		)	(13		)	128
Merger agreement termination fee, restructuring costs and other expenses	4			11		—			12			27
Mark-to-market losses, net	75			14		47			4			140

Adjusted EBITDA	$	175		$	135	$	(18	)	$	3		$	295

Table of Contents

	Nine Months Ended September 30, 2010
	Coal			Gas		DNE			Other			Total
	(in millions)
Net loss												$	(70	)
Income tax benefit												(80		)
Interest expense												272
Losses from unconsolidated investments												34
Income from discontinued operations, net of taxes												(1		)
Other items, net												(3		)

Operating income (loss)	$	138		$	2	$	32		$	(20	)	$	152
Other items, net	—			1		—			2			3
Depreciation and amortization expense	154			103		—			4			261
Losses from unconsolidated investments	—			—		—			(34		)	(34		)

EBITDA from continuing operations	292			106		32			(48		)	382
EBITDA from discontinued operations	—			1		—			—			1

EBITDA	292			107		32			(48		)	383
Asset impairments	—			134		1			37			172
Merger agreement transaction costs	—			—		—			10			10
Plum Point mark-to-market gains	—			—		—			(6		)	(6		)
Mark-to-market (gains) losses, net	(113		)	19		(41		)	12			(123		)

Adjusted EBITDA	$	179		$	260	$	(8	)	$	5		$	436

Discussion of Consolidated Results of Operations

Revenues. Revenues decreased by $525 million from $1,872 million for the nine months ended September 30, 2010 to $1,347 million for the nine months ended September 30, 2011. Of this decrease, $270 million related to mark-to market losses on forward sales of power and other derivatives in 2011, compared to mark-to-market gains in 2010. Such losses totaled $143 million for the nine months ended September 30, 2011, compared to $127 million of mark-to-market gains for the nine months ended September 30, 2010. The mark-to-market losses for the nine months ended September 30, 2011 included fees of approximately $8 million paid to brokers in connection with the Reorganization. The remaining decrease of $255 million is due to lower generated volumes and capacity prices as well as less revenues from option premiums, tolling and RMR agreements, as further described below.

Cost of Sales. Cost of sales decreased by $72 million from $873 million for the nine months ended September 30, 2010 to $801 million for the nine months ended September 30, 2011. This decrease is due to lower generated volumes and lower gas and coal prices, as further described below.

Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. Operating and maintenance expense decreased by $18 million from $341 million for the nine months ended September 30, 2010 to $323 million for the nine months ended September 30, 2011. This decrease is due to the mothballing of the Vermilion facility, retirement of the South Bay facility and the timing of outages.

Depreciation and Amortization Expense. Depreciation expense increased by $13 million from $261 million for the nine months ended September 30, 2010 to $274 million for the nine months ended September 30, 2011. The increase was largely due to fully depreciating the value of our Vermilion facility in the first quarter 2011, when it was mothballed. This was partially offset by fully depreciating the value of Wood River Units 1-3 and Havana Units 1-5 in September 2010, as well as the Havana 6 Precipitator Rebuild retirement in 2010.

Impairment and Other Charges. Impairment and other charges for the nine months ended September 30, 2010 included a pre-tax asset impairment of $134 million related to our Casco Bay power generation facility and related assets. Please read Note 6—Impairment Charges for further discussion.

Table of Contents

General and Administrative Expenses. General and administrative expenses decreased $13 million from $110 million for the nine months ended September 30, 2010 to $97 million for the nine months ended September 30, 2011. The decrease was primarily driven by lower salary and benefits costs as a result of ongoing cost savings initiatives and approximately $10 million of costs associated with a merger transaction contemplated in 2010. These savings were reduced by $9 million of transaction costs, $3 million of executive severance costs and $7 million of restructuring costs in 2011.

Losses from Unconsolidated Investments. Losses from unconsolidated investments for the nine months ended September 30, 2010 included losses of $34 million related to our former investment in PPEA Holding. Please read Note 8—Variable Interest Entities for further discussion.

Interest Expense. Interest expense totaled $285 million and $272 million for the nine months ended September 30, 2011 and 2010, respectively. The increase was primarily driven by the new credit agreements and associated higher borrowings and rates.

Debt Extinguishment Costs. Debt extinguishment costs totaled $21 million for the nine months ended September 30, 2011 and were incurred in connection with the termination of the Sithe senior debt.

Income Tax Benefit. We reported an income tax benefit from continuing operations of $184 million for the nine month period ended September 30, 2011, compared to an income tax benefit from continuing operations of $80 million for the nine months ended September 30, 2010. The effective tax rate in 2011 was 41 percent, compared to 53 percent in 2010.

For the period ended September 30, 2011, the difference between the effective rate of 41 percent and the statutory rate of 35 percent resulted primarily from the impact of state taxes which included a benefit of $9 million related to an increase in state NOLs due to the acceptance of amended returns, partially offset by an expense of $3 million related to an increase in the Illinois statutory rate. For the period ended September 30, 2010, the difference between the effective rates of 53 percent and the statutory rate of 35 percent resulted primarily to a benefit of $18 million related to the release of reserves for uncertain tax positions, partially offset by the impact of state taxes.

Adjusted EBITDA. Adjusted EBITDA decreased by $141 million from $436 million for the nine months ended September 30, 2010 to $295 million for the nine months ended September 30, 2011 primarily due to lower value received from our commercial activities. In addition, our revenues and cost of sales were lower due to lower generated volumes resulting primarily from planned outages, the mothballing of our Vermilion facility and the retirement of our South Bay facility. Additionally, overall market prices and capacity prices were lower in 2011 compared to 2010. Finally, operating expenses decreased due to the mothballing of our Vermilion facility and the retirement of our South Bay facility.

Table of Contents

Discussion of Segment Results of Operations

Coal Segment. Although power prices were lower in early 2011 compared to early 2010, Spring prices in 2011 were higher than in 2010. Summer prices were relatively flat year over year, resulting in average prices for the nine months ended September 30, 2011 very similar to average prices for the nine months ended September 30, 2010.

The following table provides summary financial data regarding our Coal segment results of operations for the nine month periods ended September 30, 2011 and 2010, respectively:

	Nine Months Ended September 30,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	548		$	544		$	4		1	%
Capacity	8			16			(8		)	(50	)%
Financial transactions:
Mark-to-market income (loss)	(75		)	113			(188		)	(166	)%
Financial settlements	18			49			(31		)	(63	)%
Option premiums	14			7			7			100	%

Total Financial transactions	(43		)	169			(212		)	(125	)%
Other (1)	(4		)	(7		)	3			43	%

Total revenues	509			722			(213		)	(30	)%
Cost of sales	(257		)	(261		)	4			2	%

Gross margin	$	252		$	461		$	(209	)	(45	)%

Million Megawatt Hours Generated	16.9			16.3			0.6			4	%
In Market Availability for Coal Fired Facilities (2)	93		%	90		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
Cinergy (Cin Hub)	$	44		$	44		$	—		—

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

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

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

Gross margin for Coal decreased by $209 million from $461 million for the nine months ended September 30, 2010, to $252 million for the nine months ended September 30, 2011. The majority of this decrease related to a net change in mark-to-market revenue from $113 million to a loss of $75 million. Additionally, Coal had less revenue from financial transactions in 2011.

Energy revenues, and corresponding cost of sales, were slightly higher, largely due to higher generated volumes. In 2010, Baldwin experienced a three month outage. This increase in volume was partially offset by the reduced volumes due to the mothballing of the Vermilion facility early in 2011.

Capacity revenues decreased by $8 million due to an overall decrease in capacity prices in the MISO markets from 2010 to 2011.

Gas Segment. In the Northeast, generation demand was somewhat mixed in 2011, with only February through April posting positive gains, while the remaining months were down compared to 2010. Additionally, net generated volumes were lower in ISO-NE in 2011 compared to 2010 due to an unplanned outage at Casco Bay. In PJM, net generated volumes were higher, mainly driven by positive off-peak spark-spreads at our Ontelaunee facility.

Table of Contents

For our California facilities, market demand was slightly higher in 2011 compared to 2010, but generated volumes was down significantly due to competition with hydro generation. Robust snowpack in the Northwest and California led to strong hydro production; the Northwest recorded the second greatest hydro production since 1993. The strong hydro production, coupled with a very mild summer, led to historical lows in terms of spark-spreads.

The following table provides summary financial data regarding our Gas segment results of operations for the nine month periods ended September 30, 2011 and 2010, respectively:

	Nine Months Ended September 30,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	403		$	460		$	(57	)	(12	)%
Capacity	166			174			(8		)	(5	)%
RMR	5			32			(27		)	(84	)%
Tolls	100			111			(11		)	(10	)%
Natural gas	134			124			10			8	%
Financial transactions:
Mark-to-market losses	(16		)	(14		)	(2		)	(14	)%
Financial settlements	(96		)	(100		)	4			4	%
Option premiums	21			117			(96		)	(82	)%

Total financial transactions	(91		)	3			(94		)	(3,133	)%
Other (1)	26			20			6			30	%

Total revenues	743			924			(181		)	(20	)%
Cost of sales	(481		)	(520		)	39			8	%

Gross margin	$	262		$	404		$	(142	)	(35	)%

Million Megawatt Hours Generated (2)	9.6			10.3			(0.7		)	(7	)%
Average Capacity Factor for Combined Cycle Facilities (3)	33		%	35		%
Average Quoted On-Peak Market Power Prices ($/MWh) (4):
Commonwealth Edison (NI Hub)	$	44		$	43		$	1		2	%
PJM West	$	55		$	56		$	(1	)	(2	)%
North Path 15 (NP 15)	$	36		$	41		$	(5	)	(12	)%
New York—Zone A	$	43		$	45		$	(2	)	(4	)%
Mass Hub	$	57		$	57		$	—		—
Average Market Spark Spreads ($/MWh) (5):
PJM West	$	21		$	20		$	1		5	%
North Path 15 (NP 15)	$	3		$	6		$	(3	)	(50	)%
New York—Zone A	$	10		$	9		$	1		11	%
Mass Hub	$	19		$	20		$	(1	)	(5	)%

Average natural gas price—Henry Hub ($/MMBtu) (6)	$	4.21		$	4.58		$	(0.37	)	(8	)%

(1)	Other includes ancillary services and other miscellaneous items.
(2)	Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility for the three months ended September 30, 2011 and 2010, respectively.
(3)	Reflects actual production as a percentage of available capacity.
(4)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
(5)	Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator or an 11.0 MMBtu/MWh heat rate fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.

Table of Contents

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

Gross margin for Gas decreased by $142 million from $404 million for the nine months ended September 30, 2010, to $262 million for the nine months ended September 30, 2011. Gas had $96 million lower contributions from option premiums in 2011 compared to 2010, due to a change in commercial strategy.

Energy revenues, and corresponding cost of sales, were lower primarily due to lower generated volumes. Generation was down at Moss Landing due to weak spark-spreads and at Casco Bay due to a significant outage in 2011. Lower prices and spark spreads also contributed to lower generation.

Capacity and RMR revenue were also down. Capacity prices were lower in 2011 compared to 2010. RMR revenue was impacted by the retirement of the South Bay facility on December 31, 2010. Tolling revenue also decreased, due to the 2010 payment received for the termination of the Kendall toll, slightly offset by increased tolling revenue associated with the new Moss Landing toll. Finally, natural gas revenue was up slightly, as a result of sales of excess natural gas resulting from lower generation.

These items were slightly offset by higher ancillary revenue at Kendall and Ontelaunee, resulting from higher ancillary pricing in the PJM market.

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

The following table provides summary financial data regarding our DNE segment results of operations for the nine month periods ended September 30, 2011 and 2010, respectively:

	Nine Months Ended September 30,
	2011			2010			Change			% Change
	(dollars in millions)
Revenues:
Energy	$	89		$	118		$	(29	)	(25	)%
Capacity	14			34			(20		)	(59	)%
Financial transactions:
Mark-to-market income (loss)	(47		)	41			(88		)	(215	)%
Financial settlements	33			24			9			38	%
Option premiums	2			7			(5		)	(71	)%

Total financial transactions	(12		)	72			(84		)	(117	)%
Other (1)	4			2			2			100	%

Total revenues	95			226			(131		)	(58	)%
Cost of sales	(63		)	(93		)	30			32	%

Gross margin	$	32		$	133		$	(101	)	(76	)%

Million Megawatt Hours Generated	1.1			1.7			(0.6		)	(35	)%
In Market Availability for Coal Fired Facilities (2)	95		%	94		%
Average Capacity Factor—Coal	34		%	54		%
Average Capacity Factor—Gas	4		%	5		%
Average Quoted On-Peak Market Power Prices ($/MWh) (3):
New York—Zone G	$	61		$	60		$	1		2	%
Average Market Spark Spreads ($/MWh) (4):	$	(116	)	$	(69	)	$	(47	)	(68	)%
Fuel Oil

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

Table of Contents

(2)	Reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched.
(3)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
(4)	Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator or an 11.0 MMBtu/MWh heat rate fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.

Gross margin for DNE decreased by $101 million from $133 million for the nine months ended September 30, 2010, to $32 million for the nine months ended September 30, 2011. The majority of this decrease related to a net change in mark-to-market revenue from $41 million in 2010 to a loss of $47 million in 2011.

Energy revenues, and corresponding cost of sales, decreased, largely due to lower generated volumes. In 2011, Danskammer began cycling units to reduce generation during non-profitable off-peak hours. Additionally, Danskammer had higher outages, both planned and unplanned in 2011. In addition, weather conditions and an outage of a nuclear plant in the area in 2010 resulted in higher generation at Roseton in 2010 compared to 2011.

Capacity revenues decreased by $20 million due to significant decreases in capacity prices in the region.

Outlook

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

On November 7, 2011, the Debtor Entities filed the Chapter 11 Cases. Neither Dynegy nor any of its direct or indirect subsidiaries other than the five Debtor Entities sought protection from creditors, and none of those entities are debtors under Chapter 11 of the Bankruptcy Code. The Debtor Entities will continue to operate their businesses as “debtors-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. Coal Holdco and its indirect, wholly-owned subsidiary, DMG, as well as all other subsidiaries of DH other than the Debtor Entities, including DPC and all of its subsidiaries, are not included in the Chapter 11 Cases. The normal day-to-day operations of the coal-fired power generation facilities held by DMG and the gas-fired generation facilities held by DPC will continue without interruption.

We expect that our future financial results will continue to be sensitive to fuel and commodity prices, especially gas prices and the impact on such prices of shale gas production. Other factors to which our future financial results will remain sensitive include market structure and prices for electric energy, capacity and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions and IMA. Further, there is a trend toward greater environmental regulation of all aspects of our business. As this trend continues, it is likely that we will experience additional costs and limitations.

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

Our Consent Decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in Illinois. We have achieved all emission reductions scheduled to date under the Consent Decree and are in the process of installing additional emission control equipment to meet future Consent Decree emission limits. We expect our costs associated with the remaining Consent Decree projects to be approximately $120 million, payments for which will continue into early 2013. This estimate includes a number of assumptions about uncertainties beyond our control, such as costs associated with labor and materials.

Table of Contents

Our expected coal requirements are approximately 100 percent contracted in 2011 and 2012. All of our forecast coal requirements are 100 percent priced through 2012. Committed volumes that are currently unpriced are subject to a price collar structure. Our coal transportation requirements are 100 percent contracted and priced through 2013. We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies. Our DMG expected generation volumes are volumetrically 95 percent hedged through 2011 and approximately 20 percent hedged for 2012.

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

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

South Bay’s RMR designation was terminated at the end of 2010, and as a result, the South Bay power generation facility has been decommissioned. We have a contractual obligation to demolish the facility and potentially remediate specific parcels of the property. Our cost estimates for the demolition of the facility have not been finalized, but our obligation is expected to be approximately $40 million, exclusive of certain rental payments that will be due the Port of San Diego. We expect to begin the demolition in 2012.

The estimated useful lives of our generation facilities consider environmental regulations currently in place. With respect to units 6 and 7 at our Moss Landing facility, we are continuing to review the potential impact of the California Water Intake Policy. We are currently depreciating these units through 2024; however, depending on the ultimate impact of the California Water Intake Policy, we may determine that we would be required to install cooling systems that could render operation of the units uneconomical. If such a determination were to be made, we could decide to reduce operations or cease to operate the units as early as December 31, 2017. A decision to cease operations at the end of 2017 would result in the acceleration of depreciation on the remaining net book values of the units, which were $342 million at September 30, 2011.

In New England, five forward capacity auctions have been held since the ISO-NE transitioned to a forward capacity auction market in June 2010. Capacity clearing prices have ranged from a high of $4.50 per kW-month for the 2010-2011 market period to a low of $2.95 per kW-month for the 2013-2014 market period. During the most recent forward capacity market auction for the 2014-2015 market period, held in June of 2011, capacity cleared at $3.21 per kW-month. These capacity clearing prices represent the floor price, although the actual rate paid to Casco Bay (and other facilities) can be reduced due to oversupply conditions and/or regional export limits. Efforts to implement prospective improvements in the forward capacity market design are currently underway in active proceedings at FERC and in discussions by the ISO and its stakeholders.

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

Table of Contents

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

In early 2011, we were advised by one of our equipment manufacturers that certain of the turbine blades at our steam turbine units at several of our combined cycle facilities may be defective and require replacement. During the 2011 spring maintenance overhaul of the Moss Landing facility, the steam turbine blades on units one and two were inspected and it was determined that the blades did not require replacement; however, repairs by the original equipment manufacturer were required. The repairs were completed and the units were returned to full service. The initial inspections at Kendall in the spring of 2011 did not identify any issues with the steam turbine blades. The affected steam turbine blades at the Casco Bay facility were removed and partially repaired in March 2011. Permanent repairs were completed in October 2011.

Currently, our Gas portfolio is approximately 89 percent hedged volumetrically through 2011 and approximately 48 percent hedged for 2012.

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

DNE. DNE consists of the Roseton and Danskammer facilities in New York totaling 1,693 MW. A total of 1,570 MW of generation capacity relate to leased units at the two facilities. In connection with the Chapter 11 Cases, the Debtor Entities intend, subject to Bankruptcy Court approval, to reject the leases of the Roseton and Danskammer power generation facilities located in Newburgh, New York. Although the Debtor Entities are prepared to surrender the Roseton and Danskammer facilities upon entry of an order authorizing the rejection of the leases, applicable federal and state regulatory requirements may prevent the Debtor Entities from doing so immediately. Therefore, the Debtor Entities intend to operate the facilities to the extent necessary to comply with applicable federal and state regulatory requirements until operational control is transitioned to the owners of the leased facilities, which are affiliates of Public Service Enterprise Group, Inc.

A substantial portion of expected physical coal supply and delivery requirements for 2011 are fully contracted and priced with the balance financially hedged to the extent these facilities are forecasted to run.

We have elected not to hedge any of our generation volumes for the remainder of 2011 and through 2012.

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

We have initiated actions to further reduce costs and to improve operating performance by implementing a comprehensive improvement effort. This cost and performance improvement initiative, known as Dynegy PRIDE (“Producing Results through Innovation by Dynegy Employees”), will drive bottom line benefits by reducing our cost structure, implementing operating improvements and increasing cash flow through balance sheet efficiencies. Through the balance of this year and going forward, we will review plant-level margin for additional opportunities to improve cost and performance. By year end, we expect our consolidated general and administrative expense annual run rate to be below $105 million and our consolidated operating expense run rate to be approximately $420 million. This compares to $137 million, exclusive of one time, non-recurring charges, and $450 million, respectively, in 2010. We are on target for realizing an additional $25 million of improvements in 2012.

Table of Contents

Environmental and Regulatory Matters

Please read Item 1. Business—Environmental Matters in our Form 10-K and Outlook—Environmental and Regulatory Matters in our Form 10-Q for the quarters ended March 31, 2011 and June 30, 2011 for further discussion.

Federal Regulation of Greenhouse Gases. In September 2011, EPA announced that it would delay the release of proposed New Source Performance Standards and emission guidelines for controlling GHG emissions from new, modified and existing EGUs, which were to be issued by September 30, 2011. EPA has not yet announced a new schedule for this rulemaking.

State Regulation of Greenhouse Gases. Our assets in California are subject to the California Global Warming Solutions Act (“AB 32”), which requires the CARB to develop a GHG emission control program that will reduce emissions of GHG in the state to their 1990 levels by 2020 with a fully effective regulatory program to be in place by January 2012. In August 2011, the CARB approved its revised supplemental CEQA analysis in support of the cap and trade regulatory program. In October 2011, the CARB approved revisions to certain elements of the cap-and-trade program, including a delay in the start of the cap-and-trade rule’s compliance obligations until 2013. Additional rule changes on select issues will be considered in 2012. Our financial exposure in California is partially offset by our tolling arrangements that contain pass through provisions for the cost of carbon credits. The forward curve for California carbon allowances is in its nascent stage and remains somewhat illiquid. We will continue to monitor the CARB’s cap-and-trade program rulemaking activities, including associated litigation, and evaluate any potential impacts on our operations.

On January 1, 2009, our assets in New York and Maine became subject to a state-driven GHG emission control program known as RGGI. In September 2011, RGGI held its thirteenth auction, in which approximately 7.5 million allowances for the current control period were sold at clearing prices of $1.89 per allowance. No bids were submitted for allowances for a future control period. We have participated in each of the quarterly RGGI auctions (or in secondary markets, as appropriate) to secure some allowances for our affected assets. We expect that the increased operating costs resulting from purchase of CO2 allowances will be at least partially reflected in market prices. The RGGI states plan to continue to conduct quarterly auctions in 2012.

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 CSAPR . The CSAPR, which in response to a court decision replaces EPA’s 2005 CAIR, is intended to reduce emissions of SO2 and NOx from large electric generating units in 27 states in the eastern half of the United States. The rule imposes cap and trade programs within each affected state that cap emissions of SO2 and NOx at levels predicted to eliminate that state’s contribution to nonattainment in, or interference with maintenance of attainment status by, down-wind areas with respect to the National Ambient Air Quality Standards for particulate matter and ozone. The rule will be implemented initially through federal implementation plans. Our generating facilities in Illinois, New York and Pennsylvania will be subject to the rule.

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

Table of Contents

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

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

Petitions for administrative reconsideration or judicial review, including requests for stay, of the CSAPR have been filed. On October 6, 2011, the EPA issued proposed technical revisions to the CSAPR, including a proposed two-year delay in the assurance penalty provisions that is intended to promote liquidity in the CSAPR allowance markets. In addition, on September 23, 2011, the U.S. House of Representatives passed H.R. 2401, the Transparency in Regulatory Analysis of Impacts on the Nation Act (“TRAIN Act”), which would create an interagency committee to study the cumulative economic impacts of certain new EPA rules, void the CSAPR, and require continued implementation of the CAIR for at least three years until after the interagency study is complete. The bill also would void EPA’s proposed EGU MACT rule and prohibit reissuance of any subsequent EGU MACT rule until at least one year after the interagency study is complete. We will continue to review the CSAPR, as well as monitor related rulemaking, judicial and legislative developments, and evaluate any potential impacts on our operations.

Coal Combustion Residuals. The combustion of coal to generate electric power creates large quantities of ash that are managed at power generation facilities in dry form in landfills and in liquid or slurry form in surface impoundments. Each of our coal-fired plants has at least one CCR management unit. Certain environmental organizations have advocated designation of CCR as a hazardous waste; however, many state environmental agencies have expressed strong opposition to such designation. 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 is expected to issue final regulations governing CCR management in 2012 or later. Federal legislation to address CCR also has been introduced in Congress. On October 14, 2011, the House of Representatives passed H.R. 2273, the Coal Residuals Reuse and Management Act, which would authorize the states to implement a subtitle D permit program for CCR disposal units. The permit requirements would include structural integrity standards and certain elements of the subtitle D criteria for municipal solid waste landfills, including location restrictions, design standards, ground water monitoring, financial assurance, corrective action, closure and post-closure care. The EPA would be authorized to administer and enforce the subtitle D criteria for CCR disposal units only if a state chooses not to do so or if the EPA finds that the state program is deficient. A companion bill, S.1751, has been introduced in the Senate. We will continue to monitor CCR rulemaking and legislative developments and to evaluate any potential impacts on our operations.

We have implemented groundwater monitoring plans for the CCR surface impoundments at our Vermilion and Baldwin facilities in response to requests by the Illinois EPA. In addition, we have agreed to submit to the Illinois EPA by April 1, 2012 a proposed corrective action plan, including a closure work plan, for certain CCR surface impoundments at the Vermilion facility. Asset retirement costs are recorded for the estimated costs of closing CCR surface impoundments at each coal-fired DMG facility.

The nature and scope of potential future requirements for CCR cannot be predicted with confidence at this time, but could have a material adverse effect on our financial condition, results of operations and cash flows. Further, public perceptions of new regulations regarding the reuse of coal ash may limit or eliminate the market that currently exists for coal ash reuse, which could have material adverse effects on our financial condition, results of operations and cash flows.

Table of Contents

RISK-MANAGEMENT DISCLOSURES

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

	As of and for the Nine Months Ended September 30, 2011
	(in millions)
Balance Sheet Risk-Management Accounts
Fair value of portfolio at December 31, 2010	$	34
Risk-management losses recognized through the income statement in the period, net	(106		)
Cash received related to risk-management contracts settled in the period, net	(37		)
Changes in fair value as a result of a change in valuation technique (1)	—
Non-cash adjustments and other	3

Fair value of portfolio at September 30, 2011	$	(106	)

(1) Our modeling methodology has been consistently applied.

The net risk management liability of $106 million is the aggregate of the following line items on our unaudited condensed consolidated balance sheets: Current Assets—Assets from risk-management activities, Other Assets—Assets from risk-management activities, Current Liabilities—Liabilities from risk-management activities and Other Liabilities—Liabilities from risk-management activities.

Risk-Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of September 30, 2011, based on our valuation methodology:

Net Fair Value of Risk-Management Portfolio

	Total			2011			2012			2013		2014		2015		Thereafter
	(in millions)
Market quotations (1) (2)	$	(104	)	$	1		$	(105	)	$	—	$	—	$	—	$	—
Prices based on models (2)	(2		)	(6		)	(7		)	11		—		—		—

Total	$	(106	)	$	(5	)	$	(112	)	$	11	$	—	$	—	$	—

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

(2) The market quotations and prices based on models categorization differ from the categories of Level 1, Level 2 and Level 3 used in our fair value disclosures due to the application of the different methodologies. Please read Note 5—Fair Value Measurements for further discussion.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements”. All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate”, “estimate”, “project”, “forecast”, “plan”, “may”, “will”, “should”, “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:

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

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

· beliefs and assumptions relating to our liquidity, available borrowing capacity and capital resources generally, including the extent to which such liquidity could be affected by poor economic and financial market conditions or new regulations and any resulting impacts on financial institutions and other current and potential counterparties;

Table of Contents

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

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

· expectations regarding our compliance with our new credit agreements, including collateral demands, interest expense and other payments;

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

· expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations to which we are, or could become, subject;

· beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the impact on such prices from shale gas proliferation and the timing of a recovery in natural gas prices, if any;

· sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof;

· beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale power generation market, including the anticipation of higher market pricing over the longer term;

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

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

· beliefs and assumptions about weather and general economic conditions;

· projected operating or financial results, including anticipated cash flows from operations, revenues and profitability, 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 Consent Decree and its associated costs and performance standards.

Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth under Part II—Other Information, Item 1A-Risk Factors and Item 1A-Risk Factors of our Form 10-K.

CRITICAL ACCOUNTING POLICIES

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

Table of Contents

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our Form 10-K for a discussion of our exposure to commodity price variability and other market risks related to our net non-trading derivative assets and liabilities, including foreign currency exchange rate risk. Following is a discussion of the more material of these risks and our relative exposures as of September 30, 2011.

Value at Risk (“VaR”). The following table sets forth the aggregate daily VaR of the mark-to-market portion of our risk-management portfolio primarily associated with the Coal, Gas and DNE segments and the remaining legacy customer risk management business. The VaR calculation does not include market risks associated with the accrual portion of the risk-management portfolio that is designated as a cash flow hedge or a “normal purchase normal sale”, nor does it include expected future production from our generating assets. Please read “Value at Risk” in our Form 10-K for a complete description of our valuation methodology. The decrease in the September 30, 2011 VaR was primarily due to decreased forward sales as compared to December 31, 2010.

Daily and Average VaR for Risk-Management Portfolios

	September 30, 2011		December 31, 2010
	(in millions)
One day VaR—95 percent confidence level	$	2	$	14
One day VaR—99 percent confidence level	$	4	$	20
Average VaR for the year-to-date period—95 percent confidence level	$	10	$	22

Credit Risk. The following table represents our credit exposure at September 30, 2011 associated with the mark-to-market portion of our risk-management portfolio, on a net basis.

Credit Exposure Summary

	Investment Grade Quality		Non-Investment Grade Quality		Total
	(in millions)
Type of Business:
Financial institutions	$	20	$	—	$	20
Oil and gas producers	1		—		1
Utility and power generators	29		—		29
Commercial / industrial / end users	—		1		1

Total	$	50	$	1	$	51

Interest Rate Risk. We are exposed to fluctuating interest rates related to variable rate financial obligations. As of September 30, 2011, the amount owed under our fixed rate debt instruments, as a percentage of the total amount owed under all of our debt instruments, was 68 percent. Based on sensitivity analysis of the variable rate financial obligations in our debt portfolio as of September 30, 2011, it is estimated that a one percentage point interest rate movement in the average market interest rates (either higher or lower) over the twelve months ended September 30, 2012 would either decrease or increase interest expense by approximately $17 million to the extent LIBOR exceeds 1.5 percent, which represents the interest rate floor in the DPC Credit Agreement and DMG Credit Agreement. This exposure would have been partially offset by an approximate $8 million increase or decrease in interest income related to the restricted cash balance of $797 million posted as collateral to support our letter of credit facilities. Over time, we may seek to adjust the variable rate exposure in our debt portfolio through the use of swaps or other financial instruments. Please read Note 15—Subsequent Event for further discussion.

Table of Contents

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

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

Item 4—CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the quarter ended September 30, 2011.

Table of Contents

DYNEGY INC.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

See Note 9—Commitments and Contingencies—Legal Proceedings to the accompanying unaudited condensed consolidated financial statements for a discussion of the legal proceedings that we believe could be material to us.

Item 1A—RISK FACTORS

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

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

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

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

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

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

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

· Our ability to use our state deferred tax assets or that portion of our deferred tax assets comprised of federal NOLs and AMT credits, which totaled $222 million and $271 million, respectively, at December 31, 2010, will likely be limited or modified as a result of the bankruptcy proceedings and such limitation or modification may be significant.

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 longer the Debtor Entities have to operate under Chapter 11 bankruptcy protection. Because of the risks and uncertainties associated with our Debtor Entities’ bankruptcy 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 Support Agreement.

The Debtor Entities’ emergence from Chapter 11 bankruptcy protection is contingent upon a number of factors. Due to the fact that the Chapter 11 Cases were filed very recently, it is difficult to anticipate all such contingencies, which include, among other things, the fact that:

· a plan of reorganization contemplated by the Support Agreement may not be confirmed by the Bankruptcy Court; and

· the Support Agreement may be terminated.

The Support Agreement may be terminated if (among other things): (i) the Plan and other documents required to implement the Restructuring are not, with respect to any economic or other material term of the Restructuring, in form and substance acceptable to Dynegy, DH and a majority of the Consenting Noteholders by December 7, 2011; (ii) the Bankruptcy Court has not entered an order approving the disclosure statement related to the Plan by March 15, 2012; (iii) the Bankruptcy Court has not entered an order confirming the Plan by June 15, 2012; or (iv) the Plan has not become effective by August 1, 2012.

If we are unable to implement the Restructuring of the Debtor Entities, as contemplated by the Support Agreement, it is unclear whether we will be able to reorganize the Debtor Entities’ businesses and what, if any, distribution holders of claims against or of equity interests in the Debtor Entities ultimately would receive with respect to their claims or equity interests. For example, to address our burdensome lease obligations at Roseton and

Table of Contents

Danskammer, it is a condition precedent to the consummation of the Restructuring that the aggregate claims arising from the rejection of such obligations do not exceed $300 million, subject to certain exceptions. If this condition cannot be satisfied our Debtor Entities may need to pursue alternative restructuring proposals. If the plan reflecting the Restructuring is not confirmed and does not become effective, there also can be no assurance that our Debtor Entities will be able to successfully develop, prosecute, confirm, and consummate an alternative plan of reorganization with respect to the Chapter 11 Cases that would be acceptable to the Bankruptcy Court and applicable creditors, equity holders and other parties in interest.

If the Convertible Securities proposed to be issued pursuant to the Restructuring are not redeemed prior to their mandatory conversion, such conversion will dilute the ownership interests of our stockholders.

The Restructuring provides for the issuance of $2.1 billion of Convertible Securities. The Convertible Securities will earn payment-in-kind interest, commencing on November 7, 2011, at 4% through December 31, 2013, 8% thereafter through December 31, 2014 and 12% thereafter. The payment-in-kind interest will be paid in the form of additional Convertible Securities, which will also be convertible into additional shares of our common stock. The Convertible Securities will not be convertible at the option of the holder but will mandatorily convert into common stock comprising 97% of Dynegy’s fully diluted common stock on December 31, 2015, if not earlier redeemed. Consequently, if the Convertible Securities are not earlier redeemed, the issuance of our common stock pursuant to the mandatory conversion feature of the Convertible Securities will significantly dilute the ownership interests of existing stockholders and could affect the trading price of our common stock upon issuance. In addition, the possibility of conversion of the Convertible Securities into shares of our common stock could depress the price of our common stock.

Restrictive covenants may adversely affect operations.

The DMG and DPC Credit Agreements contain, and the indenture governing the New Senior Notes proposed to be issued pursuant to the Restructuring is expected to contain, various covenants that limit DMG or DPC’s, with respect to the credit agreements, or Dynegy’s, with respect to the indenture, ability to, among other things:

· incur or guarantee additional indebtedness or issue preferred stock;

· pay dividends or make other distributions;

· make certain investments;

· enter into agreements that restrict dividends or other payments to Dynegy from its restricted subsidiaries;

· create liens;

· sell assets, including capital stock of subsidiaries;

· engage in transactions with affiliates; and

· merge or consolidate with other companies or sell substantially all of Dynegy’s assets.

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

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

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. The ability of our subsidiaries to make distributions or pay dividends will depend on their operating results. 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 the terms and covenants of any future outstanding indebtedness, contract or agreements of our subsidiaries, including the DPC Credit Agreement and the DMG Credit Agreement, which limit distributions to $135 million and $90 million per year, respectively. Additionally, we expect that the indenture governing the New Senior Notes will also include covenants further

Table of Contents

limiting our ability to make distributions of cash (including by requiring the maintenance of a $55 million debt service account for the benefit of the holders of the New Senior Notes). The restrictions on our ability to access cash flow from certain subsidiaries may impair our ability to operate our business as effectively as possible.

The outcome of ongoing and potential legal proceedings may disrupt the Restructuring, could have a material adverse effect on the Debtor Entities or have a material adverse effect on our financial condition, results of operations and cash flows.

We are subject to certain ongoing legal proceedings for which management believes a material loss is at least reasonably possible. These legal proceedings include the matters set forth in Note 9—Commitments and Contingencies to our unaudited condensed consolidated financial statements for the period ended September 30, 2011.

Specifically with respect to the Restructuring, in September and November 2011, complaints were filed in New York state court by the Owner Lessor Plaintiffs, (ii) Indenture Trustee Plaintiffs, and (iii) the Avenue Plaintiffs. The Indenture Trustee Plaintiffs and the Avenue Plaintiffs allege, among other claims, breach of contract, breach of fiduciary duties, and violations of prohibitions on fraudulent transfers in connection with the DMG Acquisition, and seek judgments setting aside the DMG Acquisition and related transactions, as well as damages. The Owner Lessor Plaintiffs allege that the Reorganization, the DPC and DMG Credit Agreements, and the DMG Acquisition constitute an integrated scheme involving fraudulent transfers, breach of contract, and breach of fiduciary duties, and seek a judgment to unwind all of the transactions as well as damages.

We believe the allegations made by the plaintiffs in these lawsuits lack merit and intend to defend vigorously our position in these and any other proceedings that may arise involving the Reorganization, the DPC and DMG Credit Agreements, and the DMG Acquisition. However, any extraordinary remedy, such as the unwinding of the Reorganization, the DPC or DMG Credit Agreements, or the DMG Acquisition, may have a material adverse effect on our financial condition, results of operations and cash flows.

Further, Parties in interest may pursue litigation strategies to enforce any claims against the Debtor Entities or us, including litigation regarding our proposed rejection of the Roseton and Danskammer leases. Litigation is by its nature uncertain and there can be no assurance of the ultimate resolution of any such claims. Any litigation may be expensive, lengthy, and disruptive to our normal business operations and the Restructuring, and a resolution of any such litigation that is unfavorable to us could have a material adverse effect on the Restructuring or on our financial condition, results of operations or cash flows.

Table of Contents

Despite current indebtedness levels, Dynegy, DH and their subsidiaries may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial leverage.

Dynegy, DH and their subsidiaries may be able to incur substantial additional indebtedness in the future. The agreements governing the new credit agreements and the agreements governing other existing indebtedness will not or do not fully prohibit Dynegy, DH or their subsidiaries from doing so. Any such indebtedness may reduce the cash flow available to make principal and interest payments on the senior notes and debentures, and an exercise by the holder of such indebtedness of their liens may result in Dynegy or DH losing the benefit of the assets secured by such liens, including all of Dynegy’s and DH’s indirect interests in DMG and DPC. If new debt is incurred by Dynegy, DH or their subsidiaries, the related risks that they now face could intensify.

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

During the third quarter 2011, as an inducement to their acceptance of appointments as officers of the Company, Robert C. Flexon, President and Chief Executive Officer; Kevin T. Howell, Executive Vice President and Chief Operating Officer; Clint C. Freeland, Executive Vice President and Chief Financial Officer; Carolyn J. Burke, Executive Vice President and Chief Administrative Officer and Catherine B. Callaway, Executive Vice President and General Counsel were issued in a private placement 42,017, 12,605, 8,306, 8,000 and 8,993 shares of our common stock, respectively. The shares were issued pursuant to the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended.

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

Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs
July 1-31	—	$	—	—	N/A
August 1-31	782	$	4.90	—	N/A
September 1-30	—	$	—	—	N/A

Total	782	$	4.90	—	N/A

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

Table of Contents

Item 3—Defaults Upon Senior Securities

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

· DH’s (i) 8.75% senior unsecured notes due on February 15, 2012, (ii) 7.5% senior unsecured notes due on June 1, 2015, (iii) 8.375% senior unsecured notes due on May 1, 2016, (iv) 7.75% senior unsecured notes due on June 1, 2019, (v) 7.125% senior debentures due May 15, 2018 and (vi) 7.625% senior debentures due October 15, 2026, issued under the Indenture dated September 26, 1996, as amended and restated as of March 14, 2001, and under the First through Sixth Supplemental Indentures thereto, between DH and Wilmington Trust Company (as successor to JP Morgan Chase Bank, N .A., successor to Bank One Trust Company, National Association), as trustee, in the outstanding aggregate principal amount of $3,370.3 million.

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

· DH’s $1.25 billion promissory note to its subsidiary, Dynegy Gas Investments, LLC, payable on September 1, 2027.

· DH’s $26,217,318 cash collateralized letter of credit facility between DH and Credit Suisse AG, Cayman Islands Branch, which is collateralized by an account maintained by Bank of New York Mellon holding the sum of $27,003,837.54.

Table of Contents

Item 6—EXHIBITS

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

Exhibit Number		Description
2.1		Membership Interest Purchase Agreement by and between Dynegy Gas Investments, LLC and Dynegy Inc. dated September 1, 2011 (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Holdings, LLC filed on September 8, 2011, File No. 000-29311).

2.2		Undertaking Agreement by and between Dynegy Gas Investments, LLC and Dynegy Inc. dated September 1, 2011 (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Dynegy Holdings, LLC filed on September 8, 2011, File No. 000-29311).

2.3		Amended and Restated Undertaking Agreement by and between Dynegy Holdings, LLC and Dynegy Inc. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K of Dynegy Holdings, LLC filed on September 8, 2011, File No. 000-29311).

4.1		Promissory Note by and between Dynegy Holdings, LLC and Dynegy Gas Investments, LLC dated September 1, 2011 (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Holdings, LLC filed on September 8, 2011, File No. 000-29311).

4.2		Third Supplemental Indenture, dated as of September 9, 2011, among Sithe/Independence Funding Corporation, Sithe/Independence Power Partners, L.P. and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on September 12, 2011, File No. 001-33443).

**10.1		Fourth Amendment to the Dynegy Inc. Executive Severance Pay Plan, dated as of August 8, 2011.

**10.2		Employment Agreement between Dynegy Inc. and Catherine Callaway dated September 16, 2011.

**10.3		Non-Qualified Stock Option Award Agreement between Dynegy Inc. and Carolyn Burke dated August 30, 2011.

**10.4		Non-Qualified Stock Option Award Agreement between Dynegy Inc. and Catherine Callaway dated September 26, 2011.

10.5		Assignment Agreement by and among Dynegy Gas Investments, LLC, Dynegy Holdings, LLC and Dynegy Inc. dated September 1, 2011 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Holdings, LLC filed on September 8, 2011, File No. 000-29311).

10.6		Restructuring Support Agreement, dated November 7, 2011, among Dynegy Inc., Dynegy Holdings, LLC and certain beneficial holders of notes issued by Dynegy Holdings, LLC (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Dynegy Inc. and Dynegy Holdings, LLC filed on November 8, 2011, File No. 001-33443).

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

Table of Contents

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

†32.1		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema Document

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

**101.LAB		XBRL Taxonomy Extension Label Linkbase Document

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

** Filed herewith.

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

Table of Contents

DYNEGY INC.

SIGNATURE

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

		DYNEGY INC.

Date: November 14, 2011	By:	/s/ CLINT C. FREELAND
		Clint C. Freeland Executive Vice President and Chief Financial Officer